SecProbe.io

CORRESP
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 Devon
Energy Corporation

 333.
W. Sheridan Ave

 Oklahoma
City, Oklahoma 73102-5015

 TELEPHONE
(405) 235-3611

 March 24,
2026

 VIA
EDGAR

 Timothy
S. Levenberg

 Division
of Corporation Finance

 U.S.
Securities and Exchange Commission

 100
F Street, N.E.

 Washington,
D.C. 20549

 Re:
 Devon Energy Corporation

 Registration
 Statement on Form S-4

 File
 No. 333-294222

 Dear
Mr. Levenberg:

 Pursuant
to Rule 461 under the Securities Act of 1933, as amended, Devon Energy Corporation (the " Company ") respectfully
requests that the effective date of the above-referenced Registration Statement on Form S-4 (File No. 333-294222) be accelerated
by the staff of the U.S. Securities and Exchange Commission to March 26, 2026 at 4:00 p.m., Eastern Time, or as soon thereafter
as practicable.

 The
Company respectfully requests to be notified of such effectiveness by a telephone call to the Company's counsel, Skadden, Arps,
Slate, Meagher & Flom LLP, to Stephen M. Gill at (713) 655-5110, with such effectiveness to also be confirmed in writing to
Steve.Gill@skadden.com.

 /s/ Jeffrey L. Ritenour

 Jeffrey L. Ritenour

 Executive
 Vice President and Chief Financial Officer of Devon Energy Corporation

 cc:
 Stephen M. Gill, Esq.

 Mingda Zhao, Esq.

 Dohyun Kim, Esq.

 Skadden, Arps, Slate, Meagher & Flom LLP

 Tull R. Florey, Esq.

 Hillary H. Holmes, Esq.

 Gibson, Dunn & Crutcher LLP

<DOCUMENT>
<TYPE>TEXT-EXTRACT
<SEQUENCE>2
<FILENAME>filename2.txt
<TEXT>
 March 19, 2026

Clay M. Gaspar
President and Chief Executive Officer
Devon Energy Corporation
333 W. Sheridan Ave.
Oklahoma City, Oklahoma 73102-5015

 Re: Devon Energy Corporation
 Registration Statement on Form S-4
 Filed March 12, 2026
 File No. 333-294222
Dear Clay M. Gaspar:

 This is to advise you that we have not reviewed and will not review your
registration
statement.

 Please refer to Rules 460 and 461 regarding requests for acceleration.
We remind you
that the company and its management are responsible for the accuracy and
adequacy of their
disclosures, notwithstanding any review, comments, action or absence of action
by the staff.

 Please contact Timothy S. Levenberg at 202-551-3707 with any questions.

 Sincerely,

 Division of
Corporation Finance
 Office of Energy &
Transportation
cc: Mingda Zhao, Esq., of Skadden, Arps, et al.
</TEXT>
</DOCUMENT>

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CORRESP

 DEVON ENERGY CORPORATION

333. W. SHERIDAN AVE

OKLAHOMA, CITY, OKLAHOMA 73102-5015

TELEPHONE (405) 235-3611

November 17, 2021

 VIA EDGAR

Mr. Michael Purcell

 Division of Corporation Finance

Office of Energy & Transportation

 U.S. Securities and
Exchange Commission

 100 F Street, N.E.

 Washington, D.C.
20549

Re:
 Devon Energy Corporation

Registration Statement on Form S-4

File No. 333-260961

Dear Mr. Purcell:

 Pursuant to Rule 461 under the
Securities Act of 1933, as amended, Devon Energy Corporation respectfully requests that the effective date of the above-referenced Registration Statement on Form S-4 be accelerated by the staff of the U.S.
Securities and Exchange Commission to November 22, 2021 at 11:00 a.m., Eastern Time, or as soon thereafter as practicable.

 Please contact Michael
Hong of Skadden, Arps, Slate, Meagher & Flom LLP at (212) 735-2227 with any questions you may have regarding this request. In addition, please notify Mr. Hong by telephone when this request for
acceleration has been granted.

 /s/ Alana D. Tetrick

Alana D. Tetrick

 Vice President, Corporate Finance and Treasurer

Devon Energy Corporation

 cc:    Michael J. Hong, Esq.

Skadden, Arps, Slate, Meagher & Flom LLP

United States securities and exchange commission logo
November 17, 2021
Richard E. Muncrief
President and Chief Executive Officer
DEVON ENERGY CORP/DE
333 W. Sheridan Ave.
Oklahoma City, Oklahoma 73102-5015
Re:DEVON ENERGY CORP/DE
Registration Statement on Form S-4
Filed November 10, 2021
File No. 333-260961
Dear Mr. Muncrief:
            This is to advise you that we have not reviewed and will not review your registration
statement.
            Please refer to Rules 460 and 461 regarding requests for acceleration.  We remind you
that the company and its management are responsible for the accuracy and adequacy of their
disclosures, notwithstanding any review, comments, action or absence of action by the staff.
            Please contact Michael Purcell, Law Clerk, at 202-551-5351 with any questions.
Sincerely,
Division of Corporation Finance
Office of Energy & Transportation
cc:       Michael J. Hong

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CORRESP

Devon Energy Corporation 333 West Sheridan Ave. Oklahoma City, OK 73102-5015

405-235-3611 www.devonenergy.com

 November 17, 2021

VIA EDGAR

 U.S. Securities and Exchange Commission

 Division of Corporation Finance 100 F Street, N.E.

Washington, D.C. 20549

Re:

Devon Energy Corporation

Registration Statement on Form S-4

(File No. 333-260961)

Filed on November 10, 2021

 Ladies and Gentlemen:

Reference is made to the above-referenced Registration Statement on Form S-4 (the “Registration
Statement”), filed with the U.S. Securities and Exchange Commission under the U.S. Securities Act of 1933, as amended (the “Act”), on the date hereof, in connection with the proposed offers by Devon Energy Corporation (the
“Company”) to exchange (the “Exchange Offers”) up to the aggregate principal amount outstanding of each of the Company’s unregistered 8.250% Notes due 2023, 5.250% Notes due 2024, 5.250% Notes due 2027, 5.875% Notes due
2028 and 4.500% Notes due 2030 (collectively, the “Restricted Notes”) for equal aggregate principal amounts of the respective series of the Company’s 8.250% Notes due 2023, 5.250% Notes due 2024, 5.250% Notes due 2027, 5.875% Notes
due 2028 and 4.500% Notes due 2030 (collectively, the “Registered Notes”) the offers of which have been registered under the Act. The Company is registering the Exchange Offers in reliance on the position of the staff of the U.S.
Securities and Exchange Commission (the “Staff”) enunciated in Exxon Capital Holdings Corporation (April 13, 1989), Morgan Stanley & Co. Incorporated (June 5, 1991) and
Shearman & Sterling (July 2, 1993).

 This will confirm that the Company has not entered into any arrangement
or understanding with any person to distribute the Registered Notes and, to the best of the Company’s information and belief, each person participating in the Exchange Offers is acquiring the Registered Notes in its ordinary course of business
and has no arrangement or understanding with any person to participate in the distribution of the Registered Notes. In this regard, the Company will make each person participating in the Exchange Offers aware (through the Exchange Offer
prospectus) that if the Exchange Offers are being registered for the purpose of secondary resales, any securityholder using the Exchange Offers to participate in a distribution of the Registered Notes (1) could not rely on the Staff position
enunciated in Exxon Capital Holdings Corporation (April 13, 1989) or similar letters and (2) must comply with registration

 U.S. Securities and Exchange Commission

 Page
 2

and prospectus delivery requirements of the Act in connection with any sale or transfer of the Registered Notes, unless the sale or transfer is made pursuant to an exemption from those
requirements. The Company acknowledges that such a secondary resale transaction should be covered by an effective registration statement containing the selling securityholder information required by Item 507 of Regulation S-K.

 In addition, the Company will (i) make each person participating in the Exchange Offers aware
(through the Exchange Offer prospectus) that any broker-dealer who holds Restricted Notes acquired for its own account as a result of market-making activities or other trading activities, and who receives Registered Notes in exchange for such
Restricted Notes pursuant to the Exchange Offers, may be a statutory underwriter and must deliver a prospectus meeting the requirements of the Act in connection with any resale of such Restricted Notes and (ii) include in the transmittal letter
to be executed by an exchange offeree in order to participate in the Exchange Offers a provision to the following effect:

 If the
undersigned or any beneficial owner is a broker-dealer, the undersigned and such beneficial owner: (1) represents that it is participating in the Exchange Offers for its own account and is exchanging Restricted Notes that were acquired by it as
a result of market-making or other trading activities, (2) confirms that it has not entered into any arrangement or understanding with any person to distribute the Restricted Notes and (3) acknowledges that it will deliver a prospectus
meeting the requirements of the Act in connection with any resale of such Restricted Notes; however, by so acknowledging and by delivering a prospectus, such broker-dealer will not be deemed to admit that it is an underwriter within the meaning of
the Act.

 See Shearman & Sterling (July 2, 1993).

[Signature Page Follows]

 U.S. Securities and Exchange Commission

 Page
 3

Very truly yours,

DEVON ENERGY CORPORATION

By:

 /s/ Alana D. Tetrick

Name:

Alana D. Tetrick

Title:

Vice President, Corporate

Finance and Treasurer

 [Signature Page to Company Representation Letter]

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CORRESP

 DEVON ENERGY CORPORATION

333. W. SHERIDAN AVE

 OKLAHOMA,
CITY, OKLAHOMA 73102-5015

 TELEPHONE (405) 235-3611

November 20, 2020

 VIA EDGAR

Ms. Karina Dorin and Loan Lauren Nguyen

 Division of
Corporation Finance

 U.S. Securities and Exchange Commission

100 F Street, N.E.

 Washington, D.C. 20549

Re:
 Devon Energy Corporation

 Registration Statement on Form S-4

 File No. 333-249859

Dear Ms. Dorin and Ms. Nguyen:

 Pursuant to Rule 461
under the Securities Act of 1933, as amended, Devon Energy Corporation respectfully requests that the effective date of the above-referenced Registration Statement on Form S-4 be accelerated by the staff of
the U.S. Securities and Exchange Commission to November 24, 2020 at 9:00 a.m., Eastern Time, or as soon thereafter as practicable.

 Please contact
Eric Otness of Skadden, Arps, Slate, Meagher & Flom LLP at (713) 655-5135 with any questions you may have regarding this request. In addition, please notify Mr. Otness by telephone when this
request for acceleration has been granted.

/s/ Jeffrey L. Ritenour

Jeffrey L. Ritenour

 Executive Vice President and Chief Financial Officer

Devon Energy Corporation

cc:
 Eric Otness, Esq.

Frank Bayouth, Esq.

 Skadden,
Arps, Slate, Meagher & Flom LLP

 Sean T. Wheeler, Esq.

Debbie Yee, Esq.

 Michael Rigdon,
Esq.

 Kirkland & Ellis LLP

United States securities and exchange commission logo
November 19, 2020
Jeffrey L. Ritenour
Executive Vice President and Chief Financial Officer
Devon Energy Corporation
333 West Sheridan Avenue
Oklahoma City, Oklahoma 73102-5015
Re:Devon Energy Corporation
Form 10-K for the Fiscal Year Ended December 31, 2019
Filed February 19, 2020
File No. 001-32318
Dear Mr. Ritenour:
            We have completed our review of your filing.  We remind you that the company and its
management are responsible for the accuracy and adequacy of their disclosures, notwithstanding
any review, comments, action or absence of action by the staff.
Sincerely,
Division of Corporation Finance
Office of Energy & Transportation

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Devon Energy Corporation

405 552 8183 phone

333 West Sheridan Avenue

jeremy.humphers@dvn.com

Oklahoma City, OK 73102

 November 18, 2020

Via EDGAR

 Attention: Mr. John Hodgin,
Petroleum Engineer

 Mr. Craig Arakawa, Branch Chief

Division of Corporation Finance

 Office of Energy &
Transportation

 United States Securities and Exchange Commission

100 F. Street, N.E.

 Washington D.C. 20549-4631

Re:
 Devon Energy Corporation

Form 10-K for Fiscal Year Ended December 31, 2019

Filed February 19, 2020

File No. 001-32318

Dear Division of Corporation Finance, Office of Energy & Transportation:

This letter responds to the comment letter dated November 16, 2020, from the Division of Corporation Finance (the “Staff”), regarding Devon
Energy Corporation’s Form 10-K for the year ended December 31, 2019, filed February 19, 2020 (File No. 001-32318).

Devon’s responses to the Staff’s comments are set forth below:

Form 10-K for the Fiscal Year Ended December 31, 2019

Business and Properties

 Proved Reserves,
page 8

 SEC Comment

1.
 To the extent that you disclose material additions to your proved reserves, expand your disclosure to
provide a general discussion of the technologies used to establish the appropriate level of certainty for your reserves estimates. Refer to Item 1202 (a)(6) of Regulation S-K.

Response

 We acknowledge the Staff’s comment
regarding the requirement for material additions to be complemented by a general discussion of the technologies used to establish reasonable certainty in our reserves estimates. The

following discussion applies to our proved reserves additions for the year ended December 31, 2019. We commit to include a similar discussion in our
future filings as required by Item 1202(a)(6) of Regulation S-K.

 We establish our proved reserves
estimates using standard geological and engineering technologies and computational methods, which are generally accepted by the petroleum industry. We primarily prepare our proved reserves additions by analogy using type curves that are based on
decline curve analysis of wells in analogous reservoirs. We further establish reasonable certainty of our proved reserves estimates by using one or more of the following methods: geological and geophysical information to establish reservoir
continuity between penetrations, rate-transient analysis, analytical and numerical simulations, or other proprietary technical and statistical methods.

 Division of Corporation Finance

United States Securities and Exchange Commission

 Page 2

 Notes to Consolidated Financial Statements

Note 21-Supplemental Information on Oil and Gas Operations (Unaudited)

Proved Reserves, page 96

 SEC Comment

2.
 The explanation for the changes that occurred in total proved reserves indicates that a portion of the
change attributed to extensions and discoveries for fiscal 2018 and 2017 was the result of infill drilling. Refer to subparagraphs (a) and (d) of FASB ASC 932-235-50-5 and tell us your rationale for classifying reserves resulting from drilling an infill well as an extension.

Response

 Using subparagraph (d)(1) of FASB ASC 932-235-50-5 as a guide, we view the process of infill drilling in our shale formations as an increase in the proved area of the field.
The success of an infill drilling program in these ultra-tight formations results from drilling wells in areas where there is no effective drainage of the reservoir. Consequently, we interpret this as an increase in the proved area of the field.
Furthermore, the inclusion of such changes as revisions (other than price) could easily mask negative revisions resulting from well performance with infill drilling revisions which are always positive.

SEC Comment

3.
 The change in the total net quantities of proved reserves attributed to extensions and discoveries appears
to be significantly greater than the corresponding change in the net quantities of proved undeveloped reserves for each of the last three fiscal years presented, e.g. a difference of 71 MMBoe or 44% between the 160 MMBoe change attributed to total
proved reserves and the 89 MMBoe change attributed to proved undeveloped reserves for the period ending December 31, 2019. Expand the discussion of the significant changes that occurred in your total proved reserves attributed to extensions and
discoveries to explain the reason(s) for these differences. Refer to FASB ASC 932-235-50-5.

Response

 As indicated in our response to comment #2
above, our extensions and discoveries represent additions to our proved reserves from locations outside our areas classified as proved at the previous year-end. We commit to include the following explanation
and reasons for the differences between extensions and discoveries for our total proved reserves and extensions and discoveries for our proved undeveloped reserves. As indicated in our existing disclosures, we will continue to provide the
composition of our proved and proved undeveloped extensions and discoveries by asset.

 Each year, Devon’s proved reserves extensions
and discoveries consist of adding proved undeveloped reserves to locations classified as undeveloped at year-end and adding proved developed reserves from successful development wells drilled on locations
outside the areas classified as proved at the previous year-end. Therefore, it is not uncommon for Devon’s total proved extensions and discoveries to differ from the extensions and discoveries for
Devon’s proved undeveloped reserves. Furthermore, because annual additions are classified according to reserve determinations made at the previous year-end and because Devon operates a multi-basin
portfolio with assets at varying stages of maturity, extensions and discoveries for proved developed and proved undeveloped reserves can differ significantly in any particular year.

 Division of Corporation Finance

United States Securities and Exchange Commission

  Page
 3

 Proved Undeveloped Reserves, page 97

SEC Comment

4.
 Expand the discussion of the changes that occurred in your proved undeveloped reserves to include an
explanation of the material change due to revisions other than price. Your explanation should address the overall change for the line item by separately identifying and quantifying the net amount attributable to each factor that contributed to the
change, including offsetting factors, so that the change in net proved undeveloped reserves between periods is fully reconciled.

In particular, disclosure relating to revisions in previous estimates for reasons other than price should identify such individual
underlying factors as changes caused by well performance, improved recovery, or changes resulting from the removal of proved undeveloped locations due to changes in previously adopted development plan. Refer to the disclosure requirements in item
1203(b) of Regulation S-K.

 Response

The following discussion applies to our proved undeveloped reserves revisions for the year ended December 31, 2019. We commit to include a similar
discussion in our future filings.

 Proved undeveloped reserves revisions other than price were primarily due to changes in previously
adopted development plans in the Stack region of the Anadarko Basin (-9 MMBoe) and in the Delaware Basin (-6 MMBOE). An additional
-5 MMBoe of changes were due to reduced recovery estimates as a result of continued evaluation of analogous offset well performance primarily in the Stack region of the Anadarko Basin.

* * * * * * *

 In connection with the above
responses to the Staff’s comments, Devon acknowledges that:

•

 Devon is responsible for the adequacy and accuracy of the disclosure in the filing;

•

 Staff comments or changes to disclosure in response to Staff comments do not foreclose the Commission from taking
any action with respect to the filing; and

•

 Devon may not assert Staff comments as a defense in any proceeding initiated by the Commission or any person
under the federal securities laws of the United States.

 Sincerely,

/s/ Jeremy D. Humphers

 Jeremy D. Humphers

Senior Vice President and Chief Accounting Officer

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CORRESP

SKADDEN, ARPS, SLATE, MEAGHER & FLOM LLP

 1000 LOUISIANA, SUITE 6800

HOUSTON, TEXAS 77002-5026

_____

TEL: (713) 655-5100

FAX: (713) 655-5200

www.skadden.com

November 17, 2020

VIA EDGAR TRANSMISSION AND HAND DELIVERY

 FIRM/AFFILIATE OFFICES

_____

BOSTON

 CHICAGO

LOS ANGELES

 NEW YORK

PALO ALTO

 WASHINGTON, D.C.

WILMINGTON

_____

BEIJING

 BRUSSELS

FRANKFURT

 HONG KONG

LONDON

 MOSCOW

MUNICH

 PARIS

SÃO PAULO

 SEOUL

SHANGHAI

 SINGAPORE

TOKYO

 TORONTO

 Division of Corporation Finance

U.S. Securities and Exchange Commission

 100 F Street, N.E.

Washington, D.C. 20549

Attn:    Ms.
 Karina Dorin

    Ms. Loan Lauren Nguyen

Re:

 Devon Energy Corporation

 Registration Statement
on Form S-4

 Filed November 5, 2020

File No. 333-249859

 Dear Ms. Dorin and Ms. Nguyen:

On behalf of our client, Devon Energy Corporation, a Delaware corporation (the “Company”), we are providing its response to the
comment of the staff (the “Staff”) of the U.S. Securities and Exchange Commission (the “Commission”) received from the Staff by letter dated November 16, 2020 (the “Comment Letter”) with respect to the
Company’s Registration Statement on Form S-4 (File No. 333-249859) (the “Registration Statement”).

This letter is being filed electronically via the EDGAR system today. As discussed with the Staff on November 16, 2020, we are only
including the changes that we intend to make to the Registration Statement in response to the Comment Letter when we file an amendment to the Registration Statement. We hereby confirm that an amendment to the Registration Statement will not be filed
until the comments the Company received from the Staff by letter dated November 16, 2020 with respect to the Company’s Form 10-K for the Fiscal Year Ended December 31, 2019 are resolved.

The text of the Staff’s comment has been incorporated into this response letter for convenience. All references to page numbers and
captions (other than those in the Staff’s comments and unless otherwise stated) correspond to the page numbers and captions in the Registration Statement.

* * * * *

 Ms. Karina Dorin

Securities and Exchange Commission

 November 17, 2020

 Page
 2

 The Merger

Recommendation of the WPX Board and its Reasons for the Merger, page 73

1.
 Disclosure in this section states that the WPX Board considered the implementation of a “Fixed Plus
Variable” dividend strategy in recommending that WPX stockholders vote for the Merger Proposal. We also note Devon Energy’s Form 10-Q for the quarterly period ended September 30,
2020 states that upon closing of the Merger it intends to implement a fixed plus variable dividend strategy, with variable dividends up to 50% of excess quarterly free cash, subject to certain criteria. Please expand your disclosure to discuss the
criteria for the payment of the variable dividend and clarify how you expect the combined company to compute “excess free cash flow” in determining such variable dividend.

Response: The Company respectfully advises the Staff that the Company will include the following expanded disclosure in response to the
Staff’s comment in its amendment to the Registration Statement on page 103 in the section titled “The Merger—Dividend Policy”:

Following the closing of the merger, Devon expects to pursue a “fixed plus variable” dividend strategy. Under this strategy, Devon
plans to pay, on a quarterly basis, a fixed dividend amount and, potentially, a variable dividend amount, if any, to its stockholders. The declaration and payment of any future dividend, whether fixed or variable, will remain at the full discretion
of the Devon Board and will depend on Devon’s financial results, cash requirements, future prospects, COVID-19 impacts and other factors deemed relevant by the Devon Board. In determining the amount of
the quarterly fixed dividend, the Devon Board expects to consider a number of factors, including Devon’s financial condition, the commodity price environment and a general target of paying out approximately 10% of operating cash flow through
the fixed dividend. Any variable dividend amount will be determined by the Devon Board on a quarterly basis and will equal up to 50% of “excess free cash flow,” which Devon defines as operating cash flow less (i) capital expenditures
and (ii) the fixed quarterly dividend amount. The Devon Board will consider a number of factors in determining if a variable dividend payment will be made. Devon expects that the most critical factors will consist of Devon’s financial
condition, including its cash balances and leverage metrics, as well as the commodity price outlook. For additional information regarding risks associated with Devon’s dividends, please see “Risk Factors—Risks Relating to Devon and
WPX—Declaration, payment and amounts of dividends, if any, distributed to stockholders of Devon will be uncertain.”

 We also
intend to add a cross reference to the foregoing disclosure in the section titled “ The Merger—Recommendation of the WPX Board and its Reasons for the Merger.”

We thank you for your prompt attention to this letter responding to the Comment Letter and look forward to hearing from you at your earliest
convenience. If you have any questions regarding this filing, please contact Frank Bayouth at (713) 655-5115; Eric Otness at (713) 655-5135; or Jenna Godfrey at (202) 371-7567.

Sincerely,

 /s/ Eric Otness

Eric Otness

Skadden, Arps, Slate, Meagher & Flom LLP

United States securities and exchange commission logo
November 16, 2020
David A. Hager
President and Chief Executive Officer
Devon Energy Corporation
333 W. Sheridan Ave.
Oklahoma City, OK 73102-5015
Re:Devon Energy Corporation
Registration Statement on Form S-4
Filed November 5, 2020
File No. 333-249859
Dear Mr. Hager:
            We have limited our review of your registration statement to those issues we have
addressed in our comments.  In some of our comments, we may ask you to provide us with
information so we may better understand your disclosure.
            Please respond to this letter by amending your registration statement and providing the
requested information.  If you do not believe our comments apply to your facts and
circumstances or do not believe an amendment is appropriate, please tell us why in your
response.
            After reviewing any amendment to your registration statement and the information you
provide in response to these comments, we may have additional comments.
Registration Statement on Form S-4
The Merger
Recommendation of the WPX Board and its Reasons for the Merger, page 73
1.Disclosure in this section states that the WPX Board considered the implementation of a
"Fixed Plus Variable" dividend strategy in recommending that WPX stockholders vote for
the Merger Proposal.  We also note Devon Energy's Form 10-Q for the quarterly period
ended September 30, 2020 states that upon closing of the Merger it intends to implement a
fixed plus variable dividend strategy, with variable dividends up to 50% of excess
quarterly free cash, subject to certain criteria.  Please expand your disclosure to discuss
the criteria for the payment of the variable dividend and clarify how you expect the
combined company to compute "excess free cash flow" in determining such variable
dividend.

 FirstName LastNameDavid A. Hager
 Comapany NameDevon Energy Corporation
 November 16, 2020 Page 2
 FirstName LastName
David A. Hager
Devon Energy Corporation
November 16, 2020
Page 2
General
2.Please be advised that we will not be in a position to declare this registration statement
effective until you have resolved all comments on your Exchange Act reports.  Please
refer to the comment letter dated November 16, 2020 regarding your annual report on
Form 10-K for the fiscal year ended December 31, 2019.
            We remind you that the company and its management are responsible for the accuracy
and adequacy of their disclosures, notwithstanding any review, comments, action or absence of
action by the staff.
            Refer to Rules 460 and 461 regarding requests for acceleration.  Please allow adequate
time for us to review any amendment prior to the requested effective date of the registration
statement.
            Please contact Karina Dorin, Staff Attorney, at (202) 551-3763 or Loan Lauren Nguyen,
Legal Branch Chief, at (202) 551-3642 with any questions.
Sincerely,
Division of Corporation Finance
Office of Energy & Transportation
cc:       Eric Otness

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CORRESP - Confidential Treatment Requested Pursuant to Rule 83

 Devon Energy Corporation

333 West Sheridan Avenue

 Oklahoma
City, OK 73102

405 552 8183 phone
 jeremy.humphers@dvn.com

 Confidential Treatment Requested Pursuant to Rule 83

December 17, 2015

 Via EDGAR

Attention: Mr. John Hodgin, Petroleum Engineer

Mr. Brad Skinner

 Division of Corporation Finance

United States Securities and Exchange Commission

 100 F. Street,
N.E.

 Washington D.C. 20549-4631

Re:
Devon Energy Corporation

Form 10-K for Fiscal Year Ended December 31, 2014

Filed February 20, 2015

File No. 1-32318

 Dear Mr. Skinner:

This letter responds to the comment letter dated December 3, 2015, from the Division of Corporation Finance (the “Staff”), regarding Devon
Energy Corporation’s Form 10-K for the year ended December 31, 2014, filed February 20, 2015 (File No. 001-32318).

 In our responses
below to questions 1, 4, 5 and 6 of the Staff’s comment letter, we reference an exhibit (“Exhibit 1”) with tables (six total) that provide quantitative data (the “Confidential Materials”). Pursuant to Rule 83 of the U.S.
Securities Exchange Commission’s Rules on Information and Requests, 17 C.F.R. §200.83, Devon Energy Corporation (“Devon”) requests that the Confidential Materials be treated as confidential and that they not be disclosed to any
person pursuant to the Freedom of Information Act or otherwise. Exhibit 1 has been redacted and is instead marked with a typed legend stating “FOIA Confidential Treatment Requested by Jeremy D. Humphers, Senior Vice President and Chief
Accounting Officer.” An un-redacted version of this letter has been separately submitted to the Staff along with a request that the Confidential Materials be treated as confidential.

Devon’s responses to the staff’s comments are set forth below:

Form 10-K for the Fiscal Year Ended December 31, 2014

Business and Properties, page 3

 Oil and Gas
Properties, page 5

 SEC Comment

1.
Disclosure provided on pages 6 and 7 relating to your U.S. operating areas indicates that you are planning to drill a total of approximately 660 gross wells during 2015 compared to the 1,061 gross wells drilled
during 2014. In this regard, we note significant reductions in certain areas such as the Barnett Shale where you plan to drill 10 gross wells compared to the 84 gross wells drilled during 2014 and in the Mississippian-Woodford Trend where you plan
to drill 50 gross wells compared to the 236 gross wells drilled during 2014.

Mr. Brad Skinner

Confidential Treatment Requested Pursuant to Rule 83

 United States Securities and Exchange Commission

 Page
 2

 For each of your U.S. operating areas, please explain how you have taken into
consideration the reduction in the number of wells you plan to drill in 2015 in adopting a development plan that still results in converting your proved undeveloped reserves as of December 31, 2014 within five years of the initial disclosure of
these reserves. As part of your response, provide us with the net reserve quantities, if any, that you removed in each of your U.S. operating areas as a result of the changes for 2015 related to your plans to drill certain wells that had previously
been scheduled to be drilled during 2014 but were not, in fact, drilled during that year.

 Response

For each of our operating areas, we record proved undeveloped reserves when all the requirements of Rule 4-10 of Regulation S-X have been met. We specifically
comply with Rule 4-10(a)(31)(ii) when two criteria have been met: 1) We have established a development plan that has been approved by our Reserves Committee of the Board of Directors and will result in converting the proved undeveloped reserves
within five years from the initial disclosure of the reserves and 2) the associated development capital requirements are equal to or less than the management-approved capital program on a year-by-year basis. If either of these criteria cease to be
met, we remove the associated proved undeveloped reserves from our proved reserves disclosures.

 As we applied this evaluation process at the end of 2014,
we considered the reductions in the number of wells planned for 2015. Table 1 in the enclosed Exhibit 1 summarizes, by operating area, the net proved undeveloped reserves that we removed at the end of 2014 associated with wells that were originally
scheduled to be drilled in 2014 but were not. Table 1 also summarizes our proved undeveloped reserves as of December 31, 2014 by operating area.

Production, Production Prices and Production Costs, page 11

SEC Comment

2.
Please expand the tabular disclosure provided here and elsewhere on page 29 to include the total annual production volumes, by final product sold, for each of the last three fiscal years. Refer to the presentation
requirements in Item 1204(a) of Regulation S-K.

 Response

We will include total annual production volumes within the tabular disclosure for significant properties in future filings in accordance with Item 1204(a)
of Regulation S-K. However, daily volumes is the more meaningful production measure used by our investors and us to evaluate production trends. Therefore, we intend to continue disclosing and referencing daily production for each of our
operating areas within Management’s Discussion and Analysis in accordance with Item 303(a) of Regulation S-K.

 Notes to Consolidated
Financial Statements

 Supplemental Information on Oil and Gas Operations (Unaudited), page 102

Proved Undeveloped Reserves, page 110

Mr. Brad Skinner

Confidential Treatment Requested Pursuant to Rule 83

 United States Securities and Exchange Commission

 Page
 3

 SEC Comment

3.
You disclose the negative revisions relating to your proved undeveloped reserves, other than price for the fiscal year ending December 31, 2014, were primarily due to evaluations of certain U.S. onshore dry-gas
areas which the Company does not expect to develop in the next five years. We note similar disclosure of negative revisions for each fiscal year since you began providing separate disclosure of the changes in proved undeveloped reserves relating to
your U.S. properties, starting December 31, 2011. Your disclosures identify the largest revisions were related to the dry-gas areas in the Barnett Shale for the fiscal year ending 2014 and to the Barnett Shale and Carthage areas for the fiscal
years ending 2013, 2012 and 2011.

 Given the successive nature of your revisions, please tell us how you have
complied with the requirement of reasonable certainty for proved reserves relating to an adopted development plan and schedule as set forth in the definition of undeveloped reserves under Rule 4-10(a)(31)(ii) of Regulation S-X and in the answer to
Question 131.04 in the Compliance and Disclosure Interpretations (C&DIs), issued October 26, 2009 and updated May 16, 2013. You may find the C&DIs on our website at the following address:

http://www.sec.gov/divisions/corpfin/guidance/oilandgas-interp.htm.

Response

 As briefly summarized in our response to
question 1, we have designed policies and processes for recording proved undeveloped reserves, particularly with regards to reasonable certainty and adopted development plans, that comply with the Rule 4-10 requirements referenced in your question.

 Additionally, in our response to question 4 below, we provide additional quantitative analysis of the successive reserve reductions we recognized in 2011
through 2014. As noted in the response, the reductions to our proved undeveloped reserves resulted from management decisions to shift capital to operating areas generating the highest returns across our portfolio of assets as prices changed and
acquisition, divestiture and exploration activity occurred. While the operating areas from which we were shifting capital, namely U.S. dry gas regions, were similar in each year, the driving factors and areas receiving more capital were unique to
both the year and the allocation decisions being made. For example, in 2011 we shifted capital from dry-gas regions to liquids-rich regions due to rising prices for natural gas liquids and oil in contrast to declining natural gas prices. In 2013, we
began shifting more capital toward the Delaware Basin as a result of our oil-focused exploration successes. In 2014, we shifted a large portion of our capital toward our Eagle Ford asset that was acquired in early 2014.

SEC Comment

4.
We note your explanation of the changes in proved undeveloped reserves related to revisions other than price indicates these changes are “primarily” due to removing those reserves which the Company does not
expect to develop in the next five years. If your revisions are related to more than one unrelated cause, for example, changes in your corporate plans to drill certain wells and changes for well performance, provide us with the net quantities
attributable to each separate cause relating to your disclosure for each of the four years 2011 through 2014.

 Response

Table 2 in the enclosed Exhibit 1 summarizes the proved undeveloped reserves revisions other than price for 2011 through 2014. In each year, as indicated in
our disclosure explanation, the largest factor causing the revisions related to changes to our drilling plans that resulted in the removal of proved undeveloped reserves. In each year, the drilling plan changes resulted from management decisions to
shift capital to operating areas generating the highest returns across our portfolio of assets as prices changed and acquisition, divestiture and exploration activity occurred. The other less significant revisions to our proved undeveloped reserves
presented in Table 2 relate to well performance and cost structure and were generally positive in each year.

Mr. Brad Skinner

Confidential Treatment Requested Pursuant to Rule 83

 United States Securities and Exchange Commission

 Page
 4

 In our future filings, we will provide more detailed explanations for the revisions other than price we deem
to be both significant and unrelated.

 SEC Comment

5.
To help us understand the historical record and the associated activity impacting your reported proved undeveloped reserves, please provide us with a schedule that shows the ultimate disposition or current status for
all of the PUD locations (e.g. number of gross locations) scheduled to be drilled in the 12 month period following disclosure as of December 31, 2011, 2012, 2013 and 2014.

Your analysis of the ultimate disposition or current status for each period should account for the total number of gross PUD locations that
were:

•

scheduled to be drilled during the 12 months following disclosure at the end of the fiscal year,

•

actually drilled during the 12 months following disclosure at the end of the fiscal year,

•

deferred and actually drilled in another year (identify the year and number of gross PUD locations drilled in that specific year),

•

removed from the PUD category (identify the reason, e.g. no plans to drill, sold, performance, price, etc., the year and the number of gross PUD locations related to each reason), and

•

undrilled and remaining as PUDs at 12/31/2014.

 Response

Table 3 in the enclosed Exhibit 1 provides the requested reconciliation of our PUD locations for the U.S. and Canada, excluding our Jackfish Heavy Oil project
in Canada. Because the development timeline and spacing unit (pads rather than wells) for Jackfish differ from the rest of our PUD locations, the Jackfish PUD locations are reconciled separately in Table 4.

SEC Comment

6.
To help us understand the changes specific to the Barnett Shale, please provide us with:

•

the changes in the proved undeveloped Barnett Shale reserves pursuant to Item 1203(b) of Regulation S-K for each of the four fiscal years 2011 through 2014, and

•

a schedule that shows the ultimate disposition or current status for all of your Barnett Shale PUD locations (e.g. number of gross locations) scheduled to be drilled in the 12 month period following disclosure
as of December 31, 2011, 2012, 2013 and 2014.

 Response

Table 5 in the enclosed Exhibit 1 reconciles the changes in our Barnett Shale proved undeveloped reserves as requested.

Mr. Brad Skinner

Confidential Treatment Requested Pursuant to Rule 83

 United States Securities and Exchange Commission

 Page
 5

 Table 6 in the enclosed Exhibit 1 provides the requested reconciliation of our Barnett Shale PUD locations.

 * * * * * * *

 In connection with the above
response to the staff’s comment, Devon acknowledges that:

•

Devon is responsible for the adequacy and accuracy of the disclosure in the filing;

•

Staff comments or changes to disclosure in response to staff comments do not foreclose the Commission from taking any action with respect to the filing; and

•

Devon may not assert staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States.

Sincerely,

 /s/ Jeremy D. Humphers

Jeremy D. Humphers

 Senior Vice President and Chief Accounting
Officer

 Enclosures:

 Exhibit 1

 Exhibit 1

FOIA Confidential Treatment

Requested by Jeremy D. Humphers, Senior Vice President and Chief Accounting Officer

Exhibit 1

 to

Devon Energy Corporation’s Response Letter

to the Comment Letter Dated December 3, 2015, from the Division of Corporation Finance

[Redacted — FOIA Confidential Treatment Requested by

Jeremy D. Humphers, Senior Vice President and Chief Accounting Officer]

Mail Stop 4628
December 3, 2015

Via E -mail
Thomas L. Mitchell
Executive Vice President and Chief Financial Officer
Devon Energy Corporation
333 West Sheridan Avenue
Oklahoma City, Oklahoma 73102 -5015

Re: Devon Energy Corporation
 Form 10-K for Fiscal Year Ended December 31, 2014
Filed February 20, 2015
File No. 1 -32318

Dear Mr. Mitchell :

We have reviewed your filing an d have the following comments.  In some of our
comments, we may ask you to provide us with information so we may better understand your
disclosure.

Please respond to these comments  within ten busine ss days by providing the requested
information or advis e us as soon as possible when you will respond.  If you  do not believe our
comments apply to your facts and circumstances , please tell us why in your response.

After reviewing your response to these  comments, we may have  additional comments.

Form 10 -K for the Fiscal Year Ended December 3 1, 2014

Business and Properties, page 3

Oil and Gas Properties, page 5

1. Disclosure provided on pages 6 and 7 relating to your U.S. operating areas indicates that
you are planning to drill a total of approximately 660 gross wells during 2015 compared
to the 1,061 gross wells drilled during 2014.  In this regard, we note significant
reductions in certain areas such as the Barnett Shale where you plan to drill 10 gross
wells compared to the 84 gross wells drilled during 2014 and in the Mississippian -
Woodford  Trend where you plan to drill 50 gross wells compared to the 236 gross wells
drilled during 2014.

For each of your U.S. operating areas, please  explain how you have taken into

Thomas L. Mit chell
Devon Energy Corporation
December 3, 2015
Page 2

 consideration the reduction in the number of wells you plan to drill in 2015  in adopting a
development plan that still results in converting your proved undeveloped reserves as of
December 31, 2014 within five years of the initial disclosure of these reserves.  As part of
your response, provide us with the net reserve quantities, if any, that you removed in each
of your U.S. operating areas as a result of the changes for 2015 related to your plans to
drill certain wells that had previously been scheduled to be drilled during 2014 but were
not, in fact, drilled during that year.

Production, Production Prices and Production Costs, page 11

2. Please expand the tabular disclosure provided here and elsewhere on page 29 to include
the total annual production volumes, by final product sold, for each of the last three fiscal
years.  Refer  to the presentation requirements in Item 1204(a) of Regulation S -K.

Notes to Consolidated Financial Statements

Supplemental Information on Oil and Gas Operations (Unaudited), page 102

Proved Undeveloped Reserves, page 110

3. You disclose the negative rev isions relating to your proved undeveloped reserves, other
than price for the fiscal year ending December 31, 2014, were primarily due to
evaluations of certain U.S. onshore dry -gas areas which the Company does not expect to
develop in the next five years.   We note similar disclosure of negative revisions for each
fiscal year since you began providing separate disclosure of the changes in proved
undeveloped reserves relating to your U.S. properties, starting December 31, 2011.  Your
disclosures identify the  largest revisions were related to the dry -gas areas in the Barnett
Shale for the fiscal year ending 2014 and to the Barnett Shale and Carthage areas for the
fiscal years ending 2013, 2012 and 2011.

Given the successive nature of your revisions, please te ll us how you have complied with
the requirement of reasonable certainty for proved reserves relating to an adopted
development plan and schedule as set forth in the definition of undeveloped  reserves
under Rule 4 -10(a)(31)(ii) of Regulation S -X and in the  answer to Question 131.04 in the
Compliance and Disclosure Interpretations (C&DIs), issued October 26, 2009 and
updated May 16, 2013.  You may find the C&DIs on our website at the following
address:

http://www.sec.gov/divisions/corpfin/guidance/oilandga s-interp.htm.

4. We note your explanation of the changes in proved undeveloped reserves related to
revisions other than price indicates these changes are “primarily” due to removing those
reserves which the Company does not expect to develop in the next five  years.  If your
revisions are related to more than one unrelated cause, for example, changes in your

Thomas L. Mit chell
Devon Energy Corporation
December 3, 2015
Page 3

 corporate plans to drill certain wells and changes for well performance, provide us with
the net quantities attributable to each separate cause relating t o your disclosure for each
of the four years 2011 through 2014.

5. To help us understand the historical record and the associated activity impacting your
reported proved undeveloped reserves, please provide us with a schedule that shows the
ultimate disposit ion or current status for all of the PUD locations (e.g. number of gross
locations) scheduled to be drilled in the 12 month period following disclosure as of
December 31, 2011, 2012, 2013 and 2014.

Your analysis of the ultimate disposition or current stat us for each period should account
for the total number of gross PUD locations that were:

 scheduled to be drilled during the 12 months following disclosure at the end of the
fiscal year,

 actually drilled during the 12 months following disclosure at the end of the fiscal
year,

 deferred and actually drilled in another year (identify the year and number of
gross PUD locations drilled in that specific year),

 removed from the PUD category (identify the reason, e.g. no plans to drill, sold,
performance, pric e, etc., the year and the number of gross PUD locations related
to each reason), and

 undrilled and remaining as PUDs at 12/31/2014.

6. To help us understand the changes specific to the Barnett Shale, please provide us with:

 the changes in the proved undeve loped Barnett Shale reserves pursuant to Item
1203(b) of Regulation S -K for each of the four fiscal years 2011 through 2014,
and

 a schedule that shows the ultimate disposition or current status for all of your
Barnett Shale PUD locations (e.g. number of g ross locations) scheduled to be
drilled in the 12 month period following disclosure as of December 31, 2011,
2012, 2013 and 2014.

You may furnish the materials relating to comments 5 and 6 in hard copy format or on
digital media such as flash drive or com pact disk.  If you would like to have these
supplemental materials returned to you, please comply with the provisions of Rule 418(b)
of Regulation C, which provides for the return of supplemental information as long as
certain express conditions are met.

Thomas L. Mit chell
Devon Energy Corporation
December 3, 2015
Page 4

If you wish to request confidential treatment of those materials which they are in our
possession, please follow the procedures set forth in Rule 83 of the Freedom of
Information Act.

Please direct these items to:

U.S. Securities and Exchange Commission
100 F Street NE
Washington, DC 20549 -4628
Attn: John Hodgin

We urge all persons who are responsible for the accuracy and adequacy of the disclosure
in the filing to be certain that the filing includes the information the Securities Exchange Act of
1934 an d all applicable Exchange Act rules require.   Since the company and its management are
in possession of all facts relating to a company’s disclosure, they are responsible for the accuracy
and adequacy of the disclosures they have made.

 In responding to our comments, please provide  a written statement from the company
acknowledging that:

 the company is responsible for the adequacy and accuracy of the disclosure in the filing;

 staff comments or changes to disclosure in response to staff comments do not foreclose
the Commission from taking any action with respect to the filing; and

 the company may not assert staff comments as a defense in any proceeding initiated by
the Commission or any person under the federal securities laws of the United States.

You may contact John Hodgin, Petroleum Engineer, at (202) 551 -3699 if you have
questions regarding the comments .  Please contact me at (202) 551 -3489 with any other
questions.

Sincerely,

 /s/ Brad Skinner

Brad Skinner
Senior Assistant Chief Accountant

December 16, 2014

Via E -mail
Thomas L. Mitchell
Executive Vice President and Chief Financial Officer
Devon Energy Corporation
333 West Sheridan Avenue
Oklahoma City, OK 73102

 Re: Devon Energy Corporation
  Form 10 -K for Fiscal Year Ended December 31, 2013
  Filed February 28, 2014
  File No. 1 -32318

Dear Mr. Mitchell:

We refer you to our comment letter dated November 17, 2014, regarding countries that
have been identified as state sponsors of terrorism .  We have completed our review of this
subject matter.  We remind you that our comments or changes to disclosure in response to our
comments do not foreclose the Commission from taking any action with respect to the company
or the  filing and the company may not assert staff comments as a defense in any proceeding
initiated by the Commission or any person under the federal securities laws of the United States.
We urge all persons who are responsible for the accuracy and adequacy of  the disclosure in the
filing to be certain that the filing includes the information the Securities Exchange Act of 1934
and all applicable rules require.

         Sincerely,

         /s/ Cecilia Blye

         Cecilia Blye, Chief
         Office of Global Security Risk

cc:  Roger Schwall
  Assistant Director
 Division of Corporation Finance

 Jeremy Humphers
 Senior Vice President and Chief Accounting Officer
 Devon Energy Corporation

CORRESP
1
filename1.htm

CORRESP

 Devon Energy Corporation

 333 West Sheridan
Avenue

 Oklahoma City, OK 73102

405 228 2839 phone tom.mitchell@dvn.com

 December 2, 2014

Via EDGAR

 Attention: Mr. Daniel
Leslie, Office of Global Security Risk

 Ms. Cecilia Blye

Office of Global Security Risk

 United States Securities and
Exchange Commission

 Division of Corporation Finance

 100 F.
Street, N.E.

 Washington D.C. 20549-4631

Re:
Devon Energy Corporation

Form 10-K for Fiscal Year Ended December 31, 2013

Filed February 28, 2014

File No. 1-32318

 Dear Ms. Blye:

On behalf of Devon Energy Corporation (the “Company” or “Devon”), this letter is submitted in response to the comment provided in the
Staff’s letter dated November 17, 2014 with respect to Devon’s Annual Report on Form 10-K referenced above. For your convenience, we have repeated the Staff’s comment below followed by Devon’s response.

General

 SEC Comment

1.
On pages 7, 37, and elsewhere in the 10-K you refer to your joint venture with Sinopec Corporation. You state on page 40 that the joint venture had remaining commitments at the end of 2013. The 20-F filed
April 28, 2014 by China Petroleum & Chemical Corporation (“CPCC”) indicates that CPCC is also known as “Sinopec Corp.” We are aware of recent state government and university divestment or similar initiatives
regarding CPCC due to its contacts with Iran and Sudan. Iran and Sudan are designated by the State Department as state sponsors of terrorism, and are subject to U.S. economic sanctions and export controls. Please discuss for us the potential for
your relationship with Sinopec to have an adverse impact on your reputation and share value.

 Devon Response

In 2012, we entered into a joint venture with Tip Top Energy Production US LLC (“Tip Top”), a Sinopec affiliate, involving Devon’s acreage
positions in five oil and gas exploration plays, which are all located in the United States. As a Delaware limited liability company, Tip Top is governed by applicable U.S. law. Additionally, the agreements related to the joint venture contemplate
that the joint venture will act in accordance with applicable law. Pursuant to our joint venture agreement, Tip Top acquired a 33.3 percent interest in these plays in exchange for an approximate $900 million cash payment and a commitment to fund
approximately $1.6 billion of Devon’s share of future exploration, development and drilling costs associated with these plays. Devon has no other business relationships with Tip Top or Sinopec outside of this joint venture.

 Cecilia Blye

United States Securities and Exchange Commission

December 2, 2014

We broadly marketed this joint venture opportunity to a wide variety of potential partners, ultimately selecting Tip Top as our joint venture partner. When we
entered into the joint venture, we were aware of Tip Top’s affiliation with Sinopec and considered such affiliation in our decision to enter into the joint venture. We did not believe that our joint venture with Tip Top would have a material
adverse impact on our reputation and share value. Rather, we expected that the joint venture would be viewed favorably by our investors. When our joint venture with Tip Top was announced on January 3, 2012, our stock rose 6.6% from the previous
closing price, which was noticeably better than the 4.0% gain experienced by our peer group on the same day.

 We market and sell all oil and gas
production from the joint venture plays to our customers, which have only included U.S.-based customers to date. Furthermore, Tip Top does not take delivery of any production from the joint venture; therefore, there is no possibility that Sinopec is
selling production from the plays to Iran, Sudan or other known state sponsors of terrorism. We do not have any contacts with, or business activities in or involving, Iran or Sudan. We do not have any future plans to conduct business in those
countries.

 Devon has not received any inquiries from investors or analysts questioning or otherwise concerned with the Sinopec joint venture. In
addition, we are not aware of any Devon investors selling or closing their investment as a result of our joint venture with Sinopec.

 We do not believe
that the joint venture with Tip Top has had or will have a material adverse impact on Devon’s reputation or share value.

 * * * * * * *

 In connection with the above response to the Staff’s comment, Devon acknowledges that:

•

Devon is responsible for the adequacy and accuracy of the disclosure in the filing;

•

Staff comments or changes to disclosure in response to Staff comments do not foreclose the Commission from taking any action with respect to the filing; and

•

Devon may not assert Staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States.

Sincerely,

 DEVON ENERGY CORPORATION

/s/ Thomas L. Mitchell

 Thomas L. Mitchell

Executive Vice President and Chief Financial Officer

November 17, 2014

Via E -mail
Thomas L. Mitchell
Executive Vice President  and Chief Financial  Officer
Devon Energy Corporation
333 West Sheridan Avenue
Oklahoma City, OK 73102

 Re: Devon Energy Corporation
  Form 10 -K for Fiscal Year Ended December 31, 201 3
  Filed February 28, 2014
  File No. 1 -32318

Dear Mr. Mitchell :

We have limited our review of your filing to your contacts with countries that have been
identified  as state sponsors of terrorism, and we have the following comment .  Our review with
respect to this issue does not preclude further review by the Assistant Director group with respect
to other issues.   In our comment  we ask you to provide us with inform ation so we may better
understand your disclosure.

Please respond to this letter within ten business days by providing the requested
information, or by advising us when you will provide the requested response.  If you do not
believe our comment  applies to your facts and circumstances, please tell us why in your
response.

After reviewing the information you provide in response to th is comment , we may have
additional comments.

General

1. On pages 7, 37, and elsewhere in the 10 -K you refer to your joi nt venture with Sinopec
Corporation.  You state on page 40 that the joint venture had remaining commitments at
the end of 2013.  The 20 -F filed April 28, 2014 by China Petroleum & Chemical
Corporation (“CPCC”) indicates that CPCC is also known as “Sinopec Corp.”  We are
aware of recent state government and university divestment or similar initiatives
regarding CPCC due to its contacts with Iran and Sudan.  Iran and Sudan are designated
by the State Department as state sponsors of terrorism, and are subject to U.S. economic
sanctions and export controls.  Please discuss for us the potential for your relationship
with Sinopec to have an adverse impact upon your reputation and share value.

Thomas L. Mitchell
Devon Energy Corporation
November 17, 2014
Page 2

 We urge all persons who are responsible  for the accuracy and adequacy of the di sclosure
in the filing to be certain that the filing includes the information the Securities Exchange Act of
1934 and all applicable Exchange Act rules require.  Since the company and its management are
in possession of all facts relating to the company’s disclosure, they are responsible for the
accuracy and adequacy of the disclosures they have made.

In responding to our comments, please provide a written statement from the company
acknowledging that:

 the company is responsible for the adequacy and ac curacy of the disclosure in the filing;

 staff comments or changes to disclosure in response to staff comments do not foreclose
the Commission from taking any action with respect to the filing; and

 the company may not assert staff comments as a defense in  any proceeding initiated by
the Commission or any person under the federal securities laws of the United States.

Please contact Daniel Leslie, Staff Attorney, at (202) 551 -3876  or me at (202) 551 -3470
if you have any questions about the comment  or our review.

         Sincerely,

         /s/ Cecilia Blye

         Cecilia Blye , Chief
         Office of Global Security Risk

cc:  Roger Schwall
  Assistant Director
 Division of Corporation Finance

 Jeremy Humphers
 Senior Vice President and Chief Accounting Officer
 Devon Energy Corporation

February 28 , 2014

Via Email
Thomas L. Mitchell
Chief Financial O fficer
Devon Energy Corporat ion
333 West Sheridan Avenue
Oklahoma City, OK 73102

Re: Devon Energy Corporation
 Form 10-K for Fiscal Year Ended
December 31, 2012
Filed February 21, 2013
File No. 001 -32318

Dear Mr. Mitchell :

We have completed our review of your filing .  We remind you that our comments or
changes to disclosure in response to our comments do not foreclose the Commission from taking
any action with respect to the company or the filing and the company may not assert staff
comments as a defense in any proceeding initiated by the Commission or any person under the
federal securities laws of the United  States.  We urge all persons who are responsible for the
accuracy and adequacy of the disclosure in the filing to be certain that the filing include the
information the Securities Exchange Act of 1934 and all applicable rules require.

Sincerely,

 /s/ Ethan Horowitz

        Ethan Horowitz
Branch Chief

CORRESP
1
filename1.htm

Correspondence

 Devon Energy Corporation

 333 West Sheridan
Avenue

 Oklahoma City, OK 73102

405 552 8183 jeremy.humphers@dvn.com

 February 27, 2014

Via EDGAR

 Attention: Ms. Svitlana
Sweat, Division of Corporation Finance

 Ethan Horowitz

Branch Chief

 United States Securities and Exchange Commission

 100 F. Street, N.E.

 Washington, D.C. 20549

Devon Energy Corporation

Re:
Devon Energy Corporation

Form 10-K for the Fiscal Year Ended December 31, 2012

Filed February 21, 2013

File No. 001-32318

 Dear Mr. Horowitz:

This letter responds to the staff’s comment letter dated February 7, 2014, regarding Devon Energy Corporation’s Form 10-K for the year ended
December 31, 2012, filed February 21, 2013 (File No. 001-32318). This letter is meant to supplement the responses that Devon provided in its February 14, 2014 and February 26, 2014 letters to the staff. Devon’s
responses to the staff’s comments are set forth below:

 Form 10-K for Fiscal Year Ended December 31, 2012

Notes to Consolidated Financial Statements

Note 22 – Supplemental Information on Oil and Gas Operations (Unaudited), page 87

Standardized Measure, page 97

 SEC Comment

1.
Your response to comment 5 in our letter dated January 17, 2014 states that certain general and administrative costs which are required to operate your upstream oil and gas business are not included in the
calculation of the limitation on capitalized costs as these are not well-level expenditures, but have been included as future costs in calculating the standardized measure of discounted future net cash flows. Your response refers to the definition
of the term “production costs” per Rule 4-10(a)(20) of Regulation S-X. Please tell us whether these types of general and administrative costs are considered to be operating costs of support equipment and facilities or other costs of
operating and maintaining wells and related equipment and facilities.

 Response

In our February 26, 2014 response to this comment, we indicated that we had decided not to include production support costs in our results of operations
and standardized measure supplemental disclosures. After further consideration, we have decided to reverse this decision and will not make this change in our future filings.

 Ethan Horowitz

United States Securities and Exchange Commission

February 27, 2014

 SEC Comment

2.
In connection with your response to the preceding comment, please tell us if any general and administrative costs related to oil and gas production are deducted in calculating the limitation on capitalized costs and
describe the process through which you determine whether these costs are property-level expenditures. In addition, your response should explain whether these types of costs are deemed to be essential to operating and maintaining your wells and
related equipment and facilities. As part of your response, please also describe the types of costs which are deemed to be well-level expenditures.

Response

 We have no supplemental information to add to
the responses in our February 14, 2014 and February 26, 2014 letters.

 SEC Comment

3.
Your response to comment 5 in our letter dated January 17, 2014 references FASB ASC 932-235-50-26, which requires the disclosure of results of operations for oil- and gas-producing activities and indicates that
“some expenses incurred at an entity’s central administrative office may not be general corporate expenses, but rather may be operating expenses of oil- and gas-producing activities and should be reported as such.” The first sentence
of that section defines results of operations for oil-and gas-producing activities as revenues less production (lifting) costs and goes on to specify other costs that should be included. If general and administrative costs are determined to be
operating costs of oil- and gas-producing activities, please tell us how these costs would be classified within that definition other than as production (lifting) costs.

Response

 We have no supplemental information to add to
the responses in our February 14, 2014 and February 26, 2014 letters.

 SEC Comment

4.
The definition of production costs in Rule 4-10(a)(20) of Regulation S-X is almost identical to the definition of production costs in FASB ASC 932-360-25-15, and that the limitation on capitalized costs in Rule
4-10(c)(4)(i)(A) of Regulation S-X and required disclosures applicable to the standardized measure in FASB ASC 932-235-50-31(b) both refer to estimated future expenditures “to be incurred in developing and producing the proved oil and gas
reserves.” Please tell us your authoritative basis for including certain general and administrative costs determined to be operating costs in the results of operations of oil- and gas-producing activities and in the standardized measure of
discounted future net cash flows, but not in the determination of the limitation on capitalized costs.

 Response

We have no supplemental information to add to the responses in our February 14, 2014 and February 26, 2014 letters.

* * * * * * *

 2

 Ethan Horowitz

United States Securities and Exchange Commission

February 27, 2014

 In connection with the above response to the staff’s comment, Devon acknowledges that:

•

Devon is responsible for the adequacy and accuracy of the disclosure in the filing;

•

Staff comments or changes to disclosure in response to staff comments do not foreclose the Commission from taking any action with respect to the filing; and

•

Devon may not assert staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States.

Sincerely,

 /s/ Jeremy D. Humphers

Jeremy D. Humphers

 Vice President, Accounting

 3

CORRESP
1
filename1.htm

CORRESP

 Devon Energy Corporation

333 West Sheridan Avenue

 Oklahoma
City, OK 73102

 405 552 8183

jeremy.humphers@dvn.com

 February 26, 2014

Via EDGAR

 Attention: Ms. Svitlana
Sweat, Division of Corporation Finance

 Ethan Horowitz

Branch Chief

 United States Securities and Exchange Commission

 100 F. Street, N.E.

 Washington, D.C. 20549

Devon Energy Corporation

Re:
Devon Energy Corporation

 Form 10-K for the Fiscal Year Ended December 31, 2012

 Filed February 21, 2013

File No. 001-32318

 Dear
Mr. Horowitz:

 This letter responds to the staff’s comment letter dated February 7, 2014, regarding Devon Energy Corporation’s Form
10-K for the year ended December 31, 2012, filed February 21, 2013 (File No. 001-32318). This letter is meant to supplement the responses that Devon provided in its February 14, 2014 letter to the staff. Devon’s responses to
the staff’s comments are set forth below:

 Form 10-K for Fiscal Year Ended December 31, 2012

Notes to Consolidated Financial Statements

Note 22 – Supplemental Information on Oil and Gas Operations (Unaudited), page 87

Standardized Measure, page 97

 SEC Comment

1.
Your response to comment 5 in our letter dated January 17, 2014 states that certain general and administrative costs which are required to operate your upstream oil and gas business are not included in the
calculation of the limitation on capitalized costs as these are not well-level expenditures, but have been included as future costs in calculating the standardized measure of discounted future net cash flows. Your response refers to the definition
of the term “production costs” per Rule 4-10(a)(20) of Regulation S-X. Please tell us whether these types of general and administrative costs are considered to be operating costs of support equipment and facilities or other costs of
operating and maintaining wells and related equipment and facilities.

 Response

In our February 14, 2014 response to this comment, we identified and described “production support” costs that we include in our results of
operations and standardized measure but exclude in our ceiling limitation computation. We would like to provide additional qualitative and quantitative information with regards to these costs.

 Ethan Horowitz

United States Securities and Exchange Commission

 February 26,
2014

 As previously described, these costs largely consist of labor, materials and supplies for oil and gas
production monitoring and support activities, including information technology, transaction accounting, supply chain and certain other administrative support functions. In fact, roughly 80% of the production support costs included in our results of
operations and standardized measure are comprised of information technology, transaction accounting, supply chain and other administrative support costs. We have historically allocated these costs to our results of operations and standardized
measure based on a proportionate share of departmental employee costs. Based on their nature, none of these costs meet the definition of production costs in Rule 4-10(a)(20). Furthermore, because these costs are not production or well-level costs,
they should not be included in our ceiling limitation computation, which is consistent with our accounting treatment. Based on informal surveys, we believe our accounting treatment of these costs is consistent with that of other full cost companies.

 The remaining 20% of the production support costs that we include in our results of operations and standardized measure but exclude from our ceiling
limitation computation are comprised of employee costs for oil and gas production supervision activities. In many respects, these costs are the residual general and administrative costs in our upstream oil and gas cost centers after charging
production costs to wells (i.e., recognizing production costs as lease operating expenses) and capitalizing costs pursuant to the full cost method of accounting. We believe our distinction of which non-capitalized employee compensation costs we
recognize as production costs (i.e., lease operating expenses) and, therefore, included in our ceiling test computation, or recognize as general and administrative expenses is key to the staff’s understanding of the appropriateness of our
ceiling test computation.

 Importantly, Devon’s accounting treatment for this type of cost determination is based on the terms of the governing
contracts—the joint operating agreements (“JOAs”). We record as production costs those operating costs that can be charged to the wells under the JOAs. Based on informal surveys, we believe this accounting treatment is consistent with
other peer companies. Specific to this accounting distinction, JOAs allow employee compensation costs of staff and first-level supervision to be charged to the wells as production costs (or capital). Additionally, if higher levels of supervision
work on a specific well and charge time to that well, then the associated costs can be charged to the well as production costs (or capital).

 For Devon, a
foreman is the first-level of supervision over upstream oil and gas field staff (see Table 1 below). Therefore, 100% of compensation costs for Devon’s oil and gas field staff and foremen are charged to wells under the JOAs and are, therefore,
considered production costs (or capital). Devon’s superintendents are typically the next level of supervision above foremen and managers typically supervise superintendents. Generally, compensation costs for Devon’s superintendents and
managers are recognized as general and administrative costs. If superintendents and managers charge time to wells, the associated compensation costs are recognized as production costs (or capital). Vice presidents rarely, if ever, charge time to
wells. Therefore, the superintendent level is primarily the level at which Devon determines employee compensation costs as either production or general and administrative costs.

Table 1.

 People Hierarchy

Asset Hierarchy Assignment

Ratio of People to Wells

 Executive VP

Global E&P

n/m

 Senior VP

Division

n/m

 Vice President

Business Unit

n/m

 Manager

Business Unit / Region

1:240

 Superintendent

Region

1:400

 Foreman

Field Group / Field

1:60

 Staff

Wells

n/m

 n/m – not meaningful or relevant

 2

 Ethan Horowitz

United States Securities and Exchange Commission

 February 26,
2014

 Superintendents generally work in field locations, while managers and higher levels of supervision typically
work in corporate office locations. For Devon, managers may be assigned to an entire business unit, or to a region, depending on the business unit/region size, activity level, etc. An example of a business unit is “North Texas,” while an
example of a region is “Barnett Shale North.” In most cases, Devon assigns superintendents to a region.

 Additionally, superintendents oversee a
specific function or a range of functions, depending on factors such as asset size, asset life-cycle stage, individual experience, leadership abilities, etc. In certain regions, Devon’s superintendents oversee only production operations. In
other regions, superintendents oversee both completion and production operations because completion activities have a highly correlated impact on production levels. In certain limited regions, superintendents oversee drilling, completion and
production operations. If superintendents oversee more than just production operations, a portion of their cost is capitalized pursuant to full cost accounting rules. These capitalized costs are included as development costs in our ceiling
limitation computation. In summary, Devon’s superintendents oversee operations in a large geographic area that frequently involve oversight of more than just production operations. Devon’s superintendents supervise foremen and staff in
field offices as well as monitor production for the large groups of properties in their region. Currently, Devon has about 400 wells for every 1 superintendent. We believe this ratio and the nature of the superintendents’ job responsibilities
provide further evidence to support our conclusion that superintendent compensation costs should not be considered production costs as defined in Rule 4-10(a)(20). As previously mentioned, to the extent superintendents work on a specific well or
property, their compensation costs are charged to that individual property and are reported as production costs.

 Of the production support costs that we
include in our results of operations, superintendent compensation costs represent roughly 5% of the total general and administrative expense amount. In our standardized measure, these same costs represent less than 1% of the future production costs
included in our standardized measure.

 In conclusion, we believe the accounting treatment in our full cost ceiling limitation of the administrative and
supervisory production support costs described above is appropriate.

 However, after further analysis and consideration of production cost definitions,
the relevant disclosure rules and the disclosures made by peer companies, we have decided not to include these production support costs in our results of operations and standardized measure supplemental disclosures. Because this change to our
supplemental disclosures has no impact to our previously report financial condition, results of operations or cash flows, we intend to make this change in our future filings. We will disclose the nature and reason for the disclosure change,
including the effect of the change on our previously reported results of operations and standardized measure.

 SEC Comment

2.
In connection with your response to the preceding comment, please tell us if any general and administrative costs related to oil and gas production are deducted in calculating the limitation on capitalized costs and
describe the process through which you determine whether these costs are property-level expenditures. In addition, your response should explain whether these types of costs are deemed to be essential to operating and maintaining your wells and
related equipment and facilities. As part of your response, please also describe the types of costs which are deemed to be well-level expenditures.

Response

 We have no supplemental information to add to
the response in our February 14, 2014 letter.

 3

 Ethan Horowitz

United States Securities and Exchange Commission

 February 26,
2014

 SEC Comment

3.
Your response to comment 5 in our letter dated January 17, 2014 references FASB ASC 932-235-50-26, which requires the disclosure of results of operations for oil- and gas-producing activities and indicates that
“some expenses incurred at an entity’s central administrative office may not be general corporate expenses, but rather may be operating expenses of oil- and gas-producing activities and should be reported as such.” The first sentence
of that section defines results of operations for oil-and gas-producing activities as revenues less production (lifting) costs and goes on to specify other costs that should be included. If general and administrative costs are determined to be
operating costs of oil- and gas-producing activities, please tell us how these costs would be classified within that definition other than as production (lifting) costs.

Response

 We have no supplemental information to add to
the response in our February 14, 2014 letter.

 SEC Comment

4.
The definition of production costs in Rule 4-10(a)(20) of Regulation S-X is almost identical to the definition of production costs in FASB ASC 932-360-25-15, and that the limitation on capitalized costs in Rule
4-10(c)(4)(i)(A) of Regulation S-X and required disclosures applicable to the standardized measure in FASB ASC 932-235-50-31(b) both refer to estimated future expenditures “to be incurred in developing and producing the proved oil and gas
reserves.” Please tell us your authoritative basis for including certain general and administrative costs determined to be operating costs in the results of operations of oil- and gas-producing activities and in the standardized measure of
discounted future net cash flows, but not in the determination of the limitation on capitalized costs.

 Response

We have no supplemental information to add to the response in our February 14, 2014 letter.

* * * * * * *

 In connection with the above
response to the staff’s comment, Devon acknowledges that:

•

Devon is responsible for the adequacy and accuracy of the disclosure in the filing;

•

Staff comments or changes to disclosure in response to staff comments do not foreclose the Commission from taking any action with respect to the filing; and

•

Devon may not assert staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States.

Sincerely,

/s/ Jeremy D. Humphers

Jeremy D. Humphers

Vice President, Accounting

 4

CORRESP
1
filename1.htm

CORRESP

Devon Energy Corporation

405 552 8183

333 West Sheridan Avenue

jeremy.humphers@dvn.com

Oklahoma City, OK 73102

 February 14, 2014

Via EDGAR

 Attention: Ms. Svitlana
Sweat, Division of Corporation Finance

 Ethan Horowitz

Branch Chief

 United States Securities and Exchange Commission

 100 F. Street, N.E.

 Washington, D.C. 20549

Devon Energy Corporation

Re:
Devon Energy Corporation

 Form 10-K for the Fiscal Year Ended December 31, 2012

 Filed February 21, 2013

Supplemental Response Letter Date January 28, 2014

File No. 001-32318

 Dear
Mr. Horowitz:

 This letter responds to the staff’s comment letter dated February 7, 2014, regarding Devon Energy Corporation’s Form
10-K for the year ended December 31, 2012, filed February 21, 2013 (File No. 001-32318). Devon’s responses to the staff’s comments are set forth below:

Form 10-K for Fiscal Year Ended December 31, 2012

Notes to Consolidated Financial Statements

Note 22 – Supplemental Information on Oil and Gas Operations (Unaudited), page 87

Standardized Measure, page 97

 SEC Comment

1.
Your response to comment 5 in our letter dated January 17, 2014 states that certain general and administrative costs which are required to operate your upstream oil and gas business are not included in the
calculation of the limitation on capitalized costs as these are not well-level expenditures, but have been included as future costs in calculating the standardized measure of discounted future net cash flows. Your response refers to the definition
of the term “production costs” per Rule 4-10(a)(20) of Regulation S-X. Please tell us whether these types of general and administrative costs are considered to be operating costs of support equipment and facilities or other costs of
operating and maintaining wells and related equipment and facilities.

 Response

The general and administrative costs that are the subject of your comments are not operating costs of support equipment and facilities.

 Ethan Horowitz

United States Securities and Exchange Commission

 February 14,
2014

 While we have several operating cost classifications in our statement of operations, the nature our upstream
oil and gas operating costs generally fall into one of four categories: well-level production costs, well-level production overhead costs, production support costs and general corporate overhead costs, including interest. We classify our general
corporate overhead costs as general and administrative expenses in our statement of operations. None of these costs are included in our ceiling limitation computation, our standardized measure nor our results of operations.

Well-level production costs are mostly comprised of labor, power and fuel, site maintenance, facility maintenance and repairs, disposal activities, workovers,
chemicals, equipment maintenance and repairs, insurance and production and property taxes. Well-level production overhead costs are comprised of the overhead charges that operators charge their partners under joint operating agreements. In the
United States, this is generally the COPAS overhead charge. We classify well-level production costs and well-level production overhead costs as lease operating expenses or taxes other than income taxes in our statement of operations. Additionally,
we include these costs in future production costs in both our ceiling limitation computation and our standardized measure. We also include these costs in our results of operations disclosure as lease operating expenses and taxes other than income
taxes.

 As we responded to your previous comment 5, production support costs largely consist of labor, materials and supplies for oil and gas production
monitoring and support activities, including information technology, transaction accounting and certain other administrative support functions. To a lesser extent, these costs include labor for oil and gas production supervision activities. We
classify our production support costs as a portion of general and administrative expenses in our statement of operations. Additionally, we include these costs in future production costs in our standardized measure. We also include these costs in our
results of operations disclosure as general and administrative expenses. We use an allocation method for purposes of including these costs in our standardized measure and results of operations. We do not include these costs in our ceiling limitation
computation.

 Consequently, our treatment of this category of costs we describe as production support costs has become the focus of this review. A strict
interpretation of the production cost definitions and descriptions in Rule 4-10(a)(20) of Regulation S-X and FASB ASC 932-235-50-26 indicates that oil and gas producing activities would have only two types of costs: production (or well-level
production and production overhead) and general corporate overhead, including interest. However, we believe an oil and gas company, particularly a large company, can have another category of costs—production support. These costs are not
“incurred to operate or maintain wells and related equipment and facilities,” and they definitely are not general corporate overhead. Yet, in many ways, these support costs are essential to the production of proved reserves.

In determining whether to include these production support costs in our ceiling limitation computations, we rely heavily on the terms of the joint operating
agreements (the “JOA”). The JOA governs what costs can be charged to wells or projects. As we classify them, well-level production costs and well-level production overhead costs are all costs that can be charged to the wells under the JOA.
Clearly, these are well-level production costs as defined in Rule 4-10(a)(20) of Regulation S-X. However, production support costs are not allowed to be charged to the wells under the JOA. Therefore, we do not interpret these costs to be well-level
production costs as defined in Rule 4-10(a)(20) of Regulation S-X. Consequently, we do not include them in our ceiling limitation computation.

 In making
this conclusion, we do not consider these production support costs to be a component of the full cost impairment test because we do not consider them to be well-level costs. We believe, and in select cases know, this conclusion is consistent with
other full cost companies. We also believe this treatment would be consistent with impairment tests performed by successful efforts companies. However, as stated in the previous paragraph, we deem these costs essential to the production of proved
reserves even though they are not well-level expenditures. As a result, we include these costs in our standardized measure and results of operations.

 2

 Ethan Horowitz

United States Securities and Exchange Commission

 February 14,
2014

 SEC Comment

2.
In connection with your response to the preceding comment, please tell us if any general and administrative costs related to oil and gas production are deducted in calculating the limitation on capitalized costs and
describe the process through which you determine whether these costs are property-level expenditures. In addition, your response should explain whether these types of costs are deemed to be essential to operating and maintaining your wells and
related equipment and facilities. As part of your response, please also describe the types of costs which are deemed to be well-level expenditures.

Response

 Please see our response to comment 1.

SEC Comment

3.
Your response to comment 5 in our letter dated January 17, 2014 references FASB ASC 932-235-50-26, which requires the disclosure of results of operations for oil- and gas-producing activities and indicates that
“some expenses incurred at an entity’s central administrative office may not be general corporate expenses, but rather may be operating expenses of oil- and gas-producing activities and should be reported as such.” The first sentence
of that section defines results of operations for oil-and gas-producing activities as revenues less production (lifting) costs and goes on to specify other costs that should be included. If general and administrative costs are determined to be
operating costs of oil- and gas-producing activities, please tell us how these costs would be classified within that definition other than as production (lifting) costs.

Response

 As discussed in our response to comment 1, we
consider production support costs, which are included in general and administrative expenses in our statement of operations, to be operating expenses of oil and gas producing activities for our results of operations disclosure. We believe the
sentence in FASB ASC 932-235-50-26, which indicates that “some expenses incurred at an entity’s central administrative office may not be general corporate expenses, but rather may be operating expenses of oil and gas producing activities
and should be reported as such,” support our treatment of production support costs in our results of operations disclosure. While these costs are not incurred to operate or maintain wells and related equipment and facilities, we have included
these costs in our results of operations disclosures because we believe they are necessary costs of maintaining an oil and gas operating business. Based on our research of public filings, it appears several of our peer companies also similarly
deduct a portion of general and administrative expenses in their results of operations disclosures.

 SEC Comment

4.
The definition of production costs in Rule 4-10(a)(20) of Regulation S-X is almost identical to the definition of production costs in FASB ASC 932-360-25-15, and that the limitation on capitalized costs in Rule
4-10(c)(4)(i)(A) of Regulation S-X and required disclosures applicable to the standardized measure in FASB ASC 932-235-50-31(b) both refer to estimated future expenditures “to be incurred in developing and producing the proved oil and gas
reserves.” Please tell us your authoritative basis for including certain general and administrative costs determined to be operating costs in the results of operations of oil- and gas-producing activities and in the standardized measure of
discounted future net cash flows, but not in the determination of the limitation on capitalized costs.

 3

 Ethan Horowitz

United States Securities and Exchange Commission

 February 14,
2014

 Response

We acknowledge that the definition of production costs in Rule 4-10(a)(20) of Regulation S-X is almost identical to the definition of production costs in FASB
ASC 932-360-25-15. However, as indicated in our response to comment 3, we believe production costs discussed in the results of operations disclosure in FASB ASC 932-235-50-26 is different than the definition of production costs in FASB ASC
932-360-25-15. We believe the intent of the standardized measure disclosure is to provide information about the future cash flows of the oil and gas producing business. Accordingly, we have historically deducted estimated future production support
costs as a component of future production costs in determining our standardized measure so that we are treating production support costs consistently in our results of operations and standardized measure disclosures. Although disclosures of the
components of standardized measure are less transparent that results of operations disclosures, based upon review of peer registrants’ public filings and discussions with several peers, we believe there are several peer companies that also
deduct a component of general and administrative expense (i.e., production support costs) in calculating standardized measure. We also acknowledge there are peer companies that do not appear to deduct a component of general and administrative
expense (i.e., production support costs) from either the results of operations or standardized measure disclosures.

 * * * * * * *

In connection with the above response to the staff’s comment, Devon acknowledges that:

•

Devon is responsible for the adequacy and accuracy of the disclosure in the filing;

•

Staff comments or changes to disclosure in response to staff comments do not foreclose the Commission from taking any action with respect to the filing; and

•

Devon may not assert staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States.

Sincerely,

/s/ Jeremy D. Humphers

Jeremy D. Humphers

Vice President, Accounting

 4

February 7 , 2014

Via Email
Thomas L. Mitchell
Chief Financial O fficer
Devon Energy Corporat ion
333 West Sheridan Avenue
Oklahoma City, OK 73102

Re: Devon Energy Corporation
 Form 10-K for Fiscal Year Ended
December 31, 2012
Filed February 21, 2013
Supplemental Response dated January 28, 2014
File No. 001 -32318

Dear Mr. Mitchell :

We have reviewed your response letter and have the following comments.   In some of our
comments, we may ask you to provide us with information so we may better understand your
disclosure.

Please respond to this letter within ten business days by amending your filing, by
providing the requested information, or by advising us when you will provide the r equested
response.   If you do not believe our comments apply to your facts and circumstances or do not
believe an amendment is appropriate, please tell us why in your response.

Form 10 -K for Fiscal Year Ended December 31, 2012

Notes to Consol idated Financial Statements

Note 22 – Supplemental Information on Oil and Gas Operations (Unaudited), page 87

Standardized Measure, page 97

1. Your response to comment 5 in our letter dated January  17, 2014 states that certain
general and administrative costs which are required to operate your upstream oil and gas
business are not included in the calculation of the limitation on capitalized costs as these
costs are not well -level expenditures , but h ave been included as future costs in calculating
the standardized measure of discounted future net cash flows .  Your response refers to the
definition of the term “production costs” per Rule 4 -10(a)(20) of Regulation S -X.  Please
tell us whether these  types of general and administrative costs  are considered to be

Thomas L. Mitchell
Devon Energy Corporation
February 7, 2014
Page 2

 operating costs of support equipment and facilities or other costs of operating and
maintaining wells and related equipment and facilities.

2. In connection with your response to the preceding commen t, please tell us if any general
and administrative  costs related to oil and gas production are deducted in calculating the
limitation on capitalized costs  and describe the process through which  you determine
whether these costs are property -level expendit ures.  In addition, y our response should
explain whether these types of costs are deemed to be essential to operating  and
maint aining your wells and rela ted equipment and facilities.  As part of your response,
please also describe the types of costs which are deemed to be well -level expenditures.

3. Your response to comment 5 in our letter dated January 17, 2014 references FASB ASC
932-235-50-26, which requires the disclosure of results of operations for oil - and gas -
producing activities and indicates that “some expenses incurred at an entity’s central
administrative office may not be general corporate expenses, but rather may be operating
expenses of oil - and gas -producing activities and should be reported as such.”  The first
sentence of that section defin es results of operations for oil -and gas -producing activities
as revenues less production (lifting) costs and goes on to specify other costs that should
be included.  If general and administrative costs are determined to be operating costs of
oil- and gas -producing activities, please tell us how these costs would be classified within
that definition other than as production (lifting) costs.

4. The definition of production costs in Rule 4 -10(a)(20) of Regulation S -X is almost
identical to the definition of pro duction costs in FASB ASC 932 -360-25-15, and that the
limitation on capitalized costs in Rule 4 -10(c)(4)(i)(A) of Regulation S -X and required
disclosures applicable to the standardized measure in FASB ASC 932 -235-50-31(b) both
refer to estimated future exp enditures “to be incurred in developing and producing the
proved oil and gas reserves.”  Please tell us your authoritative basis for including certain
general and administrative costs determined to be operating costs in the results of
operations of oil - and gas -producing activities and in the standardized measure of
discounted future net cash flows, but not in the determination of the limitation on
capitalized costs.

You may contact Svitlana Sweat  at (202) 551 -3326  or me at (202) 551 -3311  if you have
quest ions regarding comments on the financial statements and related matters.

Sincerely,

 /s/ Ethan Horowitz

Ethan Horowitz
Branch Chief

CORRESP
1
filename1.htm

CORRESPONDENCE

 Devon Energy Corporation

 333 West Sheridan
Avenue

 Oklahoma City, OK 73102

 405.552.8183

jeremy.humphers@dvn.com

 January 28, 2014

Via EDGAR

 Attention: Ms. Svitlana
Sweat, Division of Corporation Finance

 Ethan Horowitz

Branch Chief

 United States Securities and Exchange Commission

 100 F. Street, N.E.

 Washington, D.C. 20549

Re:
Devon Energy Corporation

 Form 10-K for the Fiscal Year Ended December 31, 2012

 Filed February 21, 2013

Response Letter Date January 17, 2014

File No. 001-32318

 Dear
Mr. Horowitz:

 This letter responds to the staff’s comment letter dated January 17, 2014, regarding Devon Energy Corporation’s Form
10-K for the year ended December 31, 2012, filed February 21, 2013 (File No. 001-32318). Devon’s responses to the staff’s comments are set forth below:

Form 10-K for Fiscal Year Ended December 31, 2012

Management’s Discussion and Analysis of Financial Condition and Results of Operations

Overview of 2012 Results, page 23

 SEC Comment

1.
We note your response to comment 4 in our letter dated December 11, 2013. Please revise to present a reserve replacement measure based on all causal factors resulting in changes to your proved reserves alongside
the reserve replacement measure currently presented on page 24 of your Form 10-K.

 Response

In our future filings, we will present a reserve replacement measure based on all causal factors alongside any reserve replacement measure not based on all
causal factors and clearly explain significant differences between the two measures.

 Non-GAAP Measures, page 43

SEC Comment

2.
 Your response to comment 6 in our letter dated December 11, 2013 does not appear to state whether you consider the non-GAAP measure
“Adjusted Cash Flow” to be a performance

 Ethan Horowitz

United States Securities and Exchange Commission

 January 28,
2014

measure or a liquidity measure. If you consider “Adjusted Cash Flow” to be a performance measure, please tell us why earnings from continuing operations is not deemed to be the most
directly comparable GAAP-basis measure. If you consider “Adjusted Cash Flow” to be a liquidity measure, please revise to comply with the guidance per Item 10(e)(1)(ii)(A) of Regulation S-K.

Response

 We believe “adjusted cash flow” is
both a performance measure and a liquidity measure for our industry. Because this measure is largely used as a performance measure for our industry, we prepared our reconciliation of adjusted cash flow with the view that this non-GAAP measure is a
performance measure. Consequently, we believe the guidance in Item 10(e)(1)(ii)(A) does not apply to our reconciliation of adjusted cash flow. However, we acknowledge that the name “adjusted cash flow” might be more obviously viewed
as a liquidity measure because the name includes the words “cash flow.” This is particularly true for our reconciliation because we reconciled adjusted cash flow to cash flow from operating activities. We used this reconciliation method
because we understand it is the same reconciliation method used by our investors and analysts.

 To avoid confusion in our future filings, we will
reconcile any non-GAAP measures we deem to be performance measures to net earnings. Additionally, specific to adjusted cash flow, we will revise the name of this non-GAAP performance measure to exclude the words “cash flow.” Furthermore,
we will ensure any non-GAAP liquidity measures we disclose do not include adjustments that required, or will require, cash settlement as prescribed in Item 10(e)(1)(ii)(A).

SEC Comment

3.
Based on your response to comment 7 in our letter dated December 11, 2013, it appears that the adjustment captioned “income tax accrual adjustment” could be revised to better indicate its nature.
Please revise to provide a more descriptive caption for this line item.

 Response

In our future filings, we will ensure the “income tax accrual adjustment” and any other adjustment captions are descriptive of the nature of the line
item. When appropriate, we will also provide additional disclosure explaining the nature of the adjustment(s) included in the line items.

 Notes to
Consolidated Financial Statements

 Note 6 – Income Taxes, page 66

SEC Comment

4.
We note your response to comments 9 and 10 in our letter dated December 11, 2013. Please revise your disclosure of critical accounting estimates regarding income taxes to specifically address unremitted foreign
earnings deemed to be indefinitely reinvested. Your revised disclosure should include a discussion of the uncertainties associated with unrecognized deferred tax liabilities related to foreign earnings that are deemed to be indefinitely reinvested
and a description of the types of events that would enable management to calculate the amount of the unrecognized deferred tax liability. For additional guidance, refer to section V of SEC Release No. 33-8350.

 Ethan Horowitz

United States Securities and Exchange Commission

 January 28,
2014

 Response

In our future filings, we will include expanded discussion of the income tax assumptions, estimates and uncertainties pertaining to unremitted foreign earnings
deemed to be indefinitely reinvested.

 Note 22 – Supplemental Information on Oil and Gas Operations (Unaudited), page 87

Standardized Measure, page 97

 SEC Comment

5.
Your response to comment 12 in our letter dated December 11, 2013 indicates that certain production costs are excluded from the present value of estimated future net revenues used to compute the full cost
ceiling because they are not property-level expenditures. Please provide us with additional information describing the nature of these costs and explain your application of Rule 4-10(c)(4)(i)(A) of Regulation S-X regarding the treatment of estimated
future expenditures to be incurred in developing and producing proved reserves in calculating the limitation on capitalized costs. As part of your response, please tell us more about your determination that these costs are deemed to be directly
identifiable to production activities only for purposes of calculating the standardized measure of discounted future net cash flows.

Response

 The general and administrative costs that we
consider to be oil and gas production costs largely consist of labor, materials and supplies for oil and gas production monitoring and support activities, including information technology, transaction accounting and certain other administrative
support functions. Our general and administrative oil and gas production costs also include labor for oil and gas production supervision activities.

 For
our results of operations disclosure, we consider these costs to be production costs because they are required to operate our upstream oil and gas business—specifically, to produce our oil and gas proved reserves. Therefore, even though the
vast majority of these costs are incurred at our central administrative offices, we include these costs in our results of operations disclosure in accordance with Codification 932-235-50-26. Furthermore, we respectfully submit to the Staff that the
spirit of Codification 932-235-50-26 seems to indicate oil and gas production costs would include “expenses incurred at an entity’s central administrative office.” In other words, it appears results of operations production costs
would include costs classified as general and administrative expenses in the income statement.

 To be consistent in our treatment of these general and
administrative production costs, we also deduct estimated future general and administrative oil and gas production costs to calculate our standardized measure of future net cash flows. We disclose this treatment on page 98 of our Form 10-K. While we
are certain other companies treat general and administrative production costs similarly to Devon in their results of operations and standardized measure disclosures, we also believe there is diversity in practice for the inclusion of these costs in
the results of operations and standardized measure disclosures.

 However, we do not believe there is any diversity of practice regarding the treatment of
these costs to calculate the limitation on capitalized costs. We believe full cost companies, including Devon, universally exclude these non-property-level expenditures from their calculation of the limitation on capitalized costs. Full cost
companies, including Devon, have universally interpreted the limitation on capitalized costs to be an impairment test applied to an asset or asset group. As such, we only include

 Ethan Horowitz

United States Securities and Exchange Commission

 January 28,
2014

“well-level” expenditures as production costs in the calculation of the present value of estimated future net revenues. Our use of only “well-level” expenditures as production
costs in the determination of the limitation on capitalized costs is also consistent with the definition of production costs provided in Rule 4-10(a)(20).

The term “production costs” is explicitly defined and generally described differently in Rule 4-10 and Topic 932. In Rule 4-10(c)(4)(i)(A)
(Limitation on Capitalized Costs), production costs are generally described as “expenditures...to be incurred in...producing the proved reserves.” In Codification 932-235-50-26 (Results of Operations), “some expenses incurred at an
entity’s central administrative office...may be operating expenses of oil- and gas-producing activities” (i.e., production costs). In Codification 932-235-50-31(b) (Standardized Measure), future production costs “shall be computed by
estimating the expenditures to be incurred in...producing the proved oil and gas reserves.” Admittedly, the production cost descriptions provided in Rule 4-10(c)(4)(i)(A) and Codification 932-235-50-31(b) are almost identical. Finally,
production costs are specifically defined in Rule 4-10(a)(20) as “costs incurred to operate and maintain wells and related equipment and facilities...”

Our interpretation of these varying definitions and descriptions of production costs is that for results of operations and standardized measure disclosures,
expenditures to operate and maintain wells are production costs, and production costs also include non-well-level costs required to produce the proved reserves, some of which may be incurred at a central administrative office. We further interpret
that production costs consisting only of well- or property-level expenditures as required in Rule 4-10(a)(20) should be used in the calculation of the limitation on capitalized costs because it is an asset-based impairment test.

* * * * * * *

 In connection with the above
response to the staff’s comment, Devon acknowledges that:

•

Devon is responsible for the adequacy and accuracy of the disclosure in the filing;

•

Staff comments or changes to disclosure in response to staff comments do not foreclose the Commission from taking any action with respect to the filing; and

•

Devon may not assert staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States.

Sincerely,

/s/ Jeremy D. Humphers

Jeremy D. Humphers

Vice President, Accounting

January 17, 2014

Jeffrey A. Agosta
Chief Financial Officer
Devon Energy Corporat ion
333 West Sheridan Avenue
Oklahoma City, OK 73102

Re: Devon Energy Corporation
 Form 10-K for Fiscal  Year Ended
 December 31, 2012
Filed February 21, 2013
Response letter dated December  26, 2013
File No. 001 -32318

Dear Mr. Agosta :

We have reviewed your response letter and have the following comments.   In some of our
comments, we may ask you to provide us with information so we may better understand your
disclosure.

Please respond to this letter within ten business days by amending your filing, by
providing the requested information, or by advising us when you will provide the requested
response.   If you do not believe our comments apply  to your facts and circumstances or do not
believe an amendment is appropriate, please tell us why in your response.

Form 10 -K for Fiscal Year Ended December 31, 2012

Management’s Discussion and Analysis of Financial Condition and Results of Operations

Overview of 2012 Results, page 23

1. We note your response to comment 4 in our letter dated December 11, 2013.  Please
revise to present a reserve replacement measure based on all causal factors resulting in
changes to your proved reserves along side the reserve replacement measure currently
presented on page 24 of your Form 10 -K.

Non-GAAP Measures, page 43

2. Your response to comment 6 in our letter dated December 11, 2013  does not appear to
state whether you consider the non -GAAP measure “Adjuste d Cash Flow” to be a
performance measure or a liquidity measure.  If you consider “Adjusted Cash Flow”  to be
a performance measure, please tell us why earnings from continuing operations is not

Jeffrey A. Agosta
Devon Energy Corporation
January 1 7, 2014
Page 2

 deemed to be the most directly comparable GAAP -basis measure.   If you consider
“Adjusted Cash Flow”  to be a liquidity measure, please revise to comply with the
guidance per Item 10(e)(1)(ii)(A)  of Regulation S -K.

3. Based on  your response to comment 7 in our  letter dated December 11, 2013, it appears
that the adjustment captioned “income tax accrual adjustment” could be revised to better
indicate its nature.  Please revise to provide a more descriptive caption for this line item.

Notes to Consolidated Financ ial Statements

Note 6 – Income Taxes, page 66

4. We note your response to comments 9 and 10 in our letter dated December 11, 2013.
Please revise your disclosure of critical accounting estimates regarding income taxes to
specifically address unremitted foreign earnings deemed to be indefinitely reinvested.
Your revised disclosure should include a discussion of the uncertainties associated wi th
unrecognized deferred tax liabilities related to foreign earnings that are deemed to be
indefinitely reinvested and a description of the types of events that would enable
management to calculate the amount of the unrecognized deferred tax liability.  Fo r
additional guidance, refer to section V of SEC Release No. 33 -8350.

Note 22 – Supplemental Information on Oil and Gas Operations (Unaudited), page 87

Standardized Measure, page 97

5. Your response to comment 12 in our letter dated December 11, 2013 indic ates that
certain production costs are excluded from the present value of estimated future net
revenues used to compute the full cost ceiling bec ause they are not property -level
expenditures.  Please provide us with additional information describing the na ture of
these costs and explain your application of Rule 4 -10(c)(4)(i)(A) of Regulation S -X
regarding the treatment of estimated future expenditures to be incurred in developing and
producing proved reserves in calculating the limitation on capitalized costs.   As part of
your response, please tell us more about your determination that these costs are deemed
to be directly identifiable to production activities  only for purposes of calculating the
standardized measure of discounted future net cash flows .

You m ay contact Svitlana Sweat  at (202) 551 -3326  or me at (202) 551 -3311  if you have
questions regarding comments on the financial statements and related matters.

Sincerely,

 /s/ Ethan Horowitz

Ethan Horowitz
Branch Chief

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Devon Energy Corporation

405 552 4577 phone

333 West Sheridan Avenue

jeff.agosta@dvn.com

Oklahoma City, OK 73102

 December 26, 2013

Via EDGAR

 Attention: Ms. Svitlana
Sweat, Division of Corporation Finance

 Ethan Horowitz

Branch Chief

 United States Securities and Exchange Commission

 100 F. Street, N.E.

 Washington, D.C. 20549

Re:
Devon Energy Corporation

 Form 10-K for the Fiscal Year Ended December 31, 2012

 Filed February 21, 2013

Response Letter Date December 12, 2013

File No. 001-32318

 Dear
Mr. Horowitz:

 This letter responds to the staff’s comment letter dated December 11, 2013, regarding Devon Energy Corporation’s Form
10-K for the year ended December 31, 2012, filed February 21, 2013 (File No. 001-32318). Devon’s responses to the staff’s comments are set forth below:

Form 10-K for Fiscal Year Ended December 31, 2012

Items 1 and 2. Business and Properties

Acreage Statistics, page 11

 SEC Comment

1.
We note that approximately 3.8 billion [sic] [recte million] net acres (or approximately 27% of your total net acreage) is scheduled to expire by December 31, 2015. Please provide expanded disclosure explaining
what actions are planned regarding expiring acreage. With your response, please tell us whether delay rentals are available for expiring undeveloped acreage and whether the related fees are material. In addition, please disclose the quantities of
proved undeveloped reserves attributable to the expiring acreage and describe the progress you have made toward conversion.

 Response

 As disclosed on page 11 of our filing, 3.8 million of our net undeveloped acres were scheduled to expire by December 31, 2015. Delay rentals
are available for approximately 30% of our acreage that was scheduled to expire by December 31, 2015. Delay rental costs are not material, generally representing less than 1% of our annual lease operating expenses. Approximately 5 MMBoe, or
less than 1%, of our proved undeveloped reserves was attributable to this expiring acreage as of December 31, 2012.

 Ethan Horowitz

United States Securities and Exchange Commission

 December 26,
2013

 We allowed approximately 50% of the 2013 expiring acreage to expire. However, we had no proved undeveloped
reserves attributable to the expired acreage. For the remaining acreage scheduled to expire in 2013, we have performed operational or administrative actions to continue the lease terms. These actions included the establishment of production and
conversion of approximately 2 MMBoe of the 5 MMBoe proved undeveloped reserves. Development of the remaining 3 MMBoe of proved undeveloped reserves is planned prior to the associated lease expirations in 2014 and 2015.

In our future filings, we will include expanded disclosure explaining what operational or administrative actions are planned regarding our expiring
undeveloped acreage, as well as the related proved undeveloped reserves associated with the expiring acreage.

 Management’s Discussion and
Analysis of Financial Condition and Results of Operations

 Overview of 2012 Results, page 23

SEC Comment

2.
We note you present “Operating Margin per BOE” as part of the tabular disclosure on page 23 of your filing. It appears that this is a non-GAAP measure. However, it does not appear that a reconciliation to
the most directly comparable GAAP-basis measure has been presented in your filing as required by Item 10(e)(1)(i)(B) of Regulation S-K. Please revise this disclosure accordingly.

Response

 In Note 2 to the tabular disclosure on page 23
of our filing, we provide an explanation of the calculation of “Operating margin per Boe.” In preparing our disclosure, we viewed this explanation as a “clearly understandable method” of reconciliation as allowed by
Item 10(e)(1)(i)(B) of Regulation S-K. In our future filings, we will provide a quantitative schedule of reconciliation to the most directly comparable GAAP-basis measure.

SEC Comment

3.
The title of the non-GAAP measure “Operating Margin per BOE” may be considered confusingly similar to titles or descriptions used for GAAP-basis financial measures. Please revise. Refer to
Item 10(e)(1)(ii)(E) of Regulation S-K.

 Response

In our future filings, we will replace “Operating margin per Boe” with “Adjusted operating income per Boe.”

SEC Comment

4.
We note the disclosure on page 24 of your filing stating that you replaced 152% of your production from extensions, discoveries, and revisions other than price. In addition to the disclosure provided, please tell us
how you considered presenting reserve replacement information based on all causal factors resulting in changes to your proved reserves.

 Ethan Horowitz

United States Securities and Exchange Commission

 December 26,
2013

 Response

We have presented reserve replacement information based on all causal factors in our reserves-based disclosures on pages 91 to 97 of our filing, including the
explanations of changes to our proved reserves on pages 96 and 97.

 We provide the reserve replacement measure on page 24 of our filing to communicate the
measure our investors and analysts use to evaluate our performance. Investors and analysts use reserve replacement from extensions, discoveries, and revisions other than price to measure and evaluate a company’s ability to find, develop, and
produce oil, natural gas, and NGLs from ongoing operations. As a result, investors and analysts typically exclude proved reserve revisions due to price, as well as the purchase and sale of reserves, in their analysis.

Non-GAAP Measures, page 43

 SEC Comment

5.
We note your disclosure stating that the non-GAAP measure “Adjusted Earnings” represents net earnings excluding certain non-cash or non-recurring items. However, it does not appear that the characterization
of certain line items as non-recurring is appropriate. For example, we note the adjustments for restructuring costs in each of the three fiscal years ended December 31, 2012 and the adjustments for U.S. income taxes on foreign earnings in each
of the two fiscal years ended December 31, 2011. Please revise your disclosure to comply with Item 10(e)(1)(ii)(B) of Regulation S-K. For additional guidance, refer to Question 102.03 of the Compliance & Disclosure Interpretation
regarding Non-GAAP Financial Measures.

 Response

The adjustments described as “Restructuring costs” pertain to two distinct and non-recurring events: 1) the divestiture program of our offshore
International and Gulf of Mexico operations that began in the fourth quarter of 2009 and finished in the second quarter of 2011 and 2) the consolidation of all our U.S. personnel into Oklahoma City that began in the fourth quarter of 2012.
Therefore, we do not view the charges related to these two separate restructuring programs as “recurring.” Additionally, the adjustments for U.S. income taxes on foreign earnings are non-cash items. Nevertheless, in our future filings, we
will enhance our disclosure to better describe adjustments to our GAAP measures that might appear to be recurring.

 SEC Comment

6.
We note that you have presented “Adjusted Cash Flow” in your filing which appears to be a non-GAAP liquidity measure. Please tell us how you considered the guidance per Item 10(e)(1)(ii)(A) of
Regulation S-K which prohibits the exclusion of charges or liabilities that required or will require cash settlement from non-GAAP liquidity measures. For example, it appears the adjustment for restructuring charges relates to an item requiring cash
settlement.

 Response

 We recognize
that operating cash flow is a liquidity measure. However, operating cash flow is also considered a performance measure in our industry, and we, along with our investors and analysts, place significant emphasis on operating cash flow as a performance
measure. This emphasis on operating cash flow as a performance measure is based on the fact that there are two different, yet accepted and

 Ethan Horowitz

United States Securities and Exchange Commission

 December 26,
2013

used methods of accounting for oil and gas activities. The full cost and successful efforts methods of accounting typically yield very different earnings results in any particular reporting
period. Therefore, it is difficult to compare the performance of companies using these different methods of accounting. However, operating cash flow is generally the same under both accounting methods. Therefore, when using operating cash flow as
the performance measure, management, investors and analysts can more easily compare the financial performance of companies in our industry regardless of the accounting method used. For these reasons, we recognize operating cash flow as a performance
measure as much as it is a liquidity measure for our industry.

 Furthermore, as indicated in our disclosure on page 43 of our filing, one of the primary
uses of our non-GAAP measures, including Adjusted Cash Flow, is to facilitate securities analysts’ evaluation of our financial performance against their expectations. When we make adjustments to operating cash flow, including adjustments for
restructuring costs as noted in your comment, we view them as adjustments to a performance measure rather than adjustments to a liquidity measure.

 SEC
Comment

7.
We note the non-GAAP measures “Adjusted Earnings” and “Adjusted Cash Flow” both include an adjustment captioned “income tax accrual adjustment.” Please provide us with a description of
the nature of this line item.

 Response

The earnings adjustments largely relate to changes in our unrecognized tax benefits, as well as “return-to-accrual” adjustments that we made in the
third quarter of each year in conjunction with the filing of our U.S. income tax return. The return-to-accrual adjustments are also the primary contributor to the cash flow adjustments. As mentioned in our disclosure on page 43 of our filing, we
adjust for items to facilitate securities analysts’ evaluation of our performance against their expectations, including these income tax accrual adjustments.

The return-to-accrual adjustments largely relate to our determination of the amount of intangible drilling costs that we will capitalize or expense on our
U.S. income tax return. When we make our annual provision for current and deferred income tax expense in the fourth quarter of each year, we must determine the amount of intangible drilling costs that we will capitalize and the amount we will
expense for income tax purposes. While we use all available information and known facts at the time of the provision to make this determination, the tax provision pertaining to the treatment of intangible drilling costs is still an estimate at
year-end that will be finalized when we file the U.S. tax return. Over the past three years, as we prepared and finalized our tax return, we determined that we could and should expense larger amounts of intangible drilling costs pertaining to the
prior tax year. This resulted in a return-to-accrual adjustment that increased deferred income tax expense and decreased current income tax expense. Overall, the adjustment had little to no effect on earnings but did increase “Cash flow before
balance sheet changes.”

 SEC Comment

8.
With a view toward future disclosure, please provide expanded disclosure explaining the reasons why you believe each of the non-GAAP financial measure presented in your filing provides useful information to investors
regarding your financial condition and results of operations and identifying the additional purposes for which you use these non-GAAP financial measures. Refer to Items 10(e)(1)(i)(C) and 10(e)(1)(i)(D) of Regulation S-K.

 Ethan Horowitz

United States Securities and Exchange Commission

 December 26,
2013

 Response

Besides helping investors and analysts evaluate our performance, we use the non-GAAP measures to assess the performance of our business and to make resource
allocation and other operating decisions. We acknowledge the Staff’s comment and will provide expanded disclosure in our future filings regarding the usefulness of our non-GAAP measures.

Notes to Consolidated Financial Statements

Note 6 — Income Taxes, page 66

 SEC Comment

9.
We note your disclosure stating that approximately $5.5 billion was deemed to be indefinitely reinvested into the development and growth of your Canadian business as of December 31, 2012. Your disclosure also
states that it is not practical to estimate the U.S. income taxes and foreign withholding taxes if such earnings were to be repatriated. Please provide us with a detailed explanation supporting this assertion considering that you disclosed your
expectation to repatriate approximately $2.0 billion to the United States in the following quarter (i.e., as part of your Form 10-Q for the quarter ended March 31, 2013). Refer to FASB ASC 740-30-50-2.

Response

 Our disclosure in the last paragraph on page 67
of our filing states that approximately $5.5 billion of our unremitted foreign earnings was deemed to be indefinitely reinvested into the development and growth of our Canadian business. That same paragraph also indicates that we had $2.5 billion of
unremitted foreign earnings that was not deemed to be indefinitely reinvested ($8.0 billion total unremitted foreign earnings). As of December 31, 2012 and as presented in the table on page 67 of our filing, we had accrued a $936 million
deferred tax liability associated with the $2.5 billion of unremitted foreign earnings. Our assertion to repatriate $2 billion to the United States in the following quarter related to the $2.5 billion of foreign earnings that we deemed not to be
indefinitely reinvested and for which we had recognized a $936 million deferred tax liability as of December 31, 2012.

 With regards to the $5.5
billion of earnings deemed indefinitely reinvested, calculating a hypothetical tax on these accumulated earnings is much different from the calculation of the deferred tax liability on our earnings deemed not permanently reinvested. Unlike the tax
calculation that resulted in the $936 million deferred tax liability on our foreign earnings deemed not to be permanently reinvested, a tax calculation on the permanently reinvested earnings would require the following additional activities:

•

Separate analysis of a different chain of foreign entities;

•

Choosing a foreign tax rate on a future deemed sale and remittance of property that could vary from 12.5% to 25%, depending on the circumstances;

•

Separate analysis of foreign net operating losses, taxable gain acceleration rules in Canada, and how these may apply at the time of a remittance, depending on the circumstances;

•

Determining the nature of a yet-to-be-determined future remittance and calculation of associated withholding taxes, which would vary significantly depending on the circumstances at the deemed time of remittance; and

•

Further analysis of a variety of other inputs such as earnings, profits, the U.S./Canada tax treaty provisions and the related foreign taxes paid over more than 15 years for legal entities that are separate and apart
from the legal entities analyzed in determining the deferred tax liability on our foreign earnings that have been deemed not to be indefinitely reinvested.

 Ethan Horowitz

United States Securities and Exchange Commission

 December 26,
2013

 Because of the administrative burden required to perform these additional activities, we believe it is
impracticable to calculate a hypothetical tax on this separate and more complicated chain of companies, which is allowed by FASB ASC 740-30-50-2.

 SEC
Comment

10.
We note the disclosure in your Form 10-Q for the quarter ended September 30, 2013 stating that approximately $4.8 billion of unremitted foreign earnings was deemed to be indefinitely reinvested into your
Canadian business. Please tell us how the repatriation in the fiscal quarter ended June 30, 2013 impacted your abili

December 1 1, 2013

Via Email
Jeffrey A. Agosta
Chief Financial Officer
Devon Energy Corporat ion
333 West Sheridan Avenue
Oklahoma City, OK 73102

Re: Devon Energy Corporation
 Form 10-K for Fiscal Year Ended
 December 31, 2012
Filed February 21, 2013
File No. 001 -32318

Dear Mr. Agosta :

We have reviewed your filing an d have the following comments.  In some of our
comments, we may ask you to provide us with information so we may better understand your
disclosure.

Please respond to this letter within ten business days by amending your filing, by
providing the requested information, or by advising us when you will provide the requested
response.   If you do not believe our comments apply t o your facts and circumstances or do not
believe an amendment is appropriate, please tell us why in your response.

After reviewing any amendment to your filing and the information you provide in
response to these  comments, we may have  additional comment s.

Form 10 -K for Fiscal Year Ended December 31, 2012

Items 1 and 2. Business and Properties

Acreage Statistics, page 11

1. We note that approximately 3.8 billion net acres (or approximately 27% of your total net
acreage) is scheduled to expir e by December  31, 2015.  Please provide expanded
disclosure explaining what actions are planned regarding  expiring acreage.  With your
response, please tell us whether delay rentals are available for expiring undeveloped
acreage and whether the related fee s are material.  In addition, please disclose the
quantities of proved undeveloped reserves attributable to the expiring acreage and
describe the progress you have made toward conversion.

Jeffrey A. Agosta
Devon Energy Corporation
December 1 1, 2013
Page 2

 Management’s Discussion and Analysis of Financial Condition and Re sults of Operations

Overview of 2012 Results, page 23

2. We note you present “Operating Margin per BOE” as part of the tabular disclosure on
page  23 of your filing.   It appears that this is a non -GAAP measure.  However, it does not
appear that a reconciliati on to the most directly comparable GAAP -basis measure has
been presented in your filing as required by Item 10(e)(1)(i)(B)  of Regulation S-
K.  Please rev ise this disclosure accordingly.

3. The title of the non -GAAP measure “Operating Margin per BOE” may be considered
confusingly similar to titles or descriptions used for GAAP -basis financial measures.
Please revise.  Refer to Item 10(e)(1)(ii)(E)  of Regulation S -K.

4. We note the disclosure on page 24 of your filing stating that you replaced 152% of your
production from extensions, discoveries, and revisions other than price.  In addition to the
disclosure provided, please tell us how you considered presenting reserve replacement
information based on all causal factors resulting in changes to your pro ved reserves.

Non-GAAP Measures, page 43

5. We note your disclosure stating that the non -GAAP measure “Adjusted Earnings”
represents net earnings excluding certain non -cash or non -recurring items.  However, it
does not appear that the characterization of ce rtain line items as non -recurring is
appropriate.  For example, we note the adjustments for restructuring costs in each of the
three fiscal years ended December 31, 2012 and the adjustments for U.S. income taxes on
foreign earnings in each of the two fisca l years ended December 31, 2011.  Please revise
your disclosure to comply with Item 10(e)(1)(ii)(B)  of Regulation S -K.  For additional
guidance, refer to Question 102.03 of the Compliance & Disclosure Interpretation
regarding Non -GAAP Financial Measures.

6. We note that you have presented “Adjusted Cash Flow” in your filing which appears to
be a non -GAAP liquidity measure.  Please tell us how you considered the guidance per
Item 10(e)(1)(ii)(A)  of Regulation S -K which prohibits the exclusion of charges or
liabilities that required or will require cash settlement from non -GAAP liquidity
measures.  For example, it appears the adjustment for restructuring charges relates to an
item requiring cash settlement.

7. We note the non -GAAP measures “Adjusted Earnings” and “Adjusted Cash Flow” both
include an adjustment captioned “income tax accrual adjustment.”  Please provide us
with a description of the nature of this line item.

8. With a view toward future disclosure, please provide expanded disclosure explaining the
reaso ns why you believe each of the non -GAAP financial measure presented in your
filing provide s useful information to investors regarding your financial condition and

Jeffrey A. Agosta
Devon Energy Corporation
December 1 1, 2013
Page 3

 results of operations and identifying the additional purposes for which you use these non -
GAA P financial measures.  Refer to Items 10(e)(1)(i)(C) and 10(e)(1)(i)(D)  of Regulation
S-K.

Notes to Consolidated Financial Statements

Note 6 – Income Taxes, page 66

9. We note your disclosure stating that approximately $5.5 billion was deemed to be
indefin itely reinvested into the development and growth of your Canadian business as of
December 31, 2012.  Your disclosure also states that it is not practical to estimate the
U.S. income taxes and foreign withholding taxes if such earnings were to be repatriate d.
Please provide us with a detailed explanation supporting this assertion considering that
you disclosed your expectation to repatriate approximately $2.0 billion to the United
States in the following quarter (i.e., as part of your Form 10 -Q for the quar ter ended
March 31, 2013).  Refer to FASB ASC 740 -30-50-2.

10. We note the disclosure in your Form 10 -Q for the quarter ended September 30, 2013
stating that approximately $4.8 billion of unremitted foreign earnings was  deemed to be
indefinitely reinvested in to your Canadian business.  Please tell us how the repatriation in
the fiscal quarter ended June 30, 2013 impacted your ability to estimate the amount of the
unrecognized deferred tax liability related to such earnings.  With your response, please
also add ress the deferred tax liability recognized for unremitted foreign earnings not
deemed to be indefinitely reinvested.

Note 22 – Supplemental Information on Oil and Gas Operations (Unaudited), page 87

Capitalized Costs, page 89

11. Please expand your disclosure regarding oil and gas properties not subject to amortization
to provide a description of the current status of significant properties or projects,
including the anticipated timing of the inclusion of the costs in the amortizat ion
computation.  Refer to Rule 4 -10(c)(7)(ii) of Regulation S -X.

Standardized Measure, page 97

12. Disclosure on page 97 of your filing indicates that your standardized measure of
discounted future net cash flows as of December  31, 2012 was approximately $ 13.2
million. This amount appears to be less than the net carrying value of your oil and gas
properties, as reported on your consolidated balance sheet as of December  31, 2012.
Please provide us with a summary, by cost center, of your ceiling test calcula tions as of
December  31, 2012.  Where applicable, please reconcile amounts used in the calculation
to your balance sheet or standardized measure, as appropriate.

Jeffrey A. Agosta
Devon Energy Corporation
December 1 1, 2013
Page 4

 13. It appears that you have presented non -GAAP disclosures as part of this footnote to your
financial statements.  Please revise to comply with the guidance per Item 10(e)(5) of
Regulation S -K which states that non -GAAP measures should be presented outside of the
financial statements.

We urge all persons who are responsible for the accuracy and adequacy of the disclosure
in the filing to be certain that the filing includes the information the Securities Exchange Act of
1934 and all applicable Exchange Act rules require.   Since the company and its management are
in possession of all facts relating  to a company’s disclosure, they are responsible for the accuracy
and adequacy of the disclosures they have made.

 In responding to our comments, please provide  a written statement from the company
acknowledging that:

 the company is responsible for the  adequacy and accuracy of the disclosure in the filing;

 staff comments or changes to disclosure in response to staff comments do not foreclose
the Commission from taking any action with respect to the filing; and

 the company may not assert staff comments  as a defense in any proceeding initiated by
the Commission or any person under the federal securities laws of the United States.

You may contact Svitlana Sweat  at (202) 551 -3326  or me at (202) 551 -3311  if you have
questions regarding comments on the fina ncial statements and related matters.

Sincerely,

 /s/ Ethan Horowitz

Ethan Horowitz
Branch Chief

February 15, 2013

Via Email
Mr. Jeffrey A. Agosta
Chief Financial Officer
Devon Energy Corporation
333 West Sheridan Avenue
Oklahoma City, OK 73102

Re: Devon Energy Corporation
 Form 10 -K for Fiscal Year Ended
 December 31, 2011
Filed February 24, 2012
File No. 001 -32318

Dear Mr. Agosta:

We have completed our review of your filing .  We remind you that our comments or
changes to disclosure in response to our comments do not foreclose the Commission from taking
any action with respect to the company or the filing and the company may not assert staff
comments as a defense in any proceeding initiated by the Commission or any person under the
federal securities laws of the Un ited States.  We urge all persons who are responsible for the
accuracy and adequacy of the disclosure in the filing to be certain that the filing include the
information the Securities Exchange Act of 1934 and all applicable rules require.

Sincerely,

 /s/H. Roger Schwall

 H. Roger Schwall
Assistant Director

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Devon Energy Corporation

405 552 4577 phone

333 West Sheridan Avenue

jeff.agosta@dvn.com

Oklahoma City, OK 73102

 FOIA CONFIDENTIAL TREATMENT REQUESTED UNDER 17 CFR § 200.83

February 1, 2013

 Via EDGAR

 Attention: Ms. Svitlana Sweat, Division of Corporation Finance

H. Roger Schwall

 Assistant Director

United States Securities and Exchange Commission

100 F. Street, N.E.

 Washington, D.C. 20549

Re:
Devon Energy Corporation

Form 10-K for the Fiscal Year Ended December 31, 2011

Filed February 24, 2012

Response Letter Dated January 11, 2013

File No. 001-32318

 Dear
Mr. Schwall:

 On February 1, 2013, Devon responded to the staff’s comment letter dated January 23, 2013, regarding Devon
Energy Corporation’s Form 10-K for the year ended December 31, 2011, filed February 24, 2012 (File No. 001-32318). In conjunction with that response, Devon is providing the attached Schedule 1 [*]. Devon requests confidential
treatment of this Schedule 1 pursuant to 17 C.F.R. §200.83.

 Sincerely,

/s/ Jeffrey A. Agosta

 Jeffrey A. Agosta

 Executive
Vice President and Chief Financial Officer

[*]
Schedule 1 has been omitted and furnished separately to the Securities and Exchange Commission pursuant to Rule 83.

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Correspondence

Devon Energy Corporation

405 552 4577 phone

333 West Sheridan Avenue

jeff.agosta@dvn.com

Oklahoma City, OK 73102

 February 1, 2013

 Via EDGAR

 Attention: Ms. Svitlana Sweat, Division of Corporation Finance

 H. Roger Schwall

 Assistant
Director

 United States Securities and Exchange Commission

 100 F. Street, N.E.

 Washington, D.C. 20549

Re:
Devon Energy Corporation

Form 10-K for the Fiscal Year Ended December 31, 2011

Filed February 24, 2012

Response Letter Dated January 11, 2013

File No. 001-32318

 Dear
Mr. Schwall:

 This letter responds to the staff’s comment letter dated January 23, 2013, regarding Devon Energy
Corporation’s Form 10-K for the year ended December 31, 2011, filed February 24, 2012 (File No. 001-32318). Devon’s responses to the staff’s comments are set forth below:

Form 10-K for Fiscal Year Ended December 31, 2011

 Consolidated Financial Statements

 Notes to Consolidated Financial Statements

 Note 6 – Income Taxes, page 66

 SEC Comment

1.
We note your response to comment 2 in our letter dated December 13, 2012. Your response states that $4.3 billion of cash and short-term investments held by your
foreign subsidiaries as of December 31, 2011 was deemed repatriated. However, the disclosure per page 39 of your Form 10-K states that the vast majority of your cash and short-term investments consist of proceeds from your international
offshore divestitures held by certain of your foreign subsidiaries which you do not currently expect to repatriate to the United States. Please address this apparent inconsistency.

Response

 In our future filings, we
propose to eliminate any apparent inconsistency in our disclosure by not using the description “the vast majority” as it relates to our cash and short-term investments held by our foreign subsidiaries. To further clarify our disclosure in
future filings, we propose to make other revisions to the comparable disclosures we made in our 2011 Form 10-K in the last paragraphs on pages 39 and 67 as follows:

 H. Roger Schwall

 United States Securities and Exchange Commission

  Page
 2

 February 1, 2013

 Page 39:

At the end of 2011, we held approximately $7.1 billion of cash and short-term investments. Included in this total was
$6.9 billion of cash and short-term investments held by our foreign subsidiaries. We do not currently expect to repatriate the $6.9 billion to the U.S. This expectation is based on planned investments to develop and grow our Canadian business, our
current forecasts for both our U.S. and Canadian operations, currently favorable borrowing conditions in the U.S., and existing U.S. income tax laws pertaining to repatriations of foreign earnings. Therefore, with limited cash and short-term
investments in the U.S., we expect to continue funding our U.S. business with a combination of our U.S.-based operating cash flow and borrowings. We do not expect near-term borrowing increases will have a material negative effect on our overall
liquidity or financial condition.

 If we were to repatriate a portion or all of the cash and short-term
investments held by our foreign subsidiaries, we would recognize and pay current income taxes in accordance with current U.S. tax law. The payment of such additional income tax would materially decrease the amount of cash and short-term investments
ultimately available to fund our business.

 Page 67:

As of December 31, 2011, Devon’s unremitted foreign earnings totaled approximately $7.9 billion. Of this
amount, approximately $5.4 billion was deemed to be indefinitely reinvested into the development and growth of our Canadian business. Therefore, Devon has not recognized a deferred tax liability for U.S. income taxes associated with such earnings.
If such earnings were to be repatriated to the U.S., Devon may be subject to U.S. income taxes and foreign withholding taxes. However, it is not practical to estimate the amount of such additional taxes that may be payable due to the
inter-relationship of the various factors involved in making such an estimate.

 Devon has deemed the remaining
$2.5 billion of unremitted earnings not to be indefinitely reinvested. Consequently, Devon has recognized a $936 million deferred tax liability associated with such unremitted earnings as of December 31, 2011. Although Devon has recognized this
deferred tax liability, Devon does not currently expect to repatriate its foreign earnings. This expectation is based on Devon’s current forecasts for both its U.S. and Canadian operations, currently favorable borrowing conditions in the U.S.,
and existing U.S. income tax laws pertaining to repatriations of foreign earnings.

 SEC Comment

2.
Please confirm that you will disclose the dollar amounts of cash held by your foreign subsidiaries and the amounts you do not expect to repatriate to the United
States in your Exchange Act filings.

 Response

 As indicated in our response to comment #1, we will disclose the dollar amounts of cash held by our foreign subsidiaries, including the approximate amounts, if any, that we do not expect to repatriate to
the United States.

 H. Roger Schwall

 United States Securities and Exchange Commission

  Page
 3

 February 1, 2013

 Exhibit 99.2

 SEC Comment

3.
We acknowledge the Company’s response to comments 1 and 3 in our letter dated December 13, 2012 with respect to disclosing in future filings the average
sales price, net production and net reserves attributable to your bitumen reserves located in Canada in accordance with Items 1204 and 1202(a)(4) of Regulation S-K and FASB ASC paragraph 932-235-50-4. Please tell us if the reserves report includes
the Jackfish proved bitumen reserves as of December 31, 2011. If the reserves report does include the proved bitumen reserves attributable to Jackfish, please consult with your engineers to obtain a revised reserves report that expands the
disclosure of the pricing information to include the benchmark and weighted average realized prices used in the report for bitumen.

 Response

 Our December 31, 2011 reserves report does include the Jackfish proved
bitumen reserves. We have obtained a revised reserves report from AJM Deloitte that reflects separate price information disclosures pertaining to bitumen. Furthermore, we will include this revised report format as an exhibit in our future filings.

 * * * * * * * *

 In
connection with the above response to the staff’s comment, Devon acknowledges that:

•

 Devon is responsible for the adequacy and accuracy of the disclosure in the filing;

•

 Staff comments or changes to disclosure in response to staff comments do not foreclose the Commission from taking any action with respect to the
filing; and

•

 Devon may not assert staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the
United States.

Sincerely,

/s/ Jeffrey A. Agosta

Jeffrey A. Agosta

Executive Vice President and Chief Financial Officer

January 23 , 2013

Via Email
Mr. Jeffrey A. Agosta
Chief Financial Officer
Devon Energy Corporation
333 West Sheridan Avenue
Oklahoma City, O K 73102

Re: Devon Energy Corporation
 Form 10-K for Fiscal Year Ended
 December 31, 2011
Filed February 24, 2012
Response Letter Dated January 11, 2013
File No. 001 -32318

Dear Mr. Agosta :

We have reviewed your  response letter and have the following comments.  Where
indicated, we think  you should revise your documents in response to these comments. If you
disagree, we will consider your explanation as to why our comment is inapplicable or a revision is
unnecessary. Please be as detailed as necessary in your explanation.  After reviewing this information,
we may raise additional comments .

Please respond to this letter within ten business days by amending your filing, by
providing the requested information, or by advising us when you will provide the requested
response.   If you do not beli eve our comments apply to your facts and circumstances or do not
believe an amendment is appropriate, pleas e tell us why in your response.

Form 10 -K for Fiscal Year Ended December 31, 2011

Consolidated Financial Statements

Notes t o Consolida ted Financial Statements

Note 6 – Income Taxes, page 66

1. We note your response to comment 2 in our letter dated December 13, 2012.  Your response
states that $4.3 billion of cash and short -term investments held by your foreign subsidiaries
as of December 31, 2011 was deemed repatriated.  However, the disclosure per page 39 of
your Form 10 -K states that the vast majority of your cash and short -term investment s consist
of proceeds from your international offshore d ivestitures held by certain of your foreign

Mr. Jeffrey A. Agosta
Devon Energy Corporation
January 23, 2013
Page 2

 subsidiaries which you do not currentl y expect to repatriate to the United States.  Please
addres s this apparent inconsistency.

2. Please confirm that you will disclose the dollar amount s of cash held by your foreign
subsidiaries and the amount s you do not expect to repatriate to the U nited States in your
Exchange Act filings.

Exhibit 99.2

3. We acknowledge the Company’s  response to comments 1 and 3 in our letter dated December
13, 2012 wit h respect to disclosing in future filings the average sales  price, net production
and net reserves attributable to your bitumen reserves located in Canada in accordance with
Items 1204 and 1202(a)(4) of Regulation S -K and FASB ASC paragraph 932 -235-50-4.
Please tell us if the reserves report includes the Jackfish proved bitumen reserves as of
December 31, 2011.  If the reserves report does include s the proved bitumen reserves
attributable to Jackfish, please consult with your engineers to obtain a revised reserves report
that expands the disclosure of the pricing information to include the benchmark and weighted
average realized prices used in the report for bitumen.

You may contact Svitlana Sweat , Staff Accountant  at 202-551-3326  or Ethan Horowitz ,
Branch  Chief  at 202-551-3311 if you have questions regarding comments on the financial
statements and related matters.  Please contact John Hodgin, Petroleum Engineer , at 202-551-
3699  if you have questions regarding the engineering comments.   Please contact me at 202-551-
3745  with any other questions.

Sincerely,

 /s/H. Roger Schwall

 H. Roger Schwall
Assistant Director

CORRESP
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Correspondence Letter

Table of Contents

 Devon Energy Corporation

333 West Sheridan Avenue

 Oklahoma City, OK 73102

    405 552 4577 phone
    jeff.agosta@dvn.com

 January 11, 2013

 Via EDGAR

 Attention: Ms. Svitlana Sweat, Division of Corporation Finance

 H. Roger Schwall

 Assistant
Director

 United States Securities and Exchange Commission

 100 F. Street, N.E.

 Washington, D.C. 20549

Re:
Devon Energy Corporation

 Form 10-K for the Fiscal Year Ended December 31, 2011

 Filed
February 24, 2011

 File No. 001-32318

 Dear Mr. Schwall:

 This letter responds to the staff’s comment letter dated
December 13, 2012, regarding Devon Energy Corporation’s Form 10-K for the year ended December 31, 2011, filed February 24, 2012 (File No. 001-32318). Devon’s responses to the staff’s comments are set forth below:

 Form 10-K for Fiscal Year Ended December 31, 2011

 Oil and Gas Properties, page 4

 Production, Production Prices and Production
Costs, page 10

 SEC Comment

1.
We note you disclose the production and average sales price by final product sold on page 10 and elsewhere in your filing on Form 10-K. In regards to disclosure by
final product sold, we note on page 7 you state that Jackfish is a “non-conventional oil sands” project. Furthermore, in the section entitled “Projects Overview” under “Operations-Jackfish Projects” on your company
website (http://www.devonenergy.com/Operations/Canada/Pages/jackfish_project), you state steam assisted gravity drainage is “being used to extract the bitumen over the life of the projects”; however, it does not appear that you make
reference to or distinguish between bitumen and oil as final sales products in your filing on Form 10-K as required by Item 1204(a) of Regulation S-K. Revise your presentation to break out bitumen separately or tell us why you do not believe
that is appropriate. See also Instruction 3 to Item 1204 of Regulation S-K.

 Response

Jackfish is currently our only project with bitumen production, which totaled 13 million, 9 million and 8 million barrels in 2011, 2010 and
2009, respectively. This production represented 5%, 4% and 3% of our total production for 2011, 2010 and 2009, respectively. We will revise our presentation to break out bitumen production and average sales prices separately as required by
Item 1204(a) in future filings.

Table of Contents

 H. Roger Schwall

 United States Securities and Exchange Commission

  Page
 2

 January 11, 2013

 Notes to Consolidated Financial Statements

 Note 6 – Income Taxes, page
66

 SEC Comment

2.
We note that you recognized deferred income tax expense of $725 million during the fiscal year ended December 31, 2011 related to the assumed repatriations of
earnings from your foreign subsidiaries. We also note the disclosure per page 39 of your filing which states that the majority of your cash and short-term investments consist of the proceeds from your international offshore divestitures which are
held by certain of your foreign subsidiaries. This disclosure also states that you do not currently expect to repatriate such amounts to the United States. Please tell us the factors considered by management in its conclusion that these amounts will
not be repatriated. Your response should also outline your plans for the permanent reinvestment of the undistributed earnings of your foreign subsidiaries. Refer to FASB ASC 740-30-25-17. In connection with your response, please quantify the amount
of cash and short-term investments held by your foreign subsidiaries.

 Response

Of the $7.1 billion of cash and short-term investments we held at December 31, 2011, $6.9 billion was held by our foreign subsidiaries, of which $4.3
billion was deemed repatriated. We had recognized $936 million of deferred income tax expense for deemed repatriations through the year ended December 31, 2011 (see deferred tax liability for taxes on unremitted foreign earnings on page 67 of
our December 31, 2011 Form 10-K). We recognized virtually all this deferred income tax expense in 2009, 2010 and 2011, including the $725 million recognized in 2011.

 While we have recognized deferred income taxes for deemed repatriations on a portion of our unremitted foreign earnings, we have determined that certain of our unremitted foreign earnings are being
permanently reinvested. To form our permanent reinvestment conclusions, we consider the financial requirements of our U.S. companies and our foreign subsidiaries, the tax consequences of any remittances, and the operational and fiscal objectives of
our U.S. companies. More specifically, we consider our cash and investments on hand, forecasted after-tax cash flows, and availability of other cash resources, including commercial paper borrowings and debt offerings in the U.S. in a favorably low
interest-rate environment.

 Our plans to permanently reinvest a portion of the unremitted earnings of our foreign subsidiaries are based on
our investment programs and related cash flow forecasts of our respective U.S. and foreign operations. Specifically, our U.S. operations are self-funding through earnings and cash flow from the underlying assets or debt issuance due to a very strong
balance sheet and favorable borrowing conditions. However, the capital investment needs of our Canadian operations are expected to exceed the cash inflows largely because of on-going investments in our multi-billion dollar, long-lead time and
capital-intensive oil sands development projects. Accordingly, the unremitted foreign earnings that have funded or will fund our ongoing Canadian operations are deemed permanently reinvested.

 Supplemental Information on Oil and Gas Operations (Unaudited), page 88

Proved Reserves, page 91

 SEC
Comment

Table of Contents

 H. Roger Schwall

 United States Securities and Exchange Commission

  Page
 3

 January 11, 2013

3.
We note you disclose the net quantities and changes in your proved oil reserves on page 91. It does not appear that you make reference to or distinguish between
bitumen and oil as product types in disclosing your net reserve quantities here or elsewhere in your filing on Form 10-K. The table should reflect products in the form in which they are sold. Thus, if you sell bitumen it should be broken out
separately from oil, even if it will be upgraded to synthetic oil or gas by the purchaser. If you upgrade the bitumen to synthetic oil or gas prior to sale, then present those quantities separately as synthetic oil or synthetic gas. See
Item 1202(a)(4) of Regulation S-K and FASB ASC 932-235-50-4.

 Response

Jackfish is currently our only project with bitumen proved reserves, which totaled 457 million, 440 million and 403 million barrels at
December 31, 2011, 2010 and 2009, respectively. These proved reserves represented 15% of our total proved reserves as of each year ended December 31, 2011, 2010 and 2009. We will revise our presentation to break out bitumen proved reserves
separately as required by Item 1204(a)(4) and FASB ASC 932-235-50-4 in future filings.

 Proved Undeveloped reserves, page 95

 SEC Comment

4.
We note your disclosure of the total quantity of proved undeveloped reserves at the 2011 year end and the material changes in proved undeveloped reserves that
occurred during the year, including the net quantities of proved undeveloped reserves converted into proved developed reserves as required by Items 1203(a) and 1203(b) of Regulation S-K. Please expand your disclosure to also address the investments,
including the capital expenditures, made during the year to convert your proved undeveloped reserves to proved developed. See Item 1203(c) of Regulation S-K.

 Response

 During 2011, we invested approximately $1.3 billion to convert our proved
undeveloped (“PUD”) reserves to proved developed. In future filings, we will include in the discussion of PUD reserves expanded disclosure that includes the amount of capital expenditures incurred to convert our PUD reserves to proved
developed such as the following: “Costs incurred for the year ended December 31, 2011, related to the development of proved undeveloped reserves were $1.3 billion.”

 SEC Comment

5.
We note you disclose that revisions during 2011 other than price decreased your proved undeveloped reserves primarily due to the evaluation of certain U.S. onshore
dry-gas areas, which the Company “does not expect to develop in the next five years.” For purposes of determining the five year period, Item 1203(d) of Regulation S-K identifies the initial disclosure and date thereof as the starting
reference date. Please tell us if any of your proved undeveloped volumes disclosed as of December 31, 2011, other than those attributed to Jackfish or included in the revision as noted, will take more than five years since initial disclosure to
develop.

 Response

 Excluding our Jackfish PUD reserves, we had 0.75 million Boe of PUD reserves, which represented 0.02% of our total proved reserves, that are expected to take more than five years to develop since
initial disclosure. These PUD reserves relate to one immaterial Canadian property in which the gas cap is scheduled for development upon the depletion of the oil leg of the reservoir in accordance with the regulations of the Energy Resources
Conservation Board of Alberta. These reserves are consistent with the definition of undeveloped oil and gas reserves in Rule 4-10(a)(31)(ii) of Regulation S-X.

Table of Contents

 H. Roger Schwall

 United States Securities and Exchange Commission

  Page
 4

 January 11, 2013

SEC’s Modernization of Oil and Gas Reporting, page 96

 SEC Comment

6.
We note you disclose that the Company’s 2009 reserves increased approximately 2% as a result of adopting the provisions in the new rules permitting the use of
reliable technologies to establish the reasonable certainty of proved reserves. Furthermore, you state “this increase is included in the 2009 extensions and discoveries total.” We note your 2011 extensions and discoveries amount to 14.7%
of the opening balance of total proved reserves on a boe basis and were attributed to your activities in the Cana-Woodford Shale, Barnett Shale, Permian Basin, Jackfish, Rocky Mountain and Granite Wash areas. Additionally, we note your 2010
extensions and discoveries amount to 13% of the opening balance of total proved reserves on a boe basis and were attributed to your activities in the Cana-Woodford Shale, Barnett Shale, Jackfish, Permian Basin, Rocky Mountain and Carthage areas.
Please tell us if any of the volumes relating to extensions and discoveries for years ending 2011 and 2010 are attributable to reliable technologies and if so whether you consider the related volumes material in light of Item 1202(a)(6) of
Regulation S-K.

 Response

 In both 2011 and 2010, our extensions and discoveries included volumes that are based upon reliable technologies. However, the volumes represent less than 2% of our reserves at the beginning of each year.
Therefore, absent acknowledgement of the impact of a rule change, which was the case for our 2009 disclosure, we considered the 2011 and 2010 amounts to be immaterial.

 Standardized Measure, page 97

 SEC Comment

7.
We note you state “future cash inflows, development costs and production costs were computed using the same assumptions for prices and costs that were used to
estimate Devon’s proved oil and gas reserves at the end of each year.” You also state “for 2011, the prices averaged $67.31 per barrel of oil, $3.51 per Mcf of gas and $39.28 per barrel of natural gas liquids”; however, these
average prices do not appear to correspond to your disclosures on prices found on pages 10, 27 or 29 of your filing on Form 10-K. Please explain why these prices differ from the prices provided elsewhere in your disclosure on Form 10-K.

 Response

As required by FASB ASC 932-235 and disclosed on page 96, the future cash inflows and resulting average realized prices on page 97 are calculated using
prices that represent the unweighted arithmetic average of the first-day-of-the-month price for the preceding 12-month period (i.e., January 1, 2011 to December 1, 2011). While a portion of our production is sold based on
first-day-of-the-month prices, a portion is sold based on daily prices, particularly our oil and NGL production. Additionally, the composition of each of our commodity products sold changes over time because of variations in production development
schedules and decline rates. Consequently, our overall average realized prices for each commodity will change over the producing life of our proved reserves and, thus, will not necessarily be the same as those for 2011. Therefore, because we do not
sell all our production based on first-day-of-the-month prices and the composition of our product sales changes over time, the prices on pages 10, 27 and 29 will not match the prices on page 97.

Table of Contents

 H. Roger Schwall

 United States Securities and Exchange Commission

  Page
 5

 January 11, 2013

In future filings, we will more clearly indicate the prices used for our standardized measure are future prices with disclosure such as: “For 2011, the future average realized prices
averaged $67.31 per barrel of oil, $3.51 per Mcf of gas and $39.28 per barrel of natural gas liquids.”

 SEC Comment

8.
We note you include as a single line item entry “development costs incurred that reduced future development costs” in your disclosure of the principal
changes in the Company’s standardized measure of discounted future net cash flows on page 98. Please tell us how you have considered the requirements in FASB ASC 932-235-50-35 as illustrated in Example 6: Changes in the Standardized Measure for
Discounted Cash Flows found in FASB ASC 932-235-55-7; wherein, the changes in estimated future development costs are presented separately from the previously estimated development costs incurred during the period.

Response

 For 2011, 2010 and 2009, the
changes in our estimates of future development costs were decreases of approximately $400 million, $300 million and $200 million, respectively. In our disclosure of the principal changes in our standardized measure on page 98, we included these
amounts within our caption “revisions of quantity estimates.” In future filings, we will revise our presentation of the principal changes in our standardized measure to those illustrated in FASB ASC 932-235-50-35, including the separate
presentation of the changes in estimated future development costs.

 Exhibit 99.2

SEC Comment

9.
We note the reserve report on page 1 states “the scope of the audit consisted of the independent preparation of our own estimates of the proved and proved plus
probable reserves”; furthermore, you state “the proved and proved plus probable reserve estimates prepared by both Devon Canada and AJM conform to the reserve definitions as set forth in the SEC’s Regulation S-X Part 210.4-10(a) and
as clarified in subsequent Commission Staff Accounting Bulletins.”

 We note information relating to
probable reserves is not disclosed in Form 10-K. Either file a revised report which does not reference information relating to probable reserves or amend the Form 10-K to include that information.

Response

 In future filings, the
reference to probable reserves will be removed. Following this letter, we have attached an example of the proposed reserve report that reflects this change.

 SEC Comment

10.
 We note under the section entitled “Production Forecasts” on page 11 of your report, you state that “if the reserves were located in
a remote location and/or the reserve volume was of higher risk, the reserves were forecast to come on-stream beyond five years from the effective date” when the company could not provide specific on-stream date information. Please tell us if
you have adopted on-stream dates for any of the proved undeveloped reserves contained in your report that are beyond five years of the effe

CORRESP
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filename1.htm

Correspondence

Devon Energy Corporation

333 West Sheridan Avenue

Oklahoma City, OK 73102

405 552 4577 phone
 jeff.agosta@dvn.com

 January 3, 2013

 Via EDGAR

 Attention: Ms. Svitlana Sweat, Division of Corporation Finance

 H. Roger Schwall

 Assistant
Director

 United States Securities and Exchange Commission

 100 F. Street, N.E.

 Washington, D.C. 20549

Re:
Devon Energy Corporation

Form 10-K for the Fiscal Year Ended December 31, 2011

Filed February 24, 2011

File No. 001-32318

 Dear
Mr. Schwall:

 On January 2, 2013, Devon received the staff’s comment letter dated December 13, 2012, regarding Devon Energy
Corporation’s Form 10-K for the year ended December 31, 2011, filed February 24, 2012 (File No. 001-32318). We request an extension to submit Devon’s responses to the staff’s comments on January 11, 2013.

 Sincerely,

 /s/ Jeffrey A.
Agosta

 Jeffrey A. Agosta

Executive Vice President and Chief Financial Officer

December 1 3, 2012

Via Facsimile
Mr. Jeffrey A. Agosta
Chief Financial Officer
Devon Energy Corporation
333 West Sheridan Avenue
Oklahoma City, O K 73102

Re: Devon Energy Corporation
 Form 10-K for Fiscal Year Ended
 December 31, 2011
Filed February 24, 2012
File No. 001 -32318

Dear Mr. Agosta :

We have reviewed your filing and have the following comments.  In some of our
comments, we may ask you to provide us with information so we may better understand your
disclosure.

Please respond to this letter within ten business days by amending your filing, by
providing the requested information, or by advising us when you will provide the requested
response.   If you do not believe our  comments apply to your facts and circumstances or do not
believe an amendment is appropriate, please tell us why in your response.

After reviewing any amendment to your filing and the information you provide in
response to these comments, we may have a dditional comments.

Form 10 -K for Fiscal Year Ended December 31, 2011

Oil and Gas Properties, page 4

Production, Production Prices and Production Costs, page 10

1. We note you disclose the production and average sales price by final product sold on
page 10 and elsewhere in your filing on Form 10 -K.  In regards to disclosure by final
product sold, we note on page 7 you state that Jackfish is a “non -conventional oil sands”
project.  Furthermore, in the section entitled “Projects Overview” under  “Operations -
Jackfish Projects” on your company website
(http://www.devonenergy.com/Operations/Canada/Pages/jackfish_project), you state
steam assisted gravity drainage is “being used to extract the bitumen over the life of the
projects”; however, it does not appear that you make reference to or distinguish between

Mr. Jeffrey A. Agosta
Devon Energy Corporation
December 1 3, 2012
Page 2

 bitumen and oil as final sales products in your filing on Form 10 -K as required by Item
1204(a) of Regulation S -K.  Revise your presentation to break out bitumen separately or
tell us why you do not believe that is appropriate.  See also Instruction 3 to Item 1204 of
Regulation S -K.

Notes to Consolidated Financial Statements

Note 6 – Income Taxes, page 66

2. We note that you recognized deferred income tax expense of $725 million during the
fiscal year ended December 31, 2011 related to the assumed repatriations of earnings
from your foreign subsidiaries.  We also note the disclosure per page 39 of your filing
which states that the majority of your cash and short -term investments consist of the
proceeds from your international offshore divestitures which are held by certain of your
foreign subsidiaries.  This disclosure also states that you do not currently expect to
repatriate such amounts to the United States.  Please tell us the factors considered  by
management in its conclusion that these amounts will not be repatriated.  Your response
should also outline your plans for the permanent reinvestment of the undistributed
earnings of your foreign subsidiaries.  Refer to FASB ASC 740 -30-25-17.  In conne ction
with your response, please quantify the amount of cash and short -term investments held
by your foreign subsidiaries.

Supplemental Information on Oil and Gas Operations (Unaudited), page 88

Proved Reserves, page 91

3. We note you disclose the net quantities and changes in your proved oil reserves on page
91.  It does not appear that you make reference to or distinguish between bitumen and oil
as product types in disclosing your net reserve quantities here or elsewhere in your filing
on Form 10 -K.  The table should reflect products in the form in which they are sold.
Thus, if you sell bitumen it should be broken out separately from oil, even if it will be
upgraded to synthetic oil or gas by the purchaser.  If you upgrade the bitumen to synthetic
oil or gas prior to sale, then present those quantities separately as synthetic oil or
synthetic gas.  See Item 1202(a)(4) of Regulation S -K and FASB ASC 932 -235-50-4.

Proved Undeveloped Reserves, page 95

4. We note your disclosure of the total quantity of pro ved undeveloped reserves at the 2011
year end and the material changes in proved undeveloped reserves that occurred during
the year, including the net quantities of proved undeveloped reserves converted into
proved developed reserves as required by Items 1 203(a) and 1203(b) of  Regulation S -K.
Please expand your disclosure to also address the investments, including the capital
expenditures, made during the year to convert your proved undeveloped reserves to
proved developed.  See Item 1203(c) of Regulation  S-K.

Mr. Jeffrey A. Agosta
Devon Energy Corporation
December 1 3, 2012
Page 3

5. We note you disclose that revisions during 2011 other than price decreased your proved
undeveloped reserves primarily due to the evaluation of certain U.S. onshore dry -gas
areas, which the Company “does not expect to develop in the next five years. ”  For
purposes of determining the five year period, Item 1203(d) of Regulation S -K identifies
the initial disclosure and date thereof as the starting reference date.  Please tell us if any
of your proved undeveloped volumes disclosed as of December 31, 20 11, other than
those attributed to Jackfish or included in the revision as noted, will take more than five
years since initial disclosure to develop.

SEC’s Modernization of Oil and Gas Reporting, page 96

6. We note you disclose that the Company’s 2009 reser ves increased approximately 2% as a
result of adopting the provisions in the new rules permitting the use of reliable
technologies to establish the reasonable certainty of proved reserves.  Furthermore, you
state “this increase is included in the 2009 exte nsions and discoveries total.”  We note
your 2011 extensions and discoveries amount to 14.7% of the opening balance of total
proved reserves on a boe basis and were attributed to your activities in the Cana -
Woodford Shale, Barnett Shale, Permian Basin, Jac kfish, Rocky Mountain and Granite
Wash areas.  Additionally, we note your 2010 extensions and discoveries amount to 13%
of the opening balance of total proved reserves on a boe basis and were attributed to your
activities in the Cana -Woodford Shale, Barnet t Shale, Jackfish, Permian Basin, Rocky
Mountain and Carthage areas.  Please tell us if any of the volumes relating to extensions
and discoveries for years ending 2011 and 2010 are attributable to reliable technologies
and if so whether you consider the re lated volumes material in light of Item 1202(a)(6) of
Regulation S -K.

Standardized Measure, page 97

7. We note you state “future cash inflows, development costs and production costs were
computed using the same assumptions for prices and costs that were use d to estimate
Devon’s proved oil and gas reserves at the end of each year.”  You also state “for 2011,
the prices averaged $67.31 per barrel of oil, $3.51 per Mcf of gas and $39.28 per barrel of
natural gas liquids”; however, these average prices do not ap pear to correspond to your
disclosures on prices found on pages 10, 27 or 29 of your filing on Form 10 -K.  Please
explain why these prices differ from the prices provided elsewhere in your disclosure on
Form 10 -K.

8. We note you include as a single line item  entry “development costs incurred that reduced
future development costs” in your disclosure of the principal changes in the Company’s
standardized measure of discounted future net cash flows on page 98.  Please tell us how
you have considered the requirem ents in FASB ASC 932 -235-50-35 as illustrated in
Example 6: Changes in the Standardized Measure for Discounted Cash Flows found in
FASB ASC 932 -235-55-7; wherein, the changes in estimated future development costs

Mr. Jeffrey A. Agosta
Devon Energy Corporation
December 1 3, 2012
Page 4

 are presented separately from the previousl y estimated development costs incurred during
the period.

Exhibit 99.2

9. We note the reserve report on page 1 states “the scope of the audit consisted of the
independent preparation of our own estimates of the proved and proved plus probable
reserves”; furthermore, you state “the proved and proved plus probable reserve estimate s
prepared by both Devon Canada and AJM conform to the reserve definitions as set forth
in the SEC’s Regulation S -X Part 210.4 -10(a) and as clarified in subsequent Commission
Staff Accounting Bulletins.”

We note information relating to probable reserves is not disclosed in Form 10 -K.  Either
file a revised report which does not reference information relating to probable reserves or
amend the Form 10 -K to include that information.

10. We note under the secti on entitled “Production Forecasts” on page 11 of your report, you
state that “if the reserves were located in a remote location and/or the reserve volume was
of higher risk, the reserves were forecast to come on -stream beyond five years from the
effective date” when the company could not provide specific on -stream date information.
Please tell us if you have adopted on -stream dates for any of the proved undeveloped
reserves contained in your report that are beyond five years of the effective date of the
report or more than five years since disclosure of such reserves by the Company in a
filing made with the SEC.

11. We note the reserve report does not include the following disclosures required in Item
1202(a)(8) of Regulation S -K:

 The reserve report does not state the date on which the report was completed as
required in Item 1202(a)(8)(ii) of Regulation S -K.
 The reserve report does not include a discussion of the inherent uncertainties of
reserves estimates as required in Item 1202(a)(8)(vii) of Regulation S -K.
12. Regulation S -K requires disclosure of Items 1202(8)(i) through (8)(x) applicable to the
report prepared by the third party and specific to the properties contained in that report.
We note the following:

 Under the section entitled “Procedure” on page 4  of your report, you state “AJM
Deloitte has prepared estimates of resources and reserves in accordance with the
process published in The Canadian Oil and Gas Evaluation Handbook (COGEH),
Volume 1, 2 Edition. The reader is referred to the Handbook for a co mplete
description of the particular process quoted as follows.”  Following this statement,
you include a description of a resources or reserves evaluation on page 4 and a

Mr. Jeffrey A. Agosta
Devon Energy Corporation
December 1 3, 2012
Page 5

 reserve review on page 5; however, information provided on page 1 of your report
appears to suggest you are reporting the results of a reserves audit.  Please amend
your report, to discuss only those procedures used in the preparation of your
report.
 Under the section entitled “Reserve Definitions” on page 6 of your report, you
state “pro ved reserves are classified by AJM Deloitte in accordance with the
following definitions that are the United States Securities and Exchange
Commission Regulation S -X Part 210.4 -10.”  We note the definitions that follow
on pages 6 through 8, where attribute d to the SEC, do not appear to conform to
the current definitions as reported in Rule 4 -10(a) of Regulation S -X.  Please tell
us what reserve definitions, including the source and date, were used in the
preparation of your audit.
 Under the section entitle d “Resource and reserve estimation” on page 9 of your
report, you state “AJM Deloitte generally assigns reserves to properties via
deterministic methods.  Probabilistic estimation techniques are typically used
where there is a low degree of certainty in th e information available and is
generally used in resource evaluations. This will be stated within the detailed
property reports.”  On page 9, you provide a discussion of the use of deterministic
methods and evaluations using statistical analysis.  On page 10, you provide a
discussion of the use of probabilistic methods.  Please tell us which of the
methods or combination of methods so described were actually used in
conducting your audit of the properties addressed in your report.
 Under the section entitled  “Capital and operating considerations” on page 14 of
your report, you state your reserves were estimated to “meet the standards of NI
51-101 for constant prices and costs” rather than referencing the requirements set
forth in Rule 4 -10(a) of Regulation S -X and FASB ASC 932.  Furthermore, you
make reference on pages 2 and 16 to “price and market demand forecasts” and on
page 14 to certain “escalated runs” in your discussion of operating costs; whereas,
Rule 4 -10(a)(22)(v) of Regulation S -X requires that pro ved reserves be based on
“existing economic conditions.”  On page 15, you state “in reserve evaluations
conducted for purposes of NI 51 -101, or, if an economic analysis was prepared
for a resource evaluation, well abandonment and reclamation costs have bee n
included.”  Please tell us if your audit and the results presented in this report were
conducted by you in accordance with the standards and requirements as set forth
in the NI 51 -101 or in accordance with Rule 4 -10(a) of Regulation S -X,
Regulation S -K and FASB ASC 932.
 Under the section entitled “Glossary of terms” on page 17 of your report, you
state “AJM Deloitte subscribes to the Glossary of Terms as defined by the

Mr. Jeffrey A. Agosta
Devon Energy Corporation
December 1 3, 2012
Page 6

 Canadian Oil and Gas Evaluation Handbook, Volume 2.”  Please tell us why
terms defined by the Canadian Oil and Gas Evaluation Handbook are applicable
to the preparation of your report addressing an audit of reserves prepared
following the SEC’s definitions as contained in Rule 4 -10(a) of Regulation S -X.
13. We note the reserve report does not in clude the qualifications of the technical person
primarily responsible for overseeing the preparation of the reserves estimates.  If the
registrant files a report of the third party as an exhibit, the third party must include in that
report a disclosure un der Item 1202(a)(7) of Regulation S -K.

14. We note several references in the report to additional information that are not included in
Exhibit 99.2:
 Under the section entitled “Land schedule and maps” on page 12 of your report,
you state the report includes “ well maps.”  The referenced well maps do not
appear to be included in Exhibit 99.2.
 Under the section entitled “Geology” on page 12, you state “procedures specific
to the project are discussed in the body of the report.”  The referenced discussion
of the g eologic procedures specific to the properties addressed in your report does
not appear to be included in Exhibit 99.2.

Please advise or amend the report to include the referenced information as part of the
report discussion or as attachments to Exhibit 99.2.

We urge all persons who are responsible for the accuracy and adequacy of the disclosure
in the filing to be certain that the filing includes the information the Securities Exchange Act of
1934 and all applicable Exchange Act rules require.   Since th e company and its management are
in possession of all facts relating to a company’s disclosure, they are responsible for the accuracy
and adequacy of the disclosures they have made.

 In responding to our comments, please provide a written statement from  the company
acknowledging that:

 the company is responsible for the adequacy and accuracy of the disclosure in the filing;

 staff comments or changes to disclosure in response to staff comments do not foreclose
the Commission from taking any action with r espect to the filing; and

 the company may not assert staff comments as a defense in any proceeding initiated by
the Commission or any person under the federal securities laws of the United States.

You may contact Svitlana Sweat , Staff Accountant  at 202-551-3326  or Ethan Horowitz ,
Branch Chief  at 202-551-3311 if you have questions regarding comments on the financial
statements and related matters.  Please contact John Hodgin, Petrol

February 7, 2012
 Via E-mail

John Richels Chief Executive Officer Devon Energy Corporation 20 North Broadway Oklahoma City, OK 73102-8260
Re: Devon Energy Corporation
Form 10-K for Fiscal Year Ended December 31, 2010 Filed February 25, 2011 File No. 001-32318

Dear Mr. Richels:
We have completed our review of your f iling.  We remind you that our comments or
changes to disclosure in res ponse to our comments do not for eclose the Commission from taking
any action with respect to the company or th e filing and the company may not assert staff
comments as a defense in any proceeding ini tiated by the Commission or any person under the
federal securities laws of the United States.  We urge all pers ons who are responsible for the
accuracy and adequacy of the disclosure in the fi ling to be certain that the filing includes the
information the Securities Exchange Act of 1934 and all applicable rules require.
  Sincerely,

 /s/H. Roger Schwall   H. Roger Schwall
Assistant Director

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Letter to the SEC

Devon Energy Corporation
 20 North
Broadway

 Oklahoma City, OK 73102-8260

405 552 4577 phone
 405 552 1345 fax

jeff.agosta@dvn.com

 January 11, 2012

 Via EDGAR and Facsimile No. 703 813 6982

 Attention: Mr. Paul
Monsour, Division of Corporation Finance

 H. Roger Schwall

 Assistant Director

 United States 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, 2010

Filed February 25, 2011

File No. 001-32318

 Dear
Mr. Schwall:

 This letter responds to the staff’s comment letter dated December 30, 2011, regarding Devon Energy
Corporation’s Form 10-K for the year ended December 31, 2010, filed February 25, 2011 (File No. 001-32318). Devon’s response to the staff’s comment is set forth below:

Form 10-K for Fiscal Year Ended December 31, 2010

 Item 1A. Risk Factors, page 12

 Insurance Does Not Cover All Risks, page
15

 SEC Comment

1.
We note your disclosure in the above-captioned risk factor concerning operational and financial risks, and your disclosure on pages 14 and 15 regarding regulatory
risks related to hydraulic fracturing. If material, please revise the above-captioned risk factor to address operational and financial risks associated with hydraulic fracturing, such as underground migration and surface spillage or mishandling of
fluids, including chemical additives.

 Response

 With regards to our hydraulic fracturing activities, including the operational risks the Staff identifies in its comment, we have significant insurance coverage against losses that result from certain
sudden and accidental operational events. Therefore, we do not believe we have material financial risk associated with sudden and accidental hydraulic fracturing events. However, insurance coverage is generally not available to us for events
considered gradual in nature, such as underground migration that occurs over a number of years. Therefore, we propose to revise the above-captioned risk factor as it would be included in our upcoming Form 10-K for the fiscal year ended
December 31, 2011 as follows:

 H. Roger Schwall

 United States Securities and Exchange Commission

 Page 2

January 11, 2012

 Insurance Does Not Cover All Risks

Our business is hazardous and is subject to all of the operating risks normally associated with the exploration,
development, production, processing and transportation of oil, natural gas and NGLs. Such risks include potential blowouts, cratering, fires, loss of well control, mishandling of fluids and chemicals and possible underground migration of
hydrocarbons and chemicals. The occurrence of any of these risks could result in environmental pollution, damage to or destruction of our property, equipment and natural resources, injury to persons or loss of life. Additionally, for our
non-operated properties, we generally depend on the operator for operational safety and regulatory compliance.

To mitigate financial losses resulting from these operational hazards, we maintain comprehensive general liability
insurance, as well as insurance coverage against certain losses resulting from physical damages, loss of well control, business interruption and pollution events that are considered sudden and accidental. We also maintain worker’s compensation
and employer’s liability insurance. However, our insurance coverage does not provide 100% reimbursement of potential losses resulting from these operational hazards. Additionally, insurance coverage is generally not available to us for
pollution events that are considered gradual, and we have limited or no insurance coverage for certain risks such as political risk, war and terrorism. Our insurance does not cover penalties or fines assessed by governmental authorities. The
occurrence of a significant event against which we are not fully insured could have a material adverse effect on our profitability, financial condition and liquidity.

 * * * * * * * *

 In connection with the above response to the staff’s comment, Devon
acknowledges that:

•

 Devon is responsible for the adequacy and accuracy of the disclosure in the filing;

•

 staff comments or changes to disclosure in response to staff comments do not foreclose the Commission from taking any action with respect to the
filing; and

•

 Devon may not assert staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the
United States.

 Sincerely,

 /s/ Jeffrey A. Agosta

 Jeffrey A. Agosta

Executive Vice President and Chief Financial Officer

December 30, 2011
 Via E-mail

John Richels Chief Executive Officer Devon Energy Corporation 20 North Broadway Oklahoma City, OK 73102-8260
Re: Devon Energy Corporation
Form 10-K for Fiscal Year Ended December 31, 2010 Filed February 25, 2011 File No. 001-32318

Dear Mr. Richels:
We have reviewed your filing and have the following comments.  In some of our
comments, we may ask you to provide us with  information so we may better understand your
disclosure.
Please respond to this letter within ten business days by amending your filing, by
providing the requested information, or by advi sing us when you will provide the requested
response.  If you do not believe our comments apply to your fact s and circumstances or do not
believe an amendment is appropriate, please tell us why in your response.

After reviewing any amendment to your filing and the information you provide in
response to these comments, we may have additional comments.  Form 10-K for Fiscal Year Ended December 31, 2010

Item 1A. Risk Factors, page 12

Insurance Does Not Cover All Risks, page 15

1. We note your disclosure in the above-captione d risk factor concer ning operational and
financial risks, and your disclosure on page s 14 and 15 regarding regu latory risks related
to hydraulic fracturing.  If mate rial, please revise the above -captioned risk factor to
address operational and financial risks associ ated with hydraulic fracturing, such as
underground migration and surface spillage or mi shandling of fluids, including chemical
additives.

John Richels
Devon Energy  Corporation
December 30, 2011 Page 2

Closing Comments

We urge all persons who are responsible for th e accuracy and adequacy of the disclosure
in the filing to be certain that the filing include s the information the Securities Exchange Act of
1934 and all applicable Exchange Act rules requir e.  Since the company and its management are
in possession of all facts relating to a company’s disclosure, they are responsible for the accuracy
and adequacy of the disclosures they have made.
In responding to our comments, please provi de a written statement from the company
acknowledging that:
• the company is responsible for the adequacy an d accuracy of the disclo sure in the filing;

• staff comments or changes to disclosure in response to staff comments do not foreclose
the Commission from taking any action with respect to the filing; and

• the company may not assert staff comments as  a defense in any proceeding initiated by
the Commission or any person under the federa l securities laws of  the United States.

Please contact Paul Monsour, Staff Attorne y, at (202) 551-3360, La ura Nicholson, Staff
Attorney, at (202) 551-3584, or me at  (202) 551-3740 with any questions.

Sincerely,
/s/ A.N. Parker for
 H. Roger Schwall Assistant Director

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549-4628

DIVISION OF
CORPORATION FINANCE

        October 25, 2010
 Mr. Danny J. Heatly Vice President, Accounting Devon Energy Corporation 20 North Broadway Oklahoma City, OK  73102-8260
Re: Devon Energy Corporation
 Form 10-K for the Fiscal Year Ended December 31, 2009
Filed February 25, 2010 Schedule 14A  Filed April 28, 2010 Form 10-Q for the Quarterly Period Ended June 30, 2010 Filed August 6, 2010 File No. 1-32318

Dear Mr. Heatly:
We have completed our review of your Form 10-K and related filings and do not have
any further comments at this time.           S i n c e r e l y ,                    / s /  B r a d  S k i n n e r                   B r a d  S k i n n e r          Senior Assistant Chief Accountant

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corresp

    Devon Energy Corporation

    405 552 4702 Phone

    20 North Broadway

Oklahoma City, OK 73102-8260

    405 552 7692 Fax

danny.heatly@dvn.com

October 21, 2010

Via EDGAR

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/A for the Fiscal Year Ended December 31, 2009

    Filed August 18, 2010

    File No. 1-32318

Dear Mr. Schwall:

On August 18, 2010, Devon Energy Corporation filed a Form 10-K/A that addressed certain staff
comments concerning the independent petroleum engineers’ reports filed as exhibits to our original
Form 10-K for the year ended December 31, 2009. Included as Exhibit 99.1 to our 10-K/A is a report
from LaRoche Petroleum Consultants, Ltd.

Recently, Ms. Laura Nicholson informed me that Exhibit 99.1 does not contain properly conformed
signatures of the two engineers who signed the LaRoche report. I have informed Ms. Nicholson that
we have in our files the actual manually signed report from LaRoche, which is the same as the
report filed via EDGAR as Exhibit 99.1. Unfortunately, when we asked LaRoche for a copy of their
report to file via EDGAR, we did not notice that the signatures were not properly conformed. A
copy of the manually signed LaRoche report from our files is attached to this letter.

We will undertake to ensure this oversight is not repeated in future filings.

Sincerely,

    /s/  Danny J. Heatly

    Danny J. Heatly

    Senior Vice President — Accounting and
Chief Accounting Officer

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corresp

    Devon Energy Corporation

20 North Broadway

Oklahoma City, OK 73102-8260

    405 552 4702 Phone

405 552 7692 Fax

danny.heatly@dvn.com

August 18, 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

Response Letter Dated June 25, 2010

File No. 1-32318

Dear Mr. Schwall:

This letter responds to the staff’s comment letter dated August 4, 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:

Exhibits 99.1, 99.2 and 99.3

SEC Comment

    1.

    We direct your attention to prior comment one in our letter dated April 8, 2010. Please
obtain and file revised reports that comply with such comment.

Response

We filed on this date a Form 10-K/A that includes revised Exhibits 99.1, 99.2 and 99.3. The
revised exhibits do not contain the previous language that suggested a limit on potential investor
reliance. Language that clarifies the reports are intended for public disclosure is included in
the third and fourth paragraphs of page four in Exhibit 99.1, the first and second paragraphs of
page nine in Exhibit 99.2, and the last paragraph of page two and the first paragraph of page three
in Exhibit 99.3.

SEC Comment

    2.

    We note your response to prior comment six in our letter dated June 11, 2010. We do not
agree with your position that “...inclusion of weighted average prices in the third-party
reports would have no relevance.” Assuming that the third-party reports cover a significant
portion of your properties (92% in this case), comparison between weighted average prices in
the reports and benchmark prices can be valuable information for the public. It is the
staff’s position that

    U.S. Securities and Exchange Commission

    page 2

    August 18, 2010

    the weighted average prices used in the third-party report is a primary economic assumption
under Item 1202(a)(8)(v) of Regulation S-K. Please revise the report accordingly.

Response

Exhibits 99.1, 99.2 and 99.3 to the Form 10-K/A filed on this date disclose the relevant benchmark
prices and the weighted average prices. Such prices are included in the first paragraph of page
three in Exhibit 99.1, the table on page seven in Exhibit 99.2, and the table on page 16 of the
“Evaluation Procedure — Definitions and Methodology” section in Exhibit 99.3.

SEC Comment

    3.

    We note that the third party report by LaRoche discloses that your estimates are “in the
aggregate reasonable” but there is no statement that the third party’s estimates and yours are
within 10% of each other. Reasonable agreement is defined by Society of Petroleum Engineers
as within 10%. Since LaRoche has stated that it subscribes to the standards of the SPE, such
a statement is appropriate. Please amend your document to include, if true, this statement.

Response

Exhibit 99.1 to the Form 10-K/A filed on this date includes the statement that LaRoche’s estimates
and Devon’s estimates are within 10% of each other. This statement is included in the fourth
paragraph of page two in Exhibit 99.1.

SEC Comment

    4.

    We note the statement “Devon’s estimates of proved oil and gas reserves and future cash
flow...are in the aggregate reasonable and have been prepared in accordance with generally
accepted petroleum engineering and evaluation principles.” While we understand that there are
fundamentals of physics, mathematics and economics that are applied in the estimation of
reserves, we are not aware of an official industry compilation of such “generally accepted
petroleum engineering and evaluation principles.” With a view toward possible disclosure,
please explain to us the basis for concluding that such principles have been sufficiently
established so as to judge that the reserve information has been prepared in conformity with
such principles. Refer us to a compilation of these principles.

Response

The quoted passage from Exhibit 99.1 of our Form 10-K was originally derived from Exhibit “A” of
the SPE document titled “Standards Pertaining to the Estimating and Auditing of Oil and Gas
Reserves Information” (last updated on February 19, 2007).
Although Devon utilizes a multitude of references in the compilation of reserves estimates, there
is no singular list of “principles” that can be referenced. Consequently, the language in the
fourth paragraph of page two in Exhibit 99.1 to the Form 10-K/A filed on this date has been
modified as follows:

    U.S. Securities and Exchange Commission

    page 3

    August 18, 2010

    “Devon’s estimates of proved oil and gas reserves and future cash flow...are in the
aggregate reasonable, are within 10 percent of our numbers and have been prepared in
accordance with generally accepted petroleum engineering and evaluation methods and
procedures.”

In connection with the above responses to the staff’s comments, Devon acknowledges that:

    •

    Devon is responsible for the adequacy and accuracy of the disclosure in the
filings;

    •

    Staff comments or changes to disclosure in response to staff comments do not
foreclose the Commission from taking any action with respect to the filings; and

    •

    Devon may not assert staff comments as a defense in any proceeding initiated
by the Commission or any person under the federal securities laws of the United
States.

Sincerely,

    /s/  Danny J. Heatly

    Danny J. Heatly

    Senior Vice President — Accounting and

Chief Accounting Officer

August 4, 2010

Mr. Danny J. Heatly Vice President, Accounting Devon Energy Corporation 20 North Broadway
Oklahoma City, OK  73102-8260

Re: Devon Energy Corporation  Form 10-K for the Fiscal Year Ended December 31, 2009
Filed February 25, 2010 Schedule 14A Filed April 28, 2010 Response Letter Dated June 25, 2010 File No. 1-32318
 Dear Mr. Heatly:
 We have reviewed your filings and response letter and have the following comments.  In
some of our comments, we may ask you to provi de us with information so we may better
understand your disclosure.
 Please respond to this letter within ten business days by amending your filing, by
providing the requested information, or by advi sing us when you will provide the requested
response.  If you do not believe our comments apply to your fact s and circumstances or do not
believe an amendment is appropriate, pl ease tell us why in your response.
 After reviewing any amendment to your filing and the information you provide in
response to these comments, we ma y have additional comments.
        Exhibits 99.1, 99.2 and 99.3

     1. We direct your attention to prior comment one in our letter dated April 8, 2010.  Please obtain and file revised reports th at comply with such comment.

2. We note your response to prior comment six in our letter dated J une 11, 2010.  We do not
agree with your position that “…inclusion of weighted average prices in the third-party
reports would have no relevance.”  Assumi ng that the third pa rty reports cover a
significant portion of your pr operties (92% in this case), comparison between weighted
average prices in the reports and benchmark prices can be valuable information for the public.  It is the staff’s positi on that the weighted average pr ice used in the third-party
report is a primary economic assumption unde r Item 1202(a)(8)(v) of Regulation S-K.
Please revise the report accordingly.

Mr. Danny J. Heatly Devon Energy Corporation August 4, 2010 Page 2

3. We note that the third party report by LaRoche discloses th at your estimates are “in the
aggregate reasonable” but there is no statem ent that the third party’s estimates and yours
are within 10% of each other.  Reasonable ag reement is defined by Society of Petroleum
Engineers as within 10%.  Since LaRoche has st ated that it subscribes  to the standards of
the SPE, such a statement is appropriate.  Pl ease amend your document to include, if true,
this statement.

4. We note the statement “Devon’s estimates of pr oved oil and gas reserves and future cash
flow…are in the aggregate reasonable and have been prepared in accordance with generally accepted petroleum engineering and evaluation principles.”  While we
understand that there are fundamentals of phys ics, mathematics and economics that are
applied in the estimation of reserves, we are not aware of an official industry compilation
of such “generally accepted petroleum engineering and evaluation principles”.  With a view toward possible disclosure, please explai n to us the basis for concluding that such
principles have been sufficiently established so as to judge that the reserve information
has been prepared in conformity with such pr inciples.  Refer us to a compilation of these
principles.
 Closing Comments

 We urge all persons who are responsible for th e accuracy and adequacy of the disclosure
in the filing to be certain that the filing include s the information the Securities Exchange Act of
1934 and all applicable Exchange Act rules requir e.  Since the company and its management are
in possession of all facts relating to a company’s disclosure, they are responsible for the accuracy
and adequacy of the disclosures they have made.
  You may contact Ronald Wi nfrey, Petroleum Engineer, at (202) 551-3704 if you have
any questions regarding engine ering comments.  Please contac t Norman von Holtzendorff at
(202) 551-3237, Laura Nicholson at (202) 551-3584 or me at (202) 551-3740 with any other
questions.
Sincerely,
   /s/ H. Roger Schwall
H. Roger Schwall Assistant Director

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corresp

    Devon Energy Corporation

20 North Broadway

Oklahoma City, OK 73102-8260

    405 552 4702 Phone

405 552 7692 Fax

danny.heatly@dvn.com

June 25, 2010

Via EDGAR and Facsimile No. 703 813 6982

Attention: Mr. Norman Gholson, 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

Schedule 14A Filed April 28, 2010

Response Letters Dated April 14, 2010 and April 22, 2010

File No. 1-32318

Dear Mr. Schwall:

This letter responds to the staff’s comment letter dated June 11, 2010, regarding Devon Energy
Corporation’s Form 10-K for the year ended December 31, 2009, filed February 25, 2010, and its
Schedule 14A filed April 28, 2010 (the “Proxy
Statement”) (File No. 1-32318). Devon’s responses to
the staff’s comments are set forth below:

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

Preparation of Reserves Estimates and Reserves Audits, page 20

SEC Comment

    1.

    We note your response to prior comment four from our letter dated March 31, 2010, including
your statement that the Director of the Reserve Evaluation Group “has experience in reserves
estimation” for projects in specified areas. Please enhance your disclosure to provide
details regarding this experience. For example, please describe his role in such projects.
Also, we note that the disclosure on page 20 of your Annual Report on Form 10-K states that
the Director and key members of the Group have qualifications that “include any or all of” the
bulleted items on page 20. Please clarify which of these bulleted items apply specifically to
the Director. Provide us with a revised version of your proposed enhanced disclosure.

Response

We propose that our future disclosures will include the following language:

    The current Director of the Group has been involved with reserves estimation in accordance
with SEC definitions and guidance since 1987. He has experience in

    U.S. Securities and Exchange Commission

    page 2

    June 25, 2010

    reserves estimation for projects in the United States (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. During his career with Devon and others, he was the primary
reservoir engineer for projects including, but not limited to:

Hugoton Gas Field (Kansas)

Sho-Vel-Tum CO2 Flood (Oklahoma)

West Loco Hills Unit Waterflood and CO2 Flood (New Mexico)

Dagger Draw Oil Field (New Mexico)

Clarke Lake Gas Field (Alberta, Canada)

Panyu 4-2 and 5-1 Joint Development (Offshore South China Sea)

ACG Unit (Caspian Sea)

    As the primary reservoir engineer, he was responsible for reserves estimation on each of
these projects. These reserves estimates were utilized internally and for SEC filings.

    From 2003 to 2010, he has served as the reservoir engineering representative on our internal
Peer Review Team, reviewing reserves and resource estimates for projects including, but not
limited to:

Mobile Bay Norphlet Discoveries (Gulf of Mexico Shelf)

Cascade Lower Tertiary Development (Gulf of Mexico Deepwater)

Polvo Development (Campos Basin, Brazil)

    With regard to the penultimate sentence of your comment, we direct you to the first sentence of the
paragraph following the bulleted items on page 20 of our Form 10-K, which states, “The current
Director of the Group and the Group’s key members all have the qualifications listed above.”

Proved Oil, Natural Gas and NGL Reserves

Proved Undeveloped Reserves, page 23

SEC Comment

    2.

    We note your response to our prior comment five with regard to your proved undeveloped
reserves related to your Jackfish project. Please address the following additional comments
regarding this project:

    •

    Your response states that the development schedule for the Jackfish proved
undeveloped reserves extends through the year 2025. Please provide us with a summary
of the development plan(s) with narrations to explain the extended stages of the
Jackfish project(s).

    •

    Your response also refers to the Jackfish field as a single development
project. Please clarify whether you consider the development of the Jackfish field to
be one development project or several separate projects. We refer you to the
interpretation in Question 108.01 of the Oil and Gas

    U.S. Securities and Exchange Commission

    page 3

    June 25, 2010

    Rules Compliance and Disclosure Interpretations released on October 26, 2009.

    •

    Please address the consequences of early termination of the Jackfish project
in terms of loss capital verses [sic] reduced return on capital. Explain whether a
final investment decision has been made on the entire project, not just on Phase 1 of
the project. We refer you to the interpretation in Question 131.04 of the Oil and Gas
Rules Compliance and Disclosure Interpretations released on October 26, 2009.

    •

    Please provide us a detailed map of the Jackfish field which identifies the
portion of the field which you have or are in the process of developing and the
portion that remains undeveloped.

    •

    Please explain the significant terms of the Jackfish lease contract,
including the expiration date.

Response

Regarding your first bulleted comment, in order to maintain maximum plant capacity at both Jackfish
and Jackfish 2 central processing facilities, pad development has been staged over the life of the
projects. Table 1 and Table 2 below outline the proven undeveloped reserves for each project,
respectively, and the year in which development is expected to occur.

Table 1: Jackfish Reserves Summary at December 31, 2009

    Net PUD

    Development

    Reserves

    Development

    Status

    Reservoir

(MBbls)

    Year

    PUD

    Pad E

    13,034

    2010

    PUD

    Pad F

    13,269

    2011

    PUD

    Pad G

    12,460

    2012

    PUD

    Pad H

    11,141

    2014

    PUD

    Pad I

    13,370

    2015

    PUD

    Pad J

    13,400

    2016

    PUD

    Pad K

    11,194

    2017

    PUD

    Pad L

    11,776

    2018

    PUD

    Pad M

    5,838

    2019

    PUD

    Pad N

    9,646

    2021

    PUD

    Pad O

    11,081

    2022

    PUD

    Pad P

    8,647

    2023

    PUD

    Pad Q

    9,984

    2024

    PUD

    Pad R

    7,152

    2025

    PUD Total

    14 pads

    151,992

    U.S. Securities and Exchange Commission

    page 4

    June 25, 2010

Table 2: Jackfish 2 Reserves Summary at December 31, 2009

    Net PUD

    Development

    Reserves

    Development

    Status

    Reservoir

(MBbls)

    Year

    PUD

    PAD AA

    8,148

    2010

    PUD

    PAD BB

    15,348

    2010

    PUD

    PAD CC

    14,670

    2010

    PUD

    PAD DD

    9,771

    2010

    PUD

    PAD EE

    15,674

    2014

    PUD

    PAD FF

    12,240

    2013

    PUD

    PAD GG

    12,771

    2020

    PUD

    PAD HH

    13,736

    2019

    PUD

    PAD II

    7,704

    2025

    PUD

    PAD JJ

    14,223

    2016

    PUD

    PAD KK

    9,868

    2025

    PUD

    PAD LL

    7,455

    2024

    PUD

    PAD NN

    10,200

    2017

    PUD

    PAD OO

    11,723

    2022

    PUD

    PAD PP

    12,169

    2015

    PUD

    PAD SS

    12,765

    2021

    PUD

    PAD TT

    10,079

    2022

    PUD Total

    17 pads

    198,544

Regarding your second bulleted point, the development of both Jackfish and Jackfish 2 are
considered to be separate projects by the regulatory bodies within Canada, specifically, Alberta’s
Energy Resources Conservation Board, the Canada Revenue Agency and Alberta Environment.

Regarding your third bulleted point, as of December 31, 2009, neither the Jackfish project nor the
Jackfish 2 project have reached payout, and therefore neither have provided a return on investment
to date. Jackfish started production in late 2007, and Jackfish 2 is still in the construction
stage. Early termination of the Jackfish project
would result in 67% of the invested capital being unrecovered while an early termination of the
Jackfish 2 project would result in a loss of 100% of invested capital.

The final investment decision has been made for both Jackfish and Jackfish 2 projects and approved
by Devon’s Board of Directors as per sanction documents in June 2004 and June 2008, respectively.

Regarding your fourth bulleted point, the maps attached to this letter, entitled Area Map for
Jackfish and Area Map for Jackfish 2, outline the proven developed subsurface drainage areas that
are currently producing, and the proven undeveloped drainage areas. Please refer to Tables 1 and 2
above for development timing.

    U.S. Securities and Exchange Commission

    page 5

    June 25, 2010

Regarding your fifth bulleted point, the oilsands rights associated with PDP and PUD reserves
in the Jackfish area are leased under the provisions of Alberta Crown Oilsands Lease No. 7499050004
(primary term expiry in 2014), 7401010008 and 7401050038 (primary terms expiry in 2016).

The oilsands rights associated with PDP and PUD reserves in the Jackfish 2 area are leased under
the provisions of Alberta Crown Oilsands Lease No. 7401090041 and 7401090008 (primary term expiry
in 2016).

All leases in the Jackfish and Jackfish 2 areas shall be continued after the primary term based on
the production and reserves present in the leased lands, pursuant to the statutorily enacted
continuation mechanism and procedure for Alberta Crown oilsands leases.

Proved Reserves Cash Flow, page 24

SEC Comment

    3.

    We note your response to our prior comment seven which states that your year-end costs
included in future net revenues are estimated using averages of several prior months’ actual
costs. Tell us how your methodology complies with the guidance under ASC Topic 932-235-50-31B
that states these costs shall be computed by estimating the expenditures to be incurred in
developing and producing the proved oil and gas reserves at the end of the year, based on
year-end costs and assuming continuation of existing economic conditions. In this respect,
explain how your use of average actual costs incurred provides a basis which enables you to
determine current costs as of year-end.

Response

Our response deals separately with the two general types of costs included in the calculation of
future net revenues — (1) production costs and (2) development costs. Our methodology for
estimating the year-end production costs begins by using historical average costs. As noted in our
response of April 14, 2010, averages of prior months’ costs are used because not all costs are
incurred on a consistent month-to-month basis
throughout a year. Focusing only on year-end costs will result in omitting the costs of activities
that are incurred on a regular annual basis, but not necessarily at the end of the year.

Well workovers are a good example to illustrate this. Workovers are not conducted every month of a
year and they may not, and often do not, occur as of year-end. In fact, although Devon has
significant workover activity each year, very few workovers are performed on the last day of the
year. During the life of many reservoirs, workover activities are routinely performed to maintain
or stimulate production levels. Whether such workovers are performed in February, June or December,
by using averages throughout the year we include the appropriate amount of workover activity in our
cost estimates. The use of historical averages therefore ensures that our estimates of future
production costs include all cost activities that are expected to be necessary to produce our
proved reserves in the future.

    U.S. Securities and Exchange Commission

    page 6

    June 25, 2010

Unlike the benchmark commodity prices that are used to estimate year-end oil and gas prices in
the calculation of future cash inflows, there are no sources of similar year-end benchmark costs.
Generally, averages of several months’ actual costs are a good approximation of year-end costs.
However, as we develop and finalize our cost estimates, we examine cost trends in the weeks and
months leading up to year-end. We are always mindful of current cost trends, including divergent
trends in the geographic regions in which we operate. Operating costs can change rapidly,
particularly during periods of significant changes in commodity prices. We also have certain
operating costs, such as insurance, that are negotiated at set rates for specific periods of time.
Changes in these negotiated rates can occur at anytime throughout a year. Therefore, if cost
trends for specific operating activities at the end of the year have trended materially higher or
lower than earlier in the year, we will replace average costs with more-current estimates to
provide a fair representation of year-end costs.

Regarding development costs, such costs are estimated by examining the prior year’s cost structure
to determine average well costs for individual project areas. This cost structure is then adjusted
to account for known inflationary or deflationary changes in specific components of the cost
structure that have occurred in the weeks and months leading up to year-end. Items that may be
reviewed for significant contractual changes include, but are not limited to, drilling rigs,
stimulation services, cementing services, oilfield tubulars and other significant tangible items.

We believe the general use of average costs, with adjustments as necessary for end-of-year changes
that might occur, produces a fair representation of estimated production and development costs in
accordance with Topic 932. Our methodology, or a derivation of it, to estimate year-end costs is
widely used in the oil and gas industry. Representatives, including myself, from selected oil and
gas companies met with Mr. Wayne Carnall, Mr. Ronald Winfrey and other SEC staff members on July
16, 2009 to discuss the FASB’s proposed amendments to Topic 932 and other issues related to the
SEC’s Modernization of Oil and Gas Reporting. During that meeting, it was discussed that while the
SEC’s new rules changed the historical methodology to calculate prices used to estimate future cash
inflows, they did not change the methodology to calculate the
related future costs. A discussion of how companies have historically estimated future costs
included an acknowledgement by the SEC representatives that companies’ estimates of year-end costs
have generally included the use of historical averages. No SEC staff members in attendance
proposed that the use of averages to estimate year-end costs would not continue to be an acceptable
method to estimate year-end costs.

Exhibits 99.1, 99.2 and 99.3

SEC Comment

    4.

    We note your response to prior comment one from our letter dated April 8, 2010. We may have
further comments after the completion of our discussions with Ryder Scott Company.

Response

    We will await any further comments from you on this matter.

    U.S. Securities and Exchange Commission

    page 7

    June 25, 2010

SEC Comment

    5.

    We note your response to prior comment eight from our letter dated March 31, 2010, including
your statement that “We will ensure that in our future filings such third-party reports
include a declarative statement that is more easily identified.” Please provide us with an
example of the enhanced disclosure.

Response

We propose to include the following language in the third-party reports in our future filings:

    The assumptions, data, methods, and procedures are appropriate for the purposes served by the
report.

SEC Comment

    6.

    Please obtain revised

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549-4628

DIVISION OF
CORPORATION FINANCE

             June 11, 2010
Via U.S. Mail and Fax (405) 552-4550

Mr. Danny J. Heatly
Vice President, Accounting Devon Energy Corporation 20 North Broadway Oklahoma City, Oklahoma 73102-8260
 Re: Devon Energy Corporation
  Form 10-K for the Fiscal Year Ended December 31, 2009
Filed February 25, 2010 Schedule 14A Filed April 28, 2010 Response Letters Dated April 14, 2010 and April 22, 2010
  File No. 1-32318

 Dear Mr. Heatly:
We have reviewed your filings and response letters and have the following
comments.  In some of our comments, we may ask you to provide us with information so we may better understand your disclosure.
 Please respond to this letter within ten business days by amending your filing, by
providing the requested information, or by advising us when you will provide the requested response.  If you do not believe our comments apply to your facts and circumstances or do not believe an amendment is appropriate, please tell us why in your response.
 After reviewing any amendment to your filing and the information you provide in
response to these comments, we may have additional comments.
Form 10-K for the Fiscal Year Ended December 31, 2009

Mr. Danny Heatly
Devon Energy Corporation
June 11, 2010 Page 2

 Preparation of Reserves Estimates and Reserves Audits, page 20

 1. We note your response to prior comment four from our letter dated March 31, 2010, including your statement that the Director of the Reserve Evaluation Group “has experience in reserves estimation” for projects in specified areas.  Please enhance your disclosure to provide details regarding this experience.  For example, please describe his role in such projects.  Also, we note that the disclosure on page 20 of your Annual Report on Form 10-K states that the Director and key members of the Group have qualifications that “include any or all of” the bulleted items on page 20.  Please clarify which of these bulleted items apply specifically to the Director.  Provi de us with a revised version of your
proposed enhanced disclosure.
 Proved Oil, Natural Gas and NGL Reserves

 Proved Undeveloped Reserves, page 23

 2. We note your response to our prior comment five with regard to your proved undeveloped reserves related to your Jackfish project.  Please address the following additional comments regarding this project:

• Your response states that the development schedule for the Jackfish proved undeveloped reserves extends through the year 2025.  Please provide us with a summary of the development plan(s) with narrations to explain the extended stages of the Jackfish project(s).
• Your response also refers to the Jackfish field as a single development project.  Please clarify whether you consider the development of the Jackfish field to be one development project or several separate projects.  We refer you to the interpretation in Question 108.01 of the Oil and Gas Rules Compliance and Disclosure Interpretations released on October 26, 2009.
• Please address the consequences of early termination of the Jackfish project in terms of loss capital verses reduced return on capital.  Explain whether a final investment decision has been made on the entire project, not just on Phase I of the project.  We refer you to the interpretation in Question 131.04 of the Oil and Gas Rules Compliance and Disclosure Interpretations released on October 26, 2009.
• Please provide us a detailed map of the Jackfish field which identifies the portion of the field which you have or are in the process of developing and the portion that remains undeveloped.
• Please explain the significant terms of the Jackfish lease contract, including the expiration date.

Mr. Danny Heatly
Devon Energy Corporation
June 11, 2010 Page 3

Proved Reserves Cash Flows, page 24

3. We note your response to our prior comment seven which states that your year-
end costs included in future net revenues are estimated using averages of several prior months’ actual costs.  Tell us how your methodology complies with the guidance under ASC Topic 932-235-50-31B that states these costs shall be computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions.  In this respect, explain how your use of average actual costs incurred provides a basis which enables you to determine current costs as of your year-end.
 Exhibits 99.1, 99.2 and 99.3

 4. We note your response to prior comment one from our letter dated April 8, 2010.  We may have further comments after the completion of our discussions with Ryder Scott Company.
 5. We note your response to prior comment eight from our letter dated March 31, 2010, including your statement that “We will ensure that in our future filings such third-party reports include a declarative statement that is more easily identified.”  Please provide us with an example of the enhanced disclosure.
 6. Please obtain revised reports that disclose the relevant benchmark prices and weighted average prices from the total company reserve report.  See Item 1202(a)(8)(v) of Regulation S-K.  Such weighted average prices should be provided by the geographic area required to be provided in the reserves table pursuant to Item 1202(a)(2) of Regulation S-K.  We note that the report in Exhibit 99.1 states the benchmark prices but not the adjusted weighted average prices from the relevant reserve report; Exhibit 99.2 does not state either the benchmark prices or the adjusted weighted average prices; and Exhibit 99.3 refers to “hydrocarbon prices … in affect [sic] at December 31, 2009.”  Also, please enhance the disclosure in the Exhibit 99.3 report to clarify the methodology used for calculating the prices. For example, the reference at page 16 of such report to the hydrocarbon prices in effect at December 31, 2009 does not appear to comply with Rule 4-10(a)(22) of Regulation S-X.

Mr. Danny Heatly
Devon Energy Corporation June 11, 2010 Page 4

Schedule 14A Filed April 28, 2010
 7. We note your disclosure in response to Item 402(s) of Regulation S-K, and specifically your statement on page 32 that “the Committee believes the total executive compensation program does not encourage executives to take unnecessary or excessive risk.”  Please describe the process you undertook to reach this conclusion.
 Related Party Transactions, page 14

 8. We note your disclosure regarding related party transactions.  Please provide the disclosure required by Item 404(b) of Regulation S-K.
 Compensation Discussion and Analysis, page 21

 Compensation Decisions in 2009, page 29

 Long-Term Incentives, page 31

 9. We note your disclosure regarding the approval of long-term equity grants for 2009.  Please expand your disclosure to describe all the “other factors” that your compensation committee considered with respect to such grants, or tell us why such other factors were not material.

We urge all persons who are responsible for the accuracy and adequacy of the
disclosure in the filing to be certain that the filing includes the information the Securities Exchange Act of 1934 and all applicable Exchange Act rules require.  Since the company and its management are in possession of all facts relating to a company’s disclosure, they are responsible for the accuracy and adequacy of the disclosures they have made.

 You may contact Bob Carroll at (202) 551-3362, or Chris White at (202) 551-3717 if you have questions regarding comments on the financial statements and related matters.  You may contact Norman Gholson at (202) 551-3237, Laura Nicholson at (202)
551-3584 or me at (202) 551-3740 with any other questions.
      S i n c e r e l y ,                            H .  R o g e r  S c h w a l l        A s s i s t a n t  D i r e c t o r

CORRESP
1
filename1.htm

corresp

    Devon Energy Corporation

    405 552 4702 Phone

    20 North Broadway

    405 552 7692 Fax

    Oklahoma City, OK 73102-8260

    danny.heatly@dvn.com

April 22, 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 April 8, 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 response to the staff’s comment is set forth below:

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

Exhibits 99.1, 99.2 and 99.3

SEC Comment

    1.

    We note that each of the reports included in the above-referenced exhibits includes language
that could be interpreted to limit reliance by investors on such report. For example, the
closing paragraph in Exhibit 99.2 states, in part, that the report “was prepared for the
exclusive use and sole benefit of Devon Energy Corporation and may not be put to other use
without our prior written consent for such use.” We note that the penultimate paragraph in
Exhibit 99.1 and the closing paragraph on page 2 of Exhibit 99.3 include language that could
similarly be interpreted to limit reliance by investors. As Item 1202(a)(8) of Regulation S-K
requires these reports, please obtain and file a revised version of each such report which
retains no language that could suggest either a limited audience or a limit on potential
investor reliance.

Response

We have contacted all three third-party preparers regarding your comment on the language contained
in their reports. We have been advised that representatives of Ryder Scott Company contacted you
on April 13, 2010, regarding this same comment provided to other Ryder Scott clients. It is our
understanding that future discussions are planned between representatives of Ryder Scott, Mr. Ron
Winfrey and you to discuss potential changes in the language of the Ryder Scott report. The other
two third-party preparers

    U.S. Securities and Exchange Commission

April 22, 2010

    page 2

are also aware of your planned discussions with Ryder Scott. We and the third-party preparers will
await your future discussions with Ryder Scott and proceed based upon the outcome of such
discussions.

In connection with the above responses to the staff’s comments, Devon acknowledges that:

    •

    Devon is responsible for the adequacy and accuracy of the disclosure in the
filing;

    •

    Staff comments or changes to disclosure in response to staff comments do not
foreclose the Commission from taking any action with respect to the filing; and

    •

    Devon may not assert staff comments as a defense in any proceeding initiated
by the Commission or any person under the federal securities laws of the United
States.

Sincerely,

/s/ Danny J. Heatly

Danny J. Heatly

Senior Vice President — Accounting and

Chief Accounting Officer

CORRESP
1
filename1.htm

corresp

    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

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549-4628

DIVISION OF
CORPORATION FINANCE

           April 8, 2010
Via U.S. Mail and Fax (405) 552-4550

Mr. Danny J. Heatly
Vice President, Accounting Devon Energy Corporation 20 North Broadway Oklahoma City, Oklahoma 73102-8260
 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. Heatly:
We have reviewed your filings and have the following additional comment to our
letter dated March 31, 2010.  Where indicated, we think you should revise your documents in response to this comment.  If you disagree, we will consider your explanation as to why our comment is inapplicable or a revision is unnecessary.  Please be as detailed as necessary in your explanation.  In some of our comments, we may ask you to provide us with information so we may better understand your disclosure.  After reviewing this information, we may raise additional comments.

 Please understand that the purpose of our review process is to assist you in your compliance with the applicable disclosure requirements and to enhance the overall disclosure in your filing.  We look forward to working with you in these respects.  We welcome any questions you may have about our comments or any other aspect of our review.  Feel free to call us at the telephone numbers listed at the end of this letter.       Form 10-K for the Fiscal Year Ended December 31, 2009

Mr. Danny Heatly
Devon Energy Corporation
April 8, 2010 Page 2

 Exhibits 99.1, 99.2 and 99.3

1. We note that each of the reports included in the above-referenced exhibits includes language that could be interpreted to limit reliance by investors on such report.  For example, the closing paragraph in Exhibit 99.2 states, in part, that the report “was prepared for the exclusive use and sole benefit of Devon Energy Corporation and may not be put to other use without our prior written consent for such use.”  We note that the penultimate paragraph in Exhibit 99.1 and the closing paragraph on page 2 of Exhibit 99.3 include language that could similarly be interpreted to limit reliance by investors.  As Item 1202(a)(8) of Regula tion S-K requires these reports, please obtain
and file a revised version of each such report which retains no language that could suggest either a limited audience or a limit on potential investor reliance.
 Closing Comments

 As appropriate, please amend your filing and respond to these comments within
10 business days or tell us when you will provide us with a response.  You may wish to provide us with marked copies of the amendment to expedite our review.  Please furnish a cover letter with your amendment that keys your responses to our comments and provides any requested information.  Detailed cover letters greatly facilitate our review.  Please understand that we may have additional comments after reviewing your amendment and responses to our comments.

  We urge all persons who are responsible for the accuracy and adequacy of the disclosure in the filing to be certain that the filing includes all information required under the Securities Exchange Act of 1934 and that they have provided all information investors require for an informed investment decision.  Since the company and its management are in possession of all facts relating to a company’s disclosure, they are responsible for the accuracy and adequacy of the disclosures they have made.     In connection with responding to our comments, please provide, in writing, a statement from the company acknowledging that:  ‚ the company is responsible for the adequacy and accuracy of the disclosure in the filing;
‚ staff comments or changes to disclosure in response to staff comments do not foreclose the Commission from taking any action with respect to the filing; and
‚ the company may not assert staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States.

Mr. Danny Heatly
Devon Energy Corporation April 8, 2010 Page 3

In addition, please be advised that the Division of Enforcement has access to all
information you provide to the staff of the Di vision of Corporation Finance in our review
of your filing or in response to our comments on your filing.     You may contact Bob Carroll at (202) 551-3362, or Chris White at (202) 551-3717 if you have questions regarding comments on the financial statements and related matters.  You may contact Norman Gholson at (202) 551-3237, Laura Nicholson at (202)
551-3584 or me at (202) 551-3740 with any other questions.
      S i n c e r e l y ,                            H .  R o g e r  S c h w a l l        A s s i s t a n t  D i r e c t o r

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549-7010

DIVISION OF
CORPORATION FINANCE MAIL STOP 7010

          March 31, 2010
Via U.S. Mail and Fax (405) 552-4550

Mr. Danny J. Heatly
Vice President, Accounting Devon Energy Corporation 20 North Broadway Oklahoma City, Oklahoma 73102-8260
 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. Heatly:
We have reviewed your filings and have the following comments.  Where
indicated, we think you should revise your documents in response to these comments.  If you disagree, we will consider your explanation as to why our comment is inapplicable or a revision is unnecessary.  Please be as detailed as necessary in your explanation.  In some of our comments, we may ask you to provide us with information so we may better understand your disclosure.  After reviewing this information, we may raise additional comments.

 Please understand that the purpose of our review process is to assist you in your compliance with the applicable disclosure requirements and to enhance the overall disclosure in your filing.  We look forward to working with you in these respects.  We welcome any questions you may have about our comments or any other aspect of our review.  Feel free to call us at the telephone numbers listed at the end of this letter.       General

Mr. Danny Heatly
Devon Energy Corporation
March 31, 2010 Page 2

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

 Presentation of Discontinued Operations, page 6

 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.
 Oil, Natural Gas and NGL Marketing, page 7

 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.

Preparation of Reserves Estimates and Reserves Audits, page 20

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.”
 Proved Oil, Natural Gas and NGL Reserves

 Proved Undeveloped Reserves, page 23

 5. You state that 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 additional

Mr. Danny Heatly
Devon Energy Corporation
March 31, 2010 Page 3

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.

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.

Proved Reserves Cash Flows, page 24

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.
 Exhibits 99.2 and 99.3

 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.
 Closing Comments

 As appropriate, please amend your filing and respond to these comments within
10 business days or tell us when you will provide us with a response.  You may wish to provide us with marked copies of the amendment to expedite our review.  Please furnish a cover letter with your amendment that keys your responses to our comments and provides any requested information.  Detailed cover letters greatly facilitate our review.  Please understand that we may have additional comments after reviewing your amendment and responses to our comments.

  We urge all persons who are responsible for the accuracy and adequacy of the disclosure in the filing to be certain that the filing includes all information required under the Securities Exchange Act of 1934 and that they have provided all information investors require for an informed investment decision.  Since the company and its management are in possession of all facts relating to a company’s disclosure, they are responsible for the accuracy and adequacy of the disclosures they have made.

Mr. Danny Heatly
Devon Energy Corporation March 31, 2010 Page 4

  In connection with responding to our comments, please provide, in writing, a statement from the company acknowledging that:  ‚ the company is responsible for the adequacy and accuracy of the disclosure in the filing;
‚ staff comments or changes to disclosure in response to staff comments do not foreclose the Commission from taking any action with respect to the filing; and
‚ the company may not assert staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States.

In addition, please be advised that the Division of Enforcement has access to all
information you provide to the staff of the Di vision of Corporation Finance in our review
of your filing or in response to our comments on your filing.     You may contact Bob Carroll at (202) 551-3362, or Chris White at (202) 551-3717 if you have questions regarding comments on the financial statements and related matters.  You may contact Norman Gholson at (202) 551-3237, Laura Nicholson at (202)
551-3584 or me at (202) 551-3740 with any other questions.
      S i n c e r e l y ,                            H .  R o g e r  S c h w a l l        A s s i s t a n t  D i r e c t o r

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

       DIVISION OF
CORPORATION FINANCE

Mail Stop 7010
June 17, 2008
Via U.S. Mail and Fax (405) 552-4550

Mr. Danny J. Heatly
Vice President, Accounting Devon Energy Corporation 20 North Broadway Oklahoma City, Oklahoma 79102
 Re: Devon Energy Corporation
  Form 10-K for the Fiscal Year Ended December 31, 2007
Filed February 28, 2008
  File No. 1-32318

  Form 10-Q for the Period Ended March 31, 2008
  Filed May 8, 2008

  We have completed our review of your Form 10-K and related filings and do not, at this time, have any further comments.             S i n c e r e l y ,                      /s/ Chris White                  C h r i s  W h i t e          B r a n c h  C h i e f

CORRESP
1
filename1.htm

corresp

    Devon Energy Corporation

20 North Broadway

Oklahoma City, OK 73102-8260

    405 552 4702 Phone

405 552 7692 Fax

danny.heatly@dvn.com

June 5, 2008

Via EDGAR and Facsimile No. 202 772 9368

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, 2007

Filed February 28, 2008

File No. 1-32318

Form 10-Q for the Period Ended March 31, 2008

Filed May 8, 2008

Dear Mr. Schwall:

This letter responds to the staff’s comment letter dated May 27, 2008, regarding Devon Energy
Corporation’s Form 10-K for the year ended December 31, 2007, filed February 28, 2008 (File No.
1-32318) and its Form 10-Q for the period ended March 31, 2008, filed May 8, 2008. Devon’s
responses to the staff’s comments are set forth below:

Form 10-K for the year ended December 31, 2007

Operation of Properties, page 22

SEC Comment

    1.

    We note you receive reimbursement for direct expenses incurred in the performance of your
duties as well as other types of reimbursements, and record these as a reduction of general
and administrative expense. Please tell us your consideration of Rule 4-10(c)(6)(iv) of
Regulation S-X in your accounting for these reimbursements and tell us why they should not be
credited to the full cost pool.

Response

It is common industry practice to offset monthly reimbursements known as “COPAS reimbursements”
against the related costs actually incurred. If the amount of the reimbursements exceed the actual
costs incurred, the excess amount is recorded as a reduction to the full cost pool to avoid
recognition of income from the reimbursements.

    U.S. Securities and Exchange Commission

June 5, 2008

    page 2

As part of our disclosure of Results of Oil and Gas Producing Operations in Note 15 on pages
117-119, we have included the general and administrative expenses directly related to oil and gas
producing activities. These amounts are net of our COPAS reimbursements as well as amounts
capitalized pursuant to the full cost method of accounting. As indicated in our disclosures, the
actual related costs incurred in each of the years shown exceeded the amount of our reimbursements.
If the reimbursements had been greater than our actual expenses, the excess would have been
recorded as a reduction to the full cost pool.

Exhibit 32.2

SEC Comment

    2.

    Please revise and re-file this exhibit to reflect the correct date of the report that it
refers to. The certificate filed refers to the Form 10-K for the period ending December 31,
2006.

Response

We have been advised today by the Commission’s legal staff that correcting the typographical error
in Exhibit 32.2 will require us to file the entire contents of the original Form 10-K in a Form
10-K/A. Repeating the entire contents of the original Form 10-K will require us to obtain
currently-dated consents from our independent accountants and our three independent petroleum
consulting firms. We will file a Form 10-K/A as soon as possible once these consents are obtained.
However, we may or may not be able to file the Form 10-K/A within ten business days from the date
of your letter.

Form 10-Q for the period ended March 31, 2008

Note 5. Fair Value Measurements, page 15

SEC Comment

    3.

    We note the reclassification of your auction rate securities from short-term to long-term
investments. We also note your conclusion that the securities are not currently impaired.
Citing the accounting literature used, tell us and disclose how you have concluded no
impairment exists as of March 31, 2008.

Response

The accounting for our auction rate securities was based on the principles included in SFAS No. 115
and SFAS No. 157. Since their original acquisition, these securities have been, and continue to
be, classified as “available-for-sale” securities as defined under SFAS No. 115. SFAS No. 115
requires these securities to be measured at fair value.

The fair values of our auction rate securities are estimated pursuant to the requirements set forth
in SFAS No. 157, which Devon adopted as of January 1, 2007. Prior to February 8, 2008, an active
market existed for these securities. Accordingly, the fair values of the securities as of December
31, 2007, were based on “Level 1 inputs” as that term is defined in SFAS No. 157. Beginning on
February 8, 2008, the auction mechanism that provided liquidity to these securities began to fail.
As a result, a market for these securities ceased to exist at that time.

Paragraph 7 of SFAS No. 157 states that “a fair value measurement assumes that the asset or
liability is exchanged in an orderly transaction,” and defines an orderly transaction as one that
“assumes exposure to the market for a period prior to the

    U.S. Securities and Exchange Commission

June 5, 2008

    page 3

measurement date to allow for marketing activities that are usual and customary.” Because there
were less than eight weeks between the time that the markets ceased to exist and the end of the
1st quarter, we do not believe this is sufficient time to allow for the creation of an
alternative market with usual and customary marketing activities for these securities.

Accordingly, and as disclosed in Note 5 to our 10-Q, the fair values of our auction rate
securities were estimated using significant unobservable inputs (Level 3) in accordance with SFAS
No. 157. Our fair value estimates were determined using an income-based valuation technique developed
with various inputs including the following:

Credit Risk Our auction rate securities are AAA rated by one or more of the three
major rating agencies—S&P, Moody’s and Fitch. Furthermore, our securities have maintained
these AAA ratings throughout recent months when various sectors of the financial markets have
experienced higher levels of credit and liquidity issues.

Collateral and Performance We expect full repayment of the par value of our
securities. Our auction rate securities are collateralized by student loans which are
substantially guaranteed by the United States government. As of March 31, 2008, $144 million,
or approximately 95%, of our securities were collateralized by student loans guaranteed under
the Federal Family Education Loan Program (FFELP).

For the $144 million of securities collateralized by loans under FFELP, the value of the loans
that serve as collateral averaged 106% of the par value of our auction rate securities. For
the approximately 5% of securities that were not under FFELP, the collateral ratios averaged
117%. These collateral coverage ratios are based on data obtained from the most recently filed
quarterly servicing reports.

Interest Rates We have collected all accrued interest to date for our securities. Our
securities bear interest at market rates primarily based on United States Treasury rates.

Par Value Redemptions We also considered the fact that $23 million of our $152 million
of auction rate securities (or 15%) were called at par value prior to the filing of our
1st quarter 10-Q and subsequently redeemed on May 21, 2008. With no market currently
in existence for student loan backed auction rate securities, this redemption at par value
represents the best available current evidence of the value of the remaining $129 million of
securities, which are substantially similar to the $23 million that was redeemed.

In addition to the securities that were called at par, $1.3 million of partial redemptions were
received in May 2008 related to principal payments on the student loans. These redemptions
occur periodically throughout the lives of the auction rate securities, and are paid at par
value.

No Impact on Devon’s Liquidity Our auction rate securities at March 31, 2008,
represented less than 1% of our total assets at that date. With $2.2 billion of operating cash
flow generated in the 1st quarter of 2008, and over $2 billion of pending proceeds
from previously disclosed sales of discontinued operations, we are not in the position of
needing to liquidate the $152 million of auction rate securities under forced liquidation or
distress sale scenarios in order to satisfy our

    U.S. Securities and Exchange Commission

June 5, 2008

    page 4

liquidity requirements. As disclosed in Note 1 of our 1st quarter 10-Q, we have
the ability to hold these securities until maturity, and this ability was considered in our
overall assessment of the fair value measurement of the auction rate securities.

Based on the factors discussed above, we believe it is probable we will continue to collect the
contractual interest payments and par value maturity payments of our auction rate securities, and
that the par value of our securities was an appropriate estimate of fair value as of the March 31,
2008 measurement date. Therefore, we concluded no impairment of our securities existed on that
date.

In connection with the above responses to the staff’s comments, Devon acknowledges that:

    •

    Devon is responsible for the adequacy and accuracy of the disclosure in the
filings;

    •

    Staff comments or changes to disclosure in response to staff comments do not
foreclose the Commission from taking any action with respect to the filings; and

    •

    Devon may not assert staff comments as a defense in any proceeding initiated by
the Commission or any person under the federal securities laws of the United States.

Sincerely,

Danny J. Heatly

Vice President — Accounting

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549-7010

DIVISION OF
CORPORATION FINANCE MAIL STOP 7010
        May 27, 2008

Via U.S. Mail and Fax (405) 552-4550

Mr. Danny J. Heatly
Vice President, Accounting Devon Energy Corporation 20 North Broadway Oklahoma City, Oklahoma 79102
 Re: Devon Energy Corporation
  Form 10-K for the Fiscal Year Ended December 31, 2007
Filed February 28, 2008
  File No. 1-32318

  Form 10-Q for the Period Ended March 31, 2008
  Filed May 8, 2008

Dear Mr. Heatly:
We have reviewed your filings and have the following comments.  Where
indicated, we think you should revise your documents in response to these comments.  If you disagree, we will consider your explanation as to why our comment is inapplicable or a revision is unnecessary.  Please be as detailed as necessary in your explanation.  In some of our comments, we may ask you to provide us with information so we may better understand your disclosure.  After reviewing this information, we may raise additional comments.

 Please understand that the purpose of our review process is to assist you in your compliance with the applicable disclosure requirements and to enhance the overall disclosure in your filing.  We look forward to working with you in these respects.  We welcome any questions you may have about our comments or any other aspect of our review.  Feel free to call us at the telephone numbers listed at the end of this letter.         Form 10-K for the year ended December 31, 2007

Mr. Danny Heatly
Devon Energy Corporation May 27, 2008 Page 2

 Operation of Properties, page 22

 1. We note you receive reimbursement for direct expenses incurred in the
performance of your duties as well as other types of reimbursements, and record these as a reduction of general and administrative expense.  Please tell us your consideration of Rule 4-10(c)(6)(iv) of Regulation S-X in your accounting for
these reimbursements and tell us why they should not be credited to the full cost pool.

Exhibit 32.2
 2. Please revise and re-file this exhibit to reflect the correct date of the report that it
refers to.  The certificate filed refers to the Form 10-K for the period ending December 31, 2006.
 Form 10-Q for the period ended March 31, 2008

 Note 5. Fair Value Measurements, page 15

 3. We note the reclassification of your auction rate securities from short-term to
long-term investments.  We also note your conclusion that the securities are not currently impaired.  Citing the accounting literature used, tell us and disclose how you have concluded no impairment exists as of March 31, 2008.
 Closing Comments

 As appropriate, please amend your filing and respond to these comments within
10 business days or tell us when you will provide us with a response.  You may wish to provide us with marked copies of the amendment to expedite our review.  Please furnish a cover letter with your amendment that keys your responses to our comments and provides any requested information.  Detailed cover letters greatly facilitate our review.  Please understand that we may have additional comments after reviewing your amendment and responses to our comments.

  We urge all persons who are responsible for the accuracy and adequacy of the disclosure in the filing to be certain that the filing includes all information required under the Securities Exchange Act of 1934 and that they have provided all information investors require for an informed investment decision.  Since the company and its management are in possession of all facts relating to a company’s disclosure, they are responsible for the accuracy and adequacy of the disclosures they have made.

Mr. Danny Heatly
Devon Energy Corporation May 27, 2008 Page 3

 In connection with responding to our comments, please provide, in writing, a statement from the company acknowledging that:  ‚ the company is responsible for the adequacy and accuracy of the disclosure in the
filing;
‚ staff comments or changes to disclosure in response to staff comments do not
foreclose the Commission from taking any action with respect to the filing; and
‚ the company may not assert staff comments as a defense in any proceeding initiated
by the Commission or any person under the federal securities laws of the United States.

In addition, please be advised that the Division of Enforcement has access to all
information you provide to the staff of the Di vision of Corporation Finance in our review
of your filing or in response to our comments on your filing.     You may contact Bob Carroll at (202) 551-3362, or Chris White at (202) 551-3717 if you have questions regarding comments on the financial statements and related matters.  You may contact Donna Levy at (202) 551-3292 or me at (202) 551-3740 with
any other questions.
      S i n c e r e l y ,                   /s/ H. Roger Schwall        H .  R o g e r  S c h w a l l        A s s i s t a n t  D i r e c t o r

February 21, 2008 Mail Stop 7010
By U.S. Mail and facsimile to (405)552-8171

J. Larry Nichols Chairman and Chief Executive Officer 20 N Broadway Suite 1500 Oklahoma City, Oklahoma 73102
 Re:  Devon Energy Corporation  Definitive Proxy Statement on Schedule 14A  Filed April 27, 2007
File No. 001-32318
  Dear Mr. Nichols:
 We have completed our review of your executive compensation and related
disclosure, and we have no further comments at this time.

 Please note that the company is responsib le for the adequacy and accuracy of the
disclosure in its filing.  We  are not approving any proposed  disclosure you may have
included in your response letters  or any disclosure you includ e in your future filings in
response to our comments.

If you have any further questions regardi ng our review of your filing, please call
me at (202) 551-3687.           S i n c e r e l y ,            C a r m e n  M o n c a d a - T e r r y           A t t o r n e y  A d v i s o r

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    Devon Energy Corporation

20 North Broadway

Oklahoma City, Oklahoma 73102-8260

    Janice A. Dobbs

Corporate Secretary and

Manager, Corporate Governance

    Direct:
    (405) 552-7844

    Fax:
    (405) 552-8171

January 11, 2008

Via EDGAR and

Facsimile No. 202-772-9220

Division of Corporation Finance

Carmen Moncada-Terry

Attorney Advisor

U.S. Securities and Exchange Commission

Division of Corporation Finance

100 F Street, N.E.

Washington, D.C. 20549

    Re:

    Devon Energy Corporation

Definitive 14A

Filed April 27, 2007

File No. 001-32318

Dear Ms. Moncada-Terry:

This letter responds to the staff’s comment letter of December 14, 2007, regarding the definitive
proxy statement on Schedule 14A of Devon Energy Corporation (the “Company”), filed April 27, 2007
(File No. 001-32318) (the “Definitive 14A”). Reference is also made to our response letter dated
October 3, 2007 (the “Original Response Letter”), which provided our responses to the staff’s
comment letter dated August 21, 2007 regarding the Definitive 14A.

Annual Incentive Plan, page 22

SEC Comment

    1.

    We note your response to prior comment 6 [reproduced below] and reissue the comment.
You assert that the undisclosed targets are not material to your executive compensation
decisions, yet under “Pay for Performance,” you state that you believe that an executive
officer’s compensation should be tied to your overall performance, the performance of the
officer’s business function and area, and individual performance. To that end, you
evaluate performance by setting goals, including financial and growth goals, the focus on
profitability and operating performance. Although the targets provide a framework for your

U.S. Securities and Exchange Commission

January 11, 2008

Page 2

    compensation decisions, it is unclear why you believe that the targets are not material
to such decisions.

    Prior Comment 6

    You disclose that specific targets and maximum award levels are not
assigned, but you also indicate that an executive’s contribution to
meeting “specific financial and other key goals” established for the
company are considered in determining incentive awards. Moreover, you
state that although the approach to annual incentives is “not strictly
formulaic, it is highly structured...” You also disclose that an
executive’s performance is rated against approved goals. Your
disclosure suggests that specific quantitative targets as well as other
factors are considered. Please revise to disclose all quantitative and
qualitative targets both on an aggregate basis and with respect to each
individual officer’s contribution, as measured or determined by the
committee during the last fiscal year. To the extent you believe that
disclosure of these targets is not required because it would result in
competitive harm such that you may exclude this information under
Instruction 4 to Item 402(b) of Regulation S-K, please provide on a
supplemental basis a detailed explanation supporting your conclusion.
Please also disclose how difficult it will be for the named executive
officers or how likely it will be for you to achieve the undisclosed
target levels or other factors.

Response

To the extent that the Staff has interpreted the Company’s existing disclosures and responses in
the Original Response Letter to mean that performance targets “provide a framework” for the
Company’s compensation decisions, this interpretation is inconsistent with the methods employed in
determining 2006 annual bonuses. As noted in our Original Response Letter, the Company’s annual
bonus program is flexible, non-formulaic and highly discretionary.

The Company’s performance goals cover a large number of both quantitative and qualitative
performance targets (in fiscal 2006, there were 24 separate performance goals). Consistent with
the flexible nature of the annual bonus program, the compensation committee does not assign any
specific weight to any particular performance goal nor is any specific weight assigned to the
performance goals in the aggregate. In determining what bonuses to pay, the compensation committee
considers not only the Company’s performance during the year (including performance as compared to
the quantitative and qualitative goals set at the beginning of the year), but also any other
factors and considerations deemed relevant by the compensation committee in its discretion, which
may include market and economic trends and forces, extraordinary events, unanticipated
developments, and other relevant factors. In short, the compensation committee analyzes the total
mix of available information (including performance against any quantitative performance goals) on
a qualitative, rather than quantitative, basis in making bonus determinations.

U.S. Securities and Exchange Commission

January 11, 2008

Page 3

For the reasons stated above, given the highly subjective nature of the annual bonus determination,
we continue to believe the Company’s existing disclosures in the Definitive 14A, which set forth
the key categories of performance goals and qualitatively describe the Company’s actual performance
as compared to such goals, provide investors with the material information necessary to understand
how the 2006 bonuses were actually determined by the compensation committee. Further, the
disclosure and discussion of immaterial factors may cause investors to place undue weight on the
consideration of those factors in a manner that is clearly inconsistent with the process by which
annual bonuses were actually determined.

Notwithstanding the foregoing, we acknowledge the Staff’s concern, and, in its future filings, the
Company will disclose a performance target to the extent that the achievement of any such
performance target is a material factor in the determination of an executive’s annual bonus and the
disclosure of such target would not cause the Company competitive harm.

Please direct any comments or questions you may have to the undersigned at 405-552-7844.

    Sincerely,

    /s/  Janice A. Dobbs

    Janice A. Dobbs

Corporate Secretary and Manager,

Corporate Governance

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Devon Energy Corporation

20 North Broadway

Oklahoma City, Oklahoma 73102-8260

Janice A. Dobbs

Corporate Secretary

(405) 552-7844

December 19, 2007

Via Facsimile (202) 772-9368

Securities and Exchange Commission

Division of Corporation Finance – Mail Stop 7010

100 F Street, N.E.

Washington, D.C. 20549-7010

Attention: Carmen Moncada-Terry

    Re:

    Devon Energy Corporation

    Definitive 14A

    Filed April 27, 2007

    File No. 001-32318

Dear Ms. Moncada-Terry:

This letter is to confirm our telephone conversation today regarding a request for an extension of
time to respond to the comment contained in your letter dated December 14, 2007 regarding the
above-referenced definitive proxy statement. As we discussed, due to the holidays our senior
executives have not had time to respond to the comment.

We very much appreciate your consent to extend the comment response time to Friday, January 11,
2008.

Sincerely,

/s/ Janice A. Dobbs

Janice A. Dobbs

Corporate Secretary

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    Devon Energy Corporation

    20 North Broadway

    Oklahoma City, Oklahoma 73102-8260

    Janice A. Dobbs

    Corporate Secretary

    Direct Phone: 405/552-7844

    Direct Fax:
    405/552-8171

    Email: janice.dobbs@dvn.com

October 3, 2007

    Via EDGAR and

    Facsimile No. 202-772-9220

    Division of Corporation Finance

Mellissa Campbell Duru

Attorney Advisor

U.S. Securities and Exchange Commission

Division of Corporate Finance

450 Fifth Street, N.W.

Washington, D.C. 20549

    Re:

    Devon Energy Corporation

    Definitive 14A

    Filed April 27, 2007

    File No. 001- 32318

Dear Ms. Duru:

This letter responds to the staff’s comment letter of August 21, 2007, regarding the
Definitive 14A, filed April 27, 2007 (File No. 001-32318).

Director Compensation for the Year Ended December 31, 2006, page 12

SEC Comment

    1.

    Revise to specify the aggregate grant date fair value of the awards made in fiscal
2006. See Items 402(k)(2)(iii) and (iv) of Regulation S-K.

Response

The requested disclosure will be included in future filings.

U.S. Securities and Exchange Commission

October 3, 2007

Page 2

Compensation Discussion and Analysis, page 19

SEC Comment

    2.

    Please revise your disclosure to provide an analysis regarding how material decisions
regarding compensation for each of the named executive officers are made. For example,
provide analysis of how the compensation committee’s consideration of the bullet points
listed under the heading “Pay for Performance resulted in the incentive awards to each of
the named executive officers during the last fiscal year. Please see Item 402(b)(2)(vii)
of Regulation S-K and Instruction 1 to Item 402(b). Additionally, rather than stating that
you “[g]enerallly try to reward executives with incentive pay when [you] are
‘successful’...,” discuss what constitutes success and explain how that success determined
the levels of compensation awarded during a given year to the named executive officers. To
the extent awards are made outside of the “general” circumstances you reference, discuss
this fact and address any discretion the compensation committee exercises with respect to
such rewards. See Item 402(b)(2)(vi) of Regulation S-K.

Response

In preparing the 2006 Proxy Statement, the Company followed the SEC’s guidance regarding
Compensation Discussion and Analysis (“CD&A”) as set forth in Release 8732A at Section II.B.1.
This guidance provides that, although the CD&A should be sufficiently precise to identify material
differences in compensation policies and decisions for individual named executive officers where
appropriate, where policies or decisions are materially similar, named executive officers can be
grouped together.

The Company respectfully submits that, where there were material differences in the way
decisions were made regarding compensation for individual named executive officers, the 2006 Proxy
Statement generally identified such material differences appropriately. In preparing the 2006
Proxy Statement, the Company was cognizant of the requirement to discuss material differences
amongst its named executive officers, and therefore included those differences it felt were
material. Examples of such disclosures include the following:

    •

    the discussion under the caption “Compensation Weighted Toward Incentive Pay,” which
addresses the different percentages of total direct compensation, for the Chief Executive
Officer and for the other named executive officers, that was at risk against performance
goals;

    •

    the discussion of the compensation committee’s process for reviewing and determining
annually the Chief Executive Officer’s base salary, in the second full paragraph under the
caption “Base Salary;”

    •

    the discussion of how the Chief Executive Officer’s and the other named executive
officers’ base salaries compare to the market medians, also in the “Base Salary” section;
and

    •

    the discussion of the compensation committee’s process for determining the amount of the
Chief Executive Officer’s annual bonus for 2006, in the last paragraph under the caption
“Annual Incentive Plan.”

U.S. Securities and Exchange Commission

October 3, 2007

Page 3

The Company notes that the Staff’s comment 4, discussed below, also asks for greater detail
regarding material differences in compensation policies and decisions for specified named executive
officers. As noted more fully in our response to comment 4, the Company intends to provide
additional detail regarding the differences noted by the Staff in comment 4, to the extent
applicable in future filings. Further, the Company will endeavor, in future filings, to identify
and discuss material differences in compensation policies and decisions for individual named
executive officers where appropriate.

Also in response to the Staff’s comments, to the extent the Company uses the term “success” in
future filings in the context cited in the Staff’s comment, the Company will clarify the meaning of
such term. In addition, in future filings the Company will provide discussion, where material, of
awards made outside of the “general” circumstances referenced in the comment.

SEC Comment

    3.

    Please disclose what is meant by your reference to the “cyclical nature” of this
business and why and how this would impact compensation awarded.

Response

To the extent the Company includes a reference to the cyclical nature of its business in future
filings, such disclosure will explain what is meant by such reference and why and how the cyclical
nature of the business impacts compensation awarded.

SEC Comment

    4.

    The Compensation Discussion and Analysis should be sufficiently precise to identify
material differences in compensation policies with respect to individual executive
officers. We refer you to Section II.B.1 of Commission Release 8’.32A. Please supplement
your disclosure to discuss the discrepancies in type and amount of compensation awarded to
the named executive officers. For example,

    a.

    identify the reasons for the significant gap in total compensation
recorded with respect to the chief executive officer and other currently employed
executive officers;

    b.

    explain, by discussion and analysis of specific and/or unique duties
performed by your president or his achievements during the fiscal year, why his
compensation is significantly higher than the other named executive officers and
any material factors the compensation committee considers in structuring his total
compensation relative to that of the chief executive officer;

    c.

    disclose how the base salary component paid to Mr. Healy was
structured, giving consideration to his current position as vice-president and
acting chief financial officer; and

    d.

    explain why the post-termination benefits to Mr. Healy, pursuant to the
terms of his severance agreement, are less than or subject to less favorable terms
than those that may be provided to executives who are party to an employment
agreement as disclosed on pages 43-44.

U.S. Securities and Exchange Commission

October 3, 2007

Page 4

Response

As noted in our response to comment 2, in preparing the 2006 Proxy Statement, the Company
followed the SEC’s guidance regarding CD&A as set forth in Release 8732A at Section II.B.1. As
discussed in greater detail in our response to comment 2 above, where there were material
differences in the way in which decisions were made regarding compensation for individual named
executive officers, the Company believes the 2006 Proxy Statement appropriately identified and
discussed such material differences. Further, as noted in our response to comment 2 above, the
Company will endeavor, in future filings, to identify and discuss material differences in
compensation policies and decisions for individual named executive officers where appropriate.

In response to the specific items noted by the Staff:

a. In future filings, to the extent applicable, the Company will provide additional
detail regarding the reasons for the significant gap in total compensation recorded with
respect to the Chief Executive Officer and other currently employed executives. Such
reasons may include, by way of example only, factors such as the Chief Executive
Officer’s seniority, long tenure with the Company, status as a founder of the Company,
level of compensation in comparison to levels for comparable officers at similar
companies, and greater influence over and responsibility for the entire organization (as
opposed to a distinct division/function), as well as other factors contributing to the
discrepancy in compensation, such as the relatively large increase in pension benefit
for the Chief Executive Officer in 2006 as compared to the other named executive
officers, which reflects both his long tenure with the Company and his comparatively
higher compensation.

b. In future filings, to the extent applicable, the Company will provide additional detail
regarding the reasons why the compensation of the President is significantly higher than
other named executive officers and any material factors the compensation committee
considers in structuring his total compensation relative to that of the Chief Executive
Officer. Such reasons may include, by way of example only, factors such as the
President’s seniority, experience and stature in the industry, reporting relationship to
the Chief Executive Officer, level of compensation in comparison to levels for
comparable officers at similar companies, and greater influence over and responsibility
for the entire organization (as opposed to a distinct division/function), as well as
other factors contributing to the discrepancy in compensation.

c. and d. In future filings, to the extent applicable, the Company will provide some
additional detail regarding Mr. Heatly’s compensation. By way of background for the
Staff’s information, just prior to the end of the fiscal year, the Company’s Chief
Financial Officer (Mr. Jennings) was terminated. Mr. Heatly, the Company’s vice
president of accounting, therefore was deemed the principal financial officer at the end
of the year and was included in the group of named executive officers solely because of
his designation as the Company’s principal financial officer (and not because he was one
of the most highly paid executive officers). Mr. Heatly was not a senior executive
officer in 2006, and his compensation arrangements, including his post-termination
benefits, are therefore more in line with non-senior executive officers.

U.S. Securities and Exchange Commission

October 3, 2007

Page 5

Base Salary, page 21

SEC Comment

    5.

    Please include in your discussion of base salary determinations an analysis of how the
“scope of responsibility...experience...leadership” and the other factors listed on page 22
resulted in the actual base salary awarded to each named executive officer during the
fiscal year. Refer to Item 402(b)(1)(v) of Regulation S-K.

Response

As noted in our responses to comments 2 and 4, in preparing the 2006 Proxy Statement, the Company
followed the SEC’s guidance regarding CD&A as set forth in Release 8732A at Section II.B.1. As
discussed in greater detail above in our response to comment 2, where there were material
differences in the way in which decisions were made regarding compensation for individual named
executive officers, the Company believes the 2006 Proxy Statement appropriately identified and
discussed such material differences. By way of example only, see the discussion of the
compensation committee’s process for reviewing and determining annually the Chief Executive
Officer’s base salary, in the second full paragraph under the caption “Base Salary,” and the
discussion of how the Chief Executive Officer’s and the other named executive officers’ base
salaries compare to the market medians, also in that section.

Further, the Company notes that the primary factor in setting base salary levels for named
executive officers is a comparison to comparable salary levels for comparable officers at similar
companies with whom the Company competes for talent. Although, as explained in the 2006 Proxy
Statement, the base salary level may be adjusted from the level determined by reference to
competitive levels on account of other relevant factors, normally competitive salary levels in the
market are the material factor in determining base salary levels. In that sense, the analysis for
the named executive officers is materially similar.

As noted above in our response to comment 4, in future filings, to the extent applicable, the
Company will endeavor to identify and discuss material differences in the factors considered, and
the application of such factors, by the compensation committee in setting the base salaries for
individual named executive officers.

Annual Incentive Plan, page 22

SEC Comment

    6.

    You disclose that specific targets and maximum award levels are not assigned, but you
also indicate that an executive’s contribution to meeting “specific financial and other key
goals” established for the company are considered in determining incentive awards.
Moreover, you state that although the approach to annual incentives is “not strictly
formulaic, it is highly structured...” You also disclose that an executive’s performance is
rated against approved goals. Your disclosure suggests that specific quantitative targets
as well as other factors are considered. Please revise to disclose all quantitative and
qualitative targets both on an aggregate basis and with respect to each individual
officer’s contribution, as measured or determined by the committee during the last fiscal
year. To the extent you believe that disclosure of these targets is not required because
it would result in competitive harm such that you may exclude this information under
Instruction 4 to Item 402(b) of Regulation S-K,

U.S. Securities and Exchange Commission

October 3, 2007

Page 6

please provide on a supplemental basis a detailed explanation supporting your
conclusion. Please also disclose how difficult it will be for the named executive
officers or how likely it will be for you to achieve the undisclosed target levels or
other factors.

Response

As an initial matter, the Company notes that, although the Staff’s comment states that the Company
should disclose “all quantitative and qualitative targets,” the applicable rules require the
Company to explain all “material elements” of the named executive officers’ compensation, including
how the Company determines the amount (and, where applicable, the formula) for each element to
pay.  See Item 402(b)(1)(v).  Item 402(b)(2) sets forth an illustrative list of topics that should
be considered for inclusion in the CD&A, if relevant and material, but it does not constitute a
list of mandatory topics. The list of non-mandatory, illustrative topics in Item 402(b) includes
the “specific items of corporate performance” taken into account in setting compensation. See Item
402(b)(2)(v).  The Company respectfully submits that Item 402(b) requires a discussion and analysis
of the material factors necessary to an understanding of the compensation awarded (in this case,
the annual bonus). Item 402(b) does not necessarily require disclosure of specific performance
targets, if such specific performance targets are not material to an understanding of the
compensation awarded.

In preparing the 2006 Proxy Statement, the Company carefully considered the requirements of
Item 402(b) and whether a discussion of specific performance targets would be material to an
understanding of the annual bonus awards and the compensation committee’s process for determining
such awards. Based on its consideration of these requirements, the Company determined, and
continues to believe, that the specific performance targets are not material to a

August 21, 2007
Mail Stop 7010

By U.S. Mail and facsimile to (405)552-8171

J. Larry Nichols
Chairman and Chief Executive Officer
Devon Energy Corporation
20 North Broadway, Suite 1500
Oklahoma City, Oklahoma 73102

Re:  Devon Energy Corporation
 Definitive 14A
 Filed April 27, 2007
File No. 001-32318

Dear Mr. Nichols:

We have limited our review of your definitive proxy statement to your executive
compensation and other related disclosure a nd have the following comments.  Our review
of your filing is part of the Division of Corporation Finance’s focused review of
executive compensation disclosure.

Please understand that the purpose of our re view process is to assist you in your
compliance with the applicable disclosure requirements and to enhance the overall disclosure in your filings.  We look forward to working with you in these respects.  We
welcome any questions you may have about our comments or any other aspect of our review.  Feel free to call me at the telephone number listed at the e nd of this letter.

 In some comments we have asked you to provide us with additional information so we may better understand your disclosure.  Pl ease do so within the time frame set forth
below.  You should comply with the remain ing comments in all future filings, as
applicable.  Please confirm in writing that you will do so and also explain to us how you
intend to comply.  Please unders tand that after ou r review of all of your responses, we
may raise additional comments.

 If you disagree with any of these commen ts, we will consider your explanation as
to why our comment is inapplicable or a revisi on is unnecessary.  Please be as detailed as
necessary in your explanation.

J. Larry Nichols
Devon Energy Corporation
August 21, 2007 Page 2 of 6

Director Compensation for the Y ear Ended December 31, 2006, page 12

1. Revise to specify the aggregate grant date fair value of the awards made in fiscal
2006.  See Items 402(k)(2)(iii) and (iv) of Regulation S-K.

Compensation Discussion and Analysis, page 19

2. Please revise your disclosure to provid e an analysis regarding how material
decisions regarding compensation for each of the named executive officers are made.  For example, provide analysis of how the compensation committee’s consideration of the bullet points listed under the heading “Pay for Performance” resulted in the incentive awards to each of the named executive officers during the
last fiscal year.  Please see Item 402(b)(2)(vii) of Re gulation S-K and Instruction
1 to Item 402(b).  Additionally, rather th an stating that you “[g]enerally try to
reward executives with incentive pay wh en [you] are ‘successful’…,” discuss
what constitutes success and explain how that success determined the levels of
compensation awarded during a given year to the named executive officers.  To
the extent awards are made outside of the “general” circumstances you reference,
discuss this fact and address any disc retion the compensation committee exercises
with respect to such rewards.    See Item 402(b)(2)(vi) of Regulation S-K.

3. Please disclose what is meant by your reference to the “cyclical nature” of the business and why and how this would impact compensation awarded.

4. The Compensation Discussion and Analysis  should be sufficiently precise to
identify material differences in compen sation policies with respect to individual
executive officers.  We refer you to S ection II.B.1 of Commi ssion Release 8732A.
Please supplement your disclosure to di scuss the discrepancies in type and
amount of compensation awarded to the na med executive officers.  For example,

a. identify the reasons for the significan t gap in total compensation recorded
with respect to the chief executive officer and other currently employed
executive officers;

b. explain, by discussion and analysis of specific and/or unique duties
performed by your president or his ac hievements during the fiscal year,
why his compensation is significan tly higher than the other named
executive officers and any material factors the compensation committee considers in structuring his total compensation relative to that of the chief executive officer;

c. disclose how the base salary componen t paid to Mr. Heal y was structured,
giving consideration to his current po sition as vice-pre sident and acting

J. Larry Nichols
Devon Energy Corporation
August 21, 2007 Page 3 of 6

chief financial officer; and

d. explain why the post-termination bene fits to Mr. Healy, pursuant to the
terms of his severance agreement, are less than or subject to less favorable
terms than those that may be provide d to executives who are party to an
employment agreement as disclosed on pages 43-44.

Base Salary, page 21

5. Please include in your discussion of base sa lary determinations an analysis of how
the “scope of responsibility…experience… l eadership” and the ot her factors listed
on page 22 resulted in the actual base salary awarded to each named executive
officer during the fiscal y ear.  Refer to Item 402(b)(1 )(v) of Regulation S-K.

Annual Incentive Plan, page 22

6. You disclose that specific targets and ma ximum award levels ar e not assigned, but
you also indicate that an executive’s cont ribution to meeting “specific financial
and other key goals” established for the company are considered in determining
incentive awards.  Moreover, you state that although the approach to annual
incentives is “not strictly formulaic, it is highly structured…”  You also disclose that an executive’s performance is rate d against approved goals. Your disclosure
suggests that specific quantitative targets as well as other fact ors are considered.
Please revise to disclose all quantit ative and qualitative targets both on an
aggregate basis and with respect to eac h individual officer’s contribution, as
measured or determined by the committee durin g the last fiscal year. To the extent
you believe that disclosure of  these targets is not required because it would result
in competitive harm such that you may exclude this information under Instruction 4 to Item 402(b) of Regulation S-K, please provide on a supplemental basis a detailed explanation supporting your c onclusion.  Please al so disclose how
difficult it will be for the named executive officers or how likely it will be for you to achieve the undisclosed target  levels or other factors.

7. You disclose that in the company’s annua l goal-setting process, management sets
and the Board approves objective annual targets for your performance along with
subjective goals.  Please revise your disc losure to identify, if applicable, all
targets established for 2007.  Please also  address any other actions regarding
executive compensation that were taken af ter the end of your last fiscal year.
Please see Instruction 2 to Item 402(b) of Regulation S-K.  As noted in our prior
comment, if you believe that disclosure of the information is not required because it would result in competitive harm such that you may exclud e this information
under Instruction 4 to Item 402(b) of  Regulation S-K, please provide on a
supplemental basis a detailed explanation supporting your conclusion.  Please also

J. Larry Nichols
Devon Energy Corporation
August 21, 2007 Page 4 of 6

disclose how difficult it will be for the named executive officers or how likely it will be for you to achieve the undisclose d target levels or other factors.

8. Please include in your disclosure an anal ysis of the key factors considered and
any discretion exercised by the compensati on committee. For example, rather than
stating that the committee believed the company performed “extraordinarily well” with respect to property acquisitions, provide context to your disclosure by
indicating why the committee deemed last year’s performance as “extraordinary” with respect to such acquisitions relative to prior years. See generally Instruction
2 to Item 402(b) of Regulation S-K.   In addition, we note that the committee
determined that the executive officers had contributed “in ways that were
meaningful and appropriate” for his or he r function.  Please revise to explain how
the acquisitions and any other relevant factors were considered for each named executive officer in determining the bonus awarded.    Disclose the respective
contributions of each named executive officer and how such contributions impacted the compensation awarded. See Item 402(b)(2)(vii) of Regulation S-K.

2006 Long-Term Incentive Awards, page 24

9. Please provide an explanation of the di screpancy in awards made to Messrs.
Nichols and Richels.   Additionally, expl ain why the awards made in 2005 were
“significantly” below the 75th percentile of long-te rm incentive paid to
comparable executives and comparison companies.  Moreover, please clarify whether awards made for fiscal 2006 were  principally determined based on (1)
reference to accomplishment of the cu rrent year’s goals, (2)  based on a
consideration of the apparent  shortfall from target payment made in 2005, or (3)
both.  Please see Instruction 2 to Item 402(b) of Regulation S-K.

Total Compensation, page 24

10. You refer on page 19 to “other relevant companies” whose compensation is assessed during the company’s analysis of its compensation awarded.  Although
you identify a peer group of companies,  you have omitted disclosure regarding
the “other relevant” companies, w hy such companies were chosen for
benchmarking (i.e. the characteristics th at make comparison to such companies
meaningful or informative) and which elements of compensation you benchmark
against such “other” companies.  Please disclose the referenced companies and how they factor into the compensation d ecision-making process.  Please see Item
402(b)(2)(xiv) of Regulation S-K.

J. Larry Nichols
Devon Energy Corporation
August 21, 2007 Page 5 of 6

Outstanding Equity Awards at December 31, 2006, page 30

11. You disclose the vesting schedule for restricted stock aw ards.  However,
disclosure regarding what appears to be  alternative and more favorable vesting
schedules for restricted stoc k awards appears in footnotes  9-10 to this table.
Please address in your disclosure the ves ting schedule of restricted stock awards
referenced in the footnotes and explain, if  material to an understanding of future
compensation arrangements, whether the compensation committee retains the discretion to alter the vesti ng schedules in a manner similar to that allowed for the
aforementioned restricted stock awards.

Pension Benefits for the year  ended December 31, 2006, page 34

12. The discussion in this section is dense a nd difficult to follow.  Please revise to
present a concise, accurate and clear overv iew of the pension be nefits receivable
by the named executive officers.

Contracts and Change-in-Control Arrangements, page 44

13. Please include a description of any materi al conditions or obli gations applicable
to the receipt of payments or benefits referenced in  this section.  See Item
402(j)(4) of Regulation S-K.

14. Please provide additional analysis of how  the appropriate payment and benefit
levels are determined under the various circumstances that trigger payments or provision of benefits under the employmen t and severance agreements.  See Item
402(b)(1)(v) and 402(j)(3) of Regulation S-K.

Please respond to our comments by September 21, 2007, or tell us by that time
when you will provide us with a response.

We urge all persons who are responsible for the accuracy and adequacy of the
disclosure in the filing to be certain that the filing includes all in formation required under
the Securities Exchange Act of 1934 and th at they have provided all information
investors require for an informed invest ment decision.  Since the company and its
management are in possession of all facts re lating to a company’s disclosure, they are
responsible for the accuracy and adequacy  of the disclosures they have made.

 When you respond to our comments, please provide, in writing, a statement from the company acknowledging that:

• the company is responsible for the adequacy and accuracy of the disclosure in
the filing;

J. Larry Nichols
Devon Energy Corporation
August 21, 2007 Page 6 of 6

• staff comments or changes to disclo sure in response to comments do not
foreclose the Commission from taking a ny action with respect to the filing;
and

• the company may not assert staff comme nts as a defense in any proceeding
initiated by the Commission or any pers on under the federal s ecurities laws of
the United States.

In addition, please be advise d that the Division of Enfo rcement has access to all
information you provide to the staff of the Di vision of Corporation Finance in connection
with our review of your filing or in response to comments.

Please contact me at (202) 551-3757 with any questions.

Sincerely,

Mellissa Campbell Duru
Attorney Advisor

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    Devon Energy Corporation

    20 North Broadway

    Oklahoma City, Oklahoma 73102-8260

    Janice A. Dobbs

    Corporate Secretary

    (405) 552-7844

September 19, 2007

Via Edgar and Facsimile (202) 772-9220

Securities and Exchange Commission

Division of Corporation Finance — Mail Stop 7010

100 F Street, N.E.

Washington, D.C. 20549-7010

Attention: Ms. Mellissa Campbell Duru

    Re:

    Devon Energy Corporation

Definitive 14A

Filed April 27, 2007

File No. 001-32318

Dear Ms. Duru:

This letter is to confirm our telephone conversation today regarding a request for an extension of
time to respond to the comments contained in your letter dated August 21, 2007 regarding the
above-referenced definitive proxy statement. As we discussed, the travel schedules of our senior
executives have not permitted them time to review the responses to the comments.

We very much appreciate your consent to extend the comment response time to Friday, October 5,
2007.

Sincerely,

/s/ Janice A. Dobbs

Janice A. Dobbs

Corporate Secretary

xc:     J. Larry Nichols, Chairman and CEO

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Brian J. Jennings

Senior Vice President and

Chief Financial Officer

Devon Energy Corporation

20 North Broadway

Oklahoma City, Oklahoma 73102-8260

Direct: 405/552-7838

Direct Fax: 405/552-8109

October 31, 2006

Via EDGAR and

Facsimile No. 202-772-9368

Attention: James Murphy

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 Fiscal Year Ended December 31, 2005

    Filed March 3, 2006

    File No. 1-32318

Dear Mr. Schwall:

This letter responds to the staff’s comment letter dated October 13, 2006, regarding Devon Energy
Corporation’s Form 10-K for the year ended December 31, 2005, filed March 3, 2006 (File No.
1-32318). Devon’s responses to the staff’s comments are set forth below:

Engineering Comments

SEC Comment

    1.

    We have reviewed your response to our comment number one from our letter dated September 11,
2006. As previously discussed, you may not disclose reserve volumes that are not net to your
interest in filings with the SEC. In addition, we are concerned with any public disclosure
where you provide only the estimated gross ultimate or remaining reserve volumes in a field or
property where your net interest reserve volumes are materially lower but you do not disclose
this fact. Please confirm that in future public disclosures you will provide accurate
disclosure by disclosing your net interest and/or net reserve volumes, especially when they
are materially lower than the gross volumes of ultimate or remaining reserves.

Response

As indicated in our response included in our September 25, 2006 letter, we confirm your statement
set forth above.

U.S. Securities and Exchange Commission

October 31, 2006

Page 2

Devon Press Release of September 5, 2006

SEC Comment

    2.

    We have reviewed your response to our comment number two from our letter dated September 11,
2006. We consider 72 miles or the distance from the Jack field to the Cascade project to be
too far to consider the Jack field to be an analogous field to the Cascade. Therefore, we
believe ether economic production or a conclusive formation test is necessary to demonstrate
economic producibility. Because the industry has never produced the lower Tertiary reservoirs
in the deepwater Gulf of Mexico, we believe a conclusive formation test requires a production
test at economic rates. Please confirm that prior to booking proved reserves in the Cascade
project you will perform a conclusive production test at economic rates or alternatively wait
until you have established economic production at Cascade.

Response

We agree that Devon could not currently book proved reserves at Cascade with a reasonable
certainty. However, as discussed in a teleconference with Mr. James Murphy on October 26, 2006, if
a conclusive production test at economic rates is completed at a location that is proximate to the
Cascade area, we would consider booking proved reserves at Cascade if we were satisfied that the
SEC requirements had been met. If we decide to use an analog to book proved reserves at Cascade,
we would recommend a meeting with the SEC staff to present our case with supporting data and
conclusions.

SEC Comment

    3.

    We have reviewed your response to our comment number three from our letter dated September
11, 2006. We believe you must demonstrate economic producibility, either by economic
production or a conclusive formation test prior to the booking of proved reserves in each
lower Tertiary field. Because the industry has never produced the lower Tertiary reservoirs
in the deepwater Gulf of Mexico, we believe a conclusive formation test requires a production
test at economic rates. Please confirm that prior to booking proved reserves in the lower
Tertiary in the deepwater Gulf of Mexico you will perform a conclusive production test at
economic rates or alternatively wait until you have established economic production in each
untested field.

Response

Please see the above response to comment number 2. The lower Tertiary is currently an active area
of exploration, appraisal and development by the industry. As we discussed with Mr. Murphy, it is
possible that a production test from a potential future discovery could meet the test of analogy
and, therefore, be used as analogies for booking proved reserves in other fields or projects.
Devon will assure that all bookings are in compliance with SEC regulations and guidance at the time
of the bookings.

*************************

In connection with the above responses to the staff’s comments, Devon acknowledges that:

    •

    Devon is responsible for the adequacy and accuracy of the disclosures in the filing;

    •

    Staff comments or changes to disclosure in response to staff
comments do not foreclose the Commission from taking any action
with respect to the filing; and

    •

    Devon may not assert staff comments as a defense in any proceeding
initiated by the Commission or any person under the federal
securities laws of the United States.

U.S. Securities and Exchange Commission

October 31, 2006

Page 3

Devon would appreciate receiving the staff’s further comments or questions with respect to the
foregoing as soon as possible. Please direct any comments or questions you may have regarding the
foregoing to the undersigned at 405-552-7838, or to Danny Heatly, Vice President — Accounting, at
405-552-4702.

Very truly yours,

/s/ Brian J. Jennings

Brian J. Jennings

Senior Vice President and

Chief Financial Officer

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549-7010

DIVISION OF
CORPORATION FINANCE MAIL STOP 7010
        October 13, 2006

Mr. Brian Jennings
Senior Vice President and Chief Financial Officer
Devon Energy Corporation
20 North Broadway
Oklahoma City, Oklahoma 73102-8260

 Re: Devon Energy Corporation
  Form 10-K for the Fiscal Year Ended December 31, 2005
Filed March 3, 2006
File No. 1-32318
Re: Response Letter filed September 25, 2006

Dear Mr. Jennings:

We have reviewed your Form 10-K for the fiscal year 2005 and have the
following comments.  We have limited our review of your filing to those issues we have
addressed in our comments.  Where indicated, we think you should revise your document in response to these comments.  If you disagree, we will consider your explanation as to why our comment is inapplicable or a revision is unnecessary.  Please be as detailed as necessary in your explanation.  In some of our comments, we may ask you to provide us with information so we may better understand your disclosure.  After reviewing this information, we may raise additional comments.

 Please understand that the purpose of our review process is to assist you in your compliance with the applicable disclosure requirements and to enhance the overall disclosure in your filing.  We look forward to working with you in these respects.  We welcome any questions you may have about our comments or any other aspect of our review.  Feel free to call us at the telephone numbers listed at the end of this letter.

Engineering Comments

Mr. Brian J. Jennings
Devon Energy Corporation
October 13, 2006 Page 2

8-K issued August 2, 2006

1. We have reviewed your response to our comment number one from our letter dated September 11, 2006.   As previously discussed, you may not disclose reserve volumes that are not net to your interest in filings with the SEC.  In addition, we are concerned with any public disclosure where you provide only the estimated gross ultimate or remaining reserve volumes in a field or property where your net interest reserve volumes are materially lower but you do not disclose this fact.  Please confirm that in future public disclosures you will provide accurate disclosure by disclosing your net interest and/or net reserve volumes, especially when they are materially lower than the gross volumes of ultimate or remaining reserves.

Devon Press Release of September 5, 2006

2. We have reviewed your response to our comment number two from our letter dated September 11, 2006.   We consider 72 miles or the distance from the Jack field to the Cascade project to be too far to consider the Jack field to be an analogous field to the Cascade.  Therefore, we believe either economic production or a conclusive formation test is necessary to demonstrate economic producibility.  Because the industry has never produced the lower Tertiary reservoirs in the deepwater Gulf of Mexico, we believe a conclusive formation test requires a production test at economic rates.  Please confirm that prior to booking proved reserves in the Cascade project you will perform a conclusive production test at economic rates or alternatively wait until you have established economic production at Cascade.

3. We have reviewed your response to our comment number three from our letter dated September 11, 2006.  We believe you must demonstrate economic producibility, either by economic production or a conclusive formation test prior to the booking of proved reserves in each lower Tertiary field.  Because the industry has never produced the lower Tertiary reservoirs in the deepwater Gulf of Mexico, we believe a conclusive formation test requires a production test at economic rates.  Please confirm that prior to booking proved reserves in the lower Tertiary in the deepwater Gulf of Mexico you will perform a conclusive production test at economic rates or alternatively wait until you have established economic production in each untested field.

Closing Comments

Mr. Brian J. Jennings
Devon Energy Corporation
October 13, 2006 Page 3

 As appropriate, please amend your filings and respond to these comments within
10 business days or tell us when you will provide us with a response.  You may wish to provide us with marked copies of the amendment to expedite our review.  Please furnish a cover letter with your amendment that keys your responses to our comments and provides any requested information.  Detailed cover letters greatly facilitate our review.  Please understand that we may have additional comments after reviewing your amendment and responses to our comments.

 We urge all persons who are responsible for the accuracy and adequacy of the disclosure in the filing to be certain that the filing includes all information required under the Securities Exchange Act of 1934 and that they have provided all information investors require for an informed investment decision.  Since the company and its management are in possession of all facts relating to a company’s disclosure, they are responsible for the accuracy and adequacy of the disclosures they have made.

 In connection with responding to our comments, please provide, in writing, a statement from the company acknowledging that:

‚ the company is responsible for the adequacy and accuracy of the disclosure in the filing;

‚ staff comments or changes to disclosure in response to staff comments do not foreclose the Commission from taking any action with respect to the filing; and

‚ the company may not assert staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States.

In addition, please be advised that the Division of Enforcement has access to all
information you provide to the staff of the Di vision of Corporation Finance in our review
of your filing or in response to our comments on your filing.

  You may contact James Murphy, Petroleum Engineer, at (202) 551-3703 if you
have questions related to engineering issues and related disclosures.  Please contact me at (202) 551-3740 with any other questions.
Sincerely,

        H .  R o g e r  S c h w a l l           A s s i s t a n t  D i r e c t o r

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[DEVON LOGO]

Brian J. Jennings

Senior Vice President and

Chief Financial Officer

Devon Energy Corporation

20 North Broadway

Oklahoma City, Oklahoma 73102-8260

Direct: 405/552-7838

Direct Fax: 405/552-8109

September 25, 2006

Via EDGAR and

Facsimile No. 202-772-9368

Attention: James Murphy

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 Fiscal Year Ended December 31, 2005

Filed March 3, 2006

File No. 1-32318

Dear Mr. Schwall:

This letter responds to the staff’s comment letter dated September 11, 2006, regarding Devon Energy
Corporation’s Form 10-K for the year ended December 31, 2005, filed March 3, 2006 (File No.
1-32318). Devon’s responses to the staff’s comments are set forth below:

Engineering Comments

Form 10-K for the Fiscal Year Ended December 31, 2005

International, page 24

SEC Comment

    1.

    We note your response number 4 from your letter of August 9, 2006 which referenced our phone
conversation of July 27, 2006 where we agreed that you would make the proposed changes to the
ACG field disclosure in future filings. However, we also note your 8-K filing of August 2,
2006 where the same language on the ACG field was included. Please reconcile for us the
understanding we thought we reached on July 27, 2006 with the language concerning the ACG
field in this 8-K.

Response

The disclosure in our 2005 10-K that was the subject of the staff’s original comment read as
follows:

“In Azerbaijan, we have a 5.6% carried working interest in the Azeri-Chirag-Gunashli, or
ACG, oil development project in the Caspian Sea. We estimate that the ACG field contains
over five billion barrels of gross proved oil reserves.”

U.S. Securities and Exchange Commission

September 25, 2006

Page 2

In our response dated June 8, 2006, we proposed that in future filings we would replace this
disclosure with the following:

“In Azerbaijan, we have a 5.6% carried working interest in the Azeri-Chirag-Gunashli, or
ACG, oil development project in the Caspian Sea. Devon’s net proved reserves in the ACG
field at the end of 2005 totaled approximately 85.8 million barrels.”

Our proposal was intended to avoid potential confusion from the original disclosure due to the
significant difference between our working interest ownership and our net revenue interest
ownership pursuant to the terms of the applicable production sharing contract.

The reference to the ACG field in the August 2, 2006, 8-K that is the subject of comment #1 of your
letter of September 11, 2006, read as follows:

“The inaugural shipment of crude oil from the Baku-Tbilisi-Ceyhan pipeline marked an
important milestone for the 5.5 billion barrel ACG field in Azerbaijan in June. Devon’s
average daily oil production from ACG is expected to increase by approximately 30,000
barrels per day within the next six months.”

The above reference to the ACG field was contained in our press release announcing our second
quarter financial and operating results. This press release was then included as an exhibit to the
August 2 Form 8-K which was “furnished to,” not “filed with,” the Commission. The words “5.5
billion barrel” are used in the press release only to describe the size of the ACG field, and
presents no confusion about Devon’s net reserves as did the earlier referenced disclosure from our
2005 10-K. Accordingly, we did not believe the use of this description in a press release
furnished to the Commission was contrary to our intentions stated in our earlier response letters
and phone conversations on this subject.

Regardless, if it is the staff’s request that no reference to the gross size of the ACG field be
included in any future documents either furnished to, or filed with, the Comission, then we will
comply with such request in such future documents. Via an email of September 13, 2006, Devon’s
employees who are responsible for preparing our press releases were notified of the staff’s
objection to references to ACG’s gross proved reserves.

Please note that much of the confusion surrounding what is, and is not, acceptable to the staff
regarding this matter revolves around the fact that the staff specifically allowed our reference to
the gross size of the ACG field in our Form S-4 filed on December 19, 2001. In connection with the
staff’s review of such registration statement, comment #55 of the staff’s letter to us dated
November 19, 2001, stated:

“In our previous comment 158 pertaining to your Form 10-K, we asked you to support
statements such as ‘The ACG field is believed to contain over 4 billion barrels of proved
reserves, making it one of the largest oil fields in the world.’ It appears you have
included this same statement in your Form S-4 (page 26) without any technical support.
Supplementally, support this statement to us.”

In our letter dated November 28, 2001, we responded to your above comment as follows:

“Proved reserves at ACG are based on volumetric estimates of the ACG Contract Area which
approximate 12 billion barrels of OOIP with approximately 95% of the in-place reserves in
the Balakhany and Pereriv. Simulation results performed by the operator, BP, show recovery
efficiencies in the range of 45% to 52%, assuming reservoir pressure maintenance. Primary
recovery for the ACG Contract Area is expected to be in excess of 4 billion barrels.
Additionally, attached as Exhibits 1 and 2 are two tables that show remaining reserves for
the largest oil fields in the world. Exhibit 1 contains information compiled by IHS Energy
and Exhibit 2 contains information compiled by Wood MacKenzie. The rankings are slightly
different because IHS Energy includes Saudi and Iraqi fields and because of some differences
in reported numbers. However, by either comparison, ACG is one of the largest fields in the
world based on remaining reserves.”

U.S. Securities and Exchange Commission

September 25, 2006

Page 3

Subsequent to such response, our Registration Statement No. 333-68694 of December 19, 2001, was
declared effective by the staff. The specific reference to the ACG field included in the effective
registration statement read as follows:

“Devon has a 5.6% interest in the ACG oil field. Ryder Scott and Devon estimate that the
ACG field contains over 4 billion barrels of proved reserves, making it one of the largest
oil fields in the world.”

Our disclosures regarding the ACG field since 2001 have been made based on our dialogue with the
staff at that time.

Devon Press Release of September 5, 2006

SEC Comment

    2.

    From your recent press release dated September 5, 2006 regarding the Jack well, you indicate
that the first production from this un-produced geological interval in the deepwater Gulf of
Mexico will be from your Cascade discovery in 2009. As there has only been one test from this
interval in the deepwater Gulf, which was from another discovery, please tell us if you plan
to book proved reserves prior to any production test or actual production at Cascade. Please
tell us the distance from your recent Jack #2 production flow test to the Cascade discovery.
We may have further comments.

Response

It is uncertain at this time when Devon will book proved reserves at Cascade. We will make that
booking once we are satisfied that the SEC requirements have been met.

The distance from our recent Jack #2 production flow test is approximately 72 miles to the Cascade
discovery.

SEC Comment

    3.

    Please tell us approximately when you anticipate the first booking of proved reserves from
the lower Tertiary.

Response

It is uncertain at this time when Devon will make the first booking of proved reserves from the
Lower Tertiary. Because we have a non operator ownership position in our four Lower Tertiary
discoveries, the timing of well operations and project sanctioning are uncertain. The first proved
reserves booking will occur sometime between the sanctioning of one of our discoveries and the
establishment of commercial flow rates from the reservoir.

*************************

In connection with the above responses to the staff’s comments, Devon acknowledges that:

    •

    Devon is responsible for the adequacy and accuracy of the disclosures in the filing;

    •

    Staff comments or changes to disclosure in response to staff comments
do not foreclose the Commission from taking any action with respect
to the filing; and

    •

    Devon may not assert staff comments as a defense in any proceeding
initiated by the Commission or any person under the federal
securities laws of the United States.

U.S. Securities and Exchange Commission

September 25, 2006

Page 4

`

Devon would appreciate receiving the staff’s further comments or questions with respect to the
foregoing as soon as possible. Please direct any comments or questions you may have regarding the
foregoing to the undersigned at 405-552-7838, or to Danny Heatly, Vice President — Accounting, at
405-552-4702.

Very truly yours,

/s/ Brian J. Jennings

Brian J. Jennings

Senior Vice President and

Chief Financial Officer

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549-7010

DIVISION OF
CORPORATION FINANCE MAIL STOP 7010
        September 11, 2006

Mr. Brian Jennings
Senior Vice President and Chief Financial Officer
Devon Energy Corporation
20 North Broadway
Oklahoma City, Oklahoma 73102-8260

 Re: Devon Energy Corporation
  Form 10-K for the Fiscal Year Ended December 31, 2005
Filed March 3, 2006
File No. 1-32318
Re: Response Letter filed August 9, 2006

Dear Mr. Jennings:

We have reviewed your Form 10-K for the fiscal year 2005 and have the
following comments.  We have limited our review of your filing to those issues we have
addressed in our comments.  Where indicated, we think you should revise your document in response to these comments.  If you disagree, we will consider your explanation as to why our comment is inapplicable or a revision is unnecessary.  Please be as detailed as necessary in your explanation.  In some of our comments, we may ask you to provide us with information so we may better understand your disclosure.  After reviewing this information, we may raise additional comments.

 Please understand that the purpose of our review process is to assist you in your compliance with the applicable disclosure requirements and to enhance the overall disclosure in your filing.  We look forward to working with you in these respects.  We welcome any questions you may have about our comments or any other aspect of our review.  Feel free to call us at the telephone numbers listed at the end of this letter.

Engineering Comments

Mr. Brian J. Jennings
Devon Energy Corporation
September 11, 2006, 2006 Page 2

Form 10-K for the Fiscal Year Ended December 31, 2005

International, page 24

1. We note your response number 4 from your letter of August 9, 2006 which referenced our phone conversation of July 27, 2006 where we agreed that you would make the proposed changes to the ACG field disclosure in future filings.  However, we also note your 8-K filing of August 2, 2006 where the same language on the ACG field was included.  Please reconcile for us the understanding we thought we reached on July 27, 2006 with the language concerning the ACG field in this 8-K.

Devon Press Release of September 5, 2006

2. From your recent press release dated September 5, 2006 regarding the Jack well, you indicate that the first production from this un-produced geological interval in the deepwater Gulf of Mexico will be from your Cascade discovery in 2009.  As there has only been one test from this interval in the deepwater Gulf, which was from another discovery, please tell us if you plan to book proved reserves prior to any production test or actual production at Cascade.  Please tell us the distance from your recent Jack #2 production flow test to the Cascade discovery.  We may have further comments.

3. Please tell us approximately when you anticipate the first booking of proved reserves from the lower Tertiary.

Closing Comments

 As appropriate, please amend your filings and respond to these comments within
10 business days or tell us when you will provide us with a response.  You may wish to provide us with marked copies of the amendment to expedite our review.  Please furnish a cover letter with your amendment that keys your responses to our comments and provides any requested information.  Detailed cover letters greatly facilitate our review.  Please understand that we may have additional comments after reviewing your amendment and responses to our comments.

 We urge all persons who are responsible for the accuracy and adequacy of the disclosure in the filing to be certain that the filing includes all information required under the Securities Exchange Act of 1934 and that they have provided all information investors require for an informed investment decision.  Since the company and its

Mr. Brian J. Jennings
Devon Energy Corporation
September 11, 2006, 2006 Page 3

management are in possession of all facts relating to a company’s disclosure, they are responsible for the accuracy and adequacy of the disclosures they have made.

 In connection with responding to our comments, please provide, in writing, a statement from the company acknowledging that:

‚ the company is responsible for the adequacy and accuracy of the disclosure in the filing;

‚ staff comments or changes to disclosure in response to staff comments do not foreclose the Commission from taking any action with respect to the filing; and

‚ the company may not assert staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States.

In addition, please be advised that the Division of Enforcement has access to all
information you provide to the staff of the Di vision of Corporation Finance in our review
of your filing or in response to our comments on your filing.

  You may contact James Murphy, Petroleum Engineer, at (202) 551-3703 if you
have questions related to engineering issues and related disclosures.  Please contact me at (202) 551-3740 with any other questions.

Sincerely,

        H .  R o g e r  S c h w a l l           A s s i s t a n t  D i r e c t o r

CORRESP
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[DEVON LOGO]

Brian J. Jennings

Senior Vice President and

Chief Financial Officer

Devon Energy Corporation

20 North Broadway

Oklahoma City, Oklahoma 73102-8260

Direct: 405/552-7838

Direct Fax: 405/552-8109

August 9, 2006

Via EDGAR and Facsimile No. 202-772-9368

Attention: James Murphy

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 Fiscal Year Ended December 31, 2005

Filed March 3, 2006

File No. 1-32318

Dear Mr. Schwall:

This letter responds to the staff’s comment letter dated July 5, 2006, regarding Devon Energy
Corporation’s Form 10-K for the year ended December 31, 2005, filed March 3, 2006 (File No.
1-32318). Devon’s responses to the staff’s comments are set forth below:

Engineering Comments

Properties, page 16

Proved Reserves and Estimated Future Net Revenue, page 16

SEC Comment

    1.

    Regarding response number 5 of your June 8, 2006 letter, as previously requested please tell
us if the independent engineers that prepared and audited your proved reserves did their own
geological mapping for the reserve work they performed.

Response

All of Devon’s independent reserves engineers review the available data and determine if the
volumetric method is required for the preparation of reserves estimates. If the basis for reserves
is volumetric and it is determined that mapping is required, then our independent engineers review
Devon’s structure maps, using well logs and seismic data (where seismic data is used as a data
source for the structure). Our independent engineers then modify the map as necessary, and in some
cases, they construct their own structure maps from base maps of the field. In almost all cases,
net pay isochore maps are constructed by our independent engineers to reflect the thickness and
distribution of hydrocarbon-bearing reservoir rock. In any cases where our independent engineers
use Devon’s net pay isochore maps, these maps are reviewed and modified as they deem necessary.

U.S. Securities and Exchange Commission

August 9, 2006

Page 2

In all cases, our independent engineers update maps using new well data in active fields in order
to maintain currency and revise the volumetric estimates as long as the volumetric estimate remains
the basis for reserves. All maps used by our independent engineers are either prepared by our
independent engineers or vetted, modified as necessary, and considered the maps that our
independent engineers would represent as their own. Files containing the maps are maintained by
our independent engineers for review as supporting data for reserves estimates prepared for Devon.

SEC Comment

    2.

    As to response number 6, we believe you should only add reserves in the Extensions and
Discoveries category of paragraph 11 of FASB 69 after the actual drilling of extension wells
that increase the areal extent of a known reservoir or the drilling of exploration wells that
discover a new field or new reservoir not previously classified as proved. We do not believe
future infill wells in proved reservoirs are extension or exploration wells. We believe these
fit in the category of Revisions of Previous Estimates based on the evaluation of the results
of previously drilled analogous wells or from price increases that also justify additional
wells in proved reservoirs. One may consider this to be the result of new information.
Therefore, please revise your document as previously requested.

Response

Please refer to our response to comment #6 below.

Operation of Properties, page 21

SEC Comment

    3.

    Regarding response number 7, we believe Item 102 of Regulation S-K applies to specific
properties, such as a lease or leases in a field. We do not believe it applies to broad
geographic areas or countries. We believe that a company the size of Devon Energy has a
number of significant properties or fields based on such things as reserves, current
production, future production expectations, amount of past or future capital expenditures,
number of wells or other important criteria. It would appear the Barnett Shale, among others,
is a significant field for Devon. Please revise your document to include this information.

Response

We propose to revise our disclosure under Item 102 in future filings in accordance with your
comment. As an indication of the changes we propose to make in future filings, following is our
Item 102 property discussion from pages 22 through 25 of our 2005 Form 10-K, as revised according
to your comment.

United States

Permian Basin

Our Permian Basin assets are located in portions of Southeast New Mexico and West Texas. These
assets include conventional oil and gas properties producing from a wide variety of geologic
formations and depths. The Permian Basin assets contributed 17 MMBoe to our total 2005
production and represented 8%, or 161 MMBoe, of our proved reserves at December 31, 2005.

Our average working interest is 75% in the Southeast New Mexico portion of the Permian Basin.
Our leasehold position in Southeast New Mexico encompasses 108,000 net acres of developed lands
and 221,000 net acres of undeveloped land and minerals. Historically, we have been a very active
operator in this area, developing gas from the high productivity Morrow formation and oil in the
lower risk Delaware formation. Our most significant properties in the Southeast New Mexico
portion of the Permian Basin include the Ingle Wells and Catclaw Draw. The Ingle Wells
contributed two MMBoe to our 2005 production and represented 15 MMBoe of our proved reserves at
December 31, 2005. Catclaw Draw contributed one MMBoe to our 2005 production and

U.S. Securities and Exchange Commission

August 9, 2006

Page 3

represented seven MMBoe of our proved reserves at December 31, 2005.

Our average working interest is 40% in the West Texas portion of the Permian Basin. In West
Texas, we maintain a base of oil production with long-life reserves. Many of these reserves are
from both operated and non-operated positions in large enhanced oil recovery units such as the
Wasson ODC Unit, the Willard Unit, the Reeves Unit, the North Welch Unit and the Anton Irish
(Clearfork) Unit. These oil-producing units often exhibit low decline rates. Combined these
units contributed four MMBoe to our 2005 production and represented 58 MMBoe of our proved
reserves at December 31, 2005.

We also own a significant acreage position in West Texas with more than 200,000 net acres of
developed lands and more than 273,000 net acres of undeveloped land and minerals at December 31,
2005.

During 2005, we divested certain non-core properties in the Permian Basin. We also drilled and
completed 95 wells and recompleted or reactivated 254 wells in the Permian Basin. In 2006, we
plan to drill 76 wells and recomplete or reactivate 142 wells.

Mid-Continent

The Mid-Continent region includes portions of Texas, Oklahoma and Kansas. These areas encompass
a wide variety of geologic formations and productive depths and produce both oil and natural
gas. The Mid-Continent region contributed 44 MMBoe to our 2005 production and represented 24%,
or 509 MMBoe, of our proved reserves at December 31, 2005.

Our Mid-Continent production has historically come from conventional oil and gas properties.
However, the Barnett Shale in North Texas, acquired in 2002, is a non-conventional gas resource.
The Barnett Shale is our largest producing field, contributing 15%, or 34 MMBoe, to our total
2005 production. Approximately 19%, or 408 MMBoe, of our total proved reserves are in the
Barnett Shale.

The Barnett Shale is known as a tight gas formation. This means that in its natural state, the
formation is resistant to the production of natural gas. However, the application of available
technology has made the Barnett Shale a low-risk and highly profitable natural gas operation.
Cumulative natural gas production from our wells in the Barnett Shale surpassed one trillion
cubic feet during 2005. We hold 552,000 net acres and over 2,100 producing wells in the Barnett
Shale. Our average working interest is more than 80%.

We have been successful in extracting gas from the Barnett Shale by using light sand fracturing.
Light sand fracturing yields better results than earlier techniques, is less expensive and can
be used to complete new wells and to refracture existing wells to increase production rates. We
are also applying horizontal drilling, closer well spacing and reservoir optimization techniques
to further enhance the value of the Barnett Shale.

Our marketing and midstream operations gather and process our Barnett Shale production along
with Barnett Shale production from unrelated third parties. The Barnett Shale gathering system
consists of approximately 2,600 miles of pipeline, a 650 MMcf per day gas processing plant, and
a 15,000 Bbls per day NGL fractionator.

During 2005, we drilled a total of 217 new Barnett Shale wells including 144 horizontal and 73
vertical wells. In 2006, we plan to drill a total of 325 new Barnett Shale wells including 266
horizontal and 59 vertical wells. We began an infill drilling program on our core area acreage
in 2005, drilling 69 infill wells, and plan to drill 50 to 60 infill wells in 2006.

Rocky Mountain

Our operations in the Rocky Mountain region include properties in Wyoming, Montana, Utah, and
Northern New Mexico. These assets include conventional oil and gas properties and coalbed
natural gas projects. The Rocky Mountain region contributed 19 MMBoe to our total 2005
production. In addition, this region represented 10%, or 209 MMBoe, of our proved reserves at
December 31, 2005.

U.S. Securities and Exchange Commission

August 9, 2006

Page 4

Approximately 17%, or 34 MMBoe, of our proved reserves in the Rocky Mountains are from coalbed
natural gas. We began producing coalbed natural gas in the San Juan Basin of New Mexico in the
mid-1980s and began drilling coalbed natural gas wells in the Powder River Basin of Wyoming in
1998.

Our average working interest in the Powder River Basin is approximately 75%. The Powder River
Basin contributed four MMBoe to our total 2005 production and represented 22 MMBoe of our proved
reserves at December 31, 2005. As of December 31, 2005, we had approximately 1,360 producing
coalbed natural gas wells in the Powder River Basin. We plan to drill about 250 new wells in the
Powder River Basin in 2006.

The Washakie field in Wyoming is another significant natural gas producing area in our Rocky
Mountain region. In 2005, we drilled 88 wells in the Washakie field, including 53 wells we
operate. In 2006, we plan to drill up to 70 wells and participate in another 35 outside-operated
wells. We have interests in over 200,000 gross acres and an inventory of more than 300 drilling
locations. Our production from Washakie was five MMBoe during 2005, and our proved reserves at
December 31, 2005 were 94 MMBoe. Our average working interest is approximately 76%.

Gulf Coast Onshore

Our Gulf Coast onshore properties are located in South and East Texas, Louisiana and
Mississippi. Most of the wells in the region are completed in conventional sandstone formations.
The Gulf Coast properties contributed 26 MMBoe to our 2005 production and represented 11%, or
237 MMBoe, of our proved reserves at December 31, 2005. Our average working interests in these
properties range from 65% to 85%.

Our operations in South Texas have focused on exploration in the Edwards, Wilcox and
Frio-Vicksburg formations. We drilled three exploratory discoveries on our Gulf Coast acreage in
2005. Drilling plans in 2006 include 34 new wells and 64 recompletions. Our most significant
properties in South Texas include Zapata and Agua Dulce. Our share of Zapata production in 2005
was three MMBoe, and our share of proved reserves at December 31, 2005 was eight MMBoe. Our
share of Agua Dulce production in 2005 was one MMBoe, and our share of proved reserves at
December 31, 2005 was six MMBoe.

East Texas is an important conventional gas producing region, and Carthage and Groesbeck are two
of the primary producing areas of this region. Wells produce from the Cotton Valley sands, the
Travis Peak sands and from shallower sands and carbonates. We have interests in over 2,300
producing wells in East Texas and plan to drill 139 wells in Carthage and over 30 wells in
Groesbeck in 2006. Our share of production from the Carthage properties was 13 MMBoe in 2005,
and our share of proved reserves at December 31, 2005 was 142 MMBoe. Our share of production
from the Groesbeck properties was four MMBoe in 2005, and our share of proved reserves at
December 31, 2005 was 40 MMBoe.

We have an active exploration program under way in the Bossier Trend in North Louisiana. We hold
about 200,000 net acres in seven Bossier prospect areas. We drilled exploratory test wells on
the Vixen and North Vixen prospects in 2005. Plans for 2006 include test wells on three
additional Bossier prospects.

Gulf Offshore

The offshore Gulf of Mexico accounted for 13%, or 30 MMBoe, of our 2005 production and 5%, or
115 MMBoe, of our proved reserves at December 31, 2005. We operate over 300 platforms and
caissons in the Gulf of Mexico. Gulf of Mexico operations are typically differentiated by water
depth. The shallow water shelf is defined by water depths of 600 feet or less. We operate in
both the shelf and deepwater areas.

Our largest producing Gulf of Mexico properties in 2005 included Nansen, Magnolia, Red Hawk and
Eugene Island. Our share of production from these fields was nine MMBoe, three MMBoe, three
MMBoe and two MMBoe in 2005, respectively. At December 31, 2005, our proved reserves for these
same fields were 44 MMBoe, 19 MMBoe, six MMBoe and nine MMBoe, respectively.

In 2005, we continued development of the deepwater Magnolia field (Garden Banks 783). At
December 31,

U.S. Securities and Exchange Commission

August 9, 2006

Page 5

2005, six Magnolia wells were producing approximately 10 MBoe per day to our interest. The final
two Magnolia producing wells will be completed in 2006. Also in 2006, we will complete two
producing gas wells in the deepwater Merganser field (Atwater Valley 37). Merganser will produce
into the Independence Hub, which is expected to be completed in early 2007. We expect our net
share of production from Merganser to be approximately eight MBoe per day.

In addition to our producing properties, we have a significant inventory of exploration
prospects in the Gulf of Mexico. The current prospect inventory includes 15 shelf prospects, 18
deepwater prospects in the lower Tertiary trend and 17 deepwater Miocene prospects.

On the shallow-water shelf, the industry is exploring for oil and gas reserves at depths in
excess of 15,000 feet. We drilled a “deep shelf” discovery well on the Big Bend prospect
(Mustang Island A-110) in 2005. We are the operator of Big Bend with a 50% working interest.

In the deepwater Gulf of Mexico, almost all historical production of oil and gas has been from
Miocene aged reservoirs. During 2006, we expect to drill exploratory wells on three Miocene
prospects.

In recent years, the industry has begun to explore for oil below the Miocene in older formations
that are collectively referred to as the lower Tertiary. To date, we have participated in three
lower Tertiary discoveries.

Cascade (Walker Ridge 206) was our first discovery in the lower Tertiary trend. We drilled
successful appraisal wells on the prospect in 2005. Also in 2005, we drilled a successful
appraisal of the Jack lower Tertiary discovery (Walker Ridge 759). An extended production test
of the Jack appraisal well is planned for 2006. Using information obtained from a successful
production test, we and our partners will be able to determine a development plan for the Jack
discovery. We hold 25% working

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
100 F Street, N.E.
WASHINGTON, D.C. 20549-7010

DIVISION OF
CORPORATION FINANCE MAIL STOP 7010
        July 5, 2006

Mr. Brian J. Jennings
Chief Financial Officer
Devon Energy Corporation
20 North Broadway
Oklahoma City, Oklahoma  73102-8260

 Re: Devon Energy Corporation
  Form 10-K for Fiscal Year Ended December 31, 2005
Filed March 3, 2006
Response Letter Dated June 8, 2006
  File No. 1-32318

Dear Mr. Jennings:

We have reviewed your response letter and have the following comments.  We
have limited our review of your filing to those issues we have addressed in our
comments.  Where indicated, we think you should revise your document in response to these comments.  If you disagree, we will consider your explanation as to why our comment is inapplicable or a revision is unnecessary.  Please be as detailed as necessary in your explanation.  In some of our comments, we may ask you to provide us with information so we may better understand your disclosure.  After reviewing this information, we may raise additional comments.

Form 10-K for the Fiscal Year Ended December 31, 2005

Engineering Comments

Properties, page 16

Proved Reserves and Estimated Future Net Revenue, page 16

1. Regarding response number 5 of your June 8, 2006 letter, as previously requested please tell us if the independent engineers that prepared and audited your proved reserves did their own geological mapping for the reserve work they performed.

Mr. Brian J. Jennings
Devon Energy Corporation
July 5, 2006 page 2
2. As to response number 6, we believe you should only add reserves in the Extensions and Discoveries category of paragraph 11 of FASB 69 after the actual drilling of extension wells that increase the areal extent of a known reservoir or the drilling of exploration wells that discover a new field or new reservoir not previously classified as proved.  We do not believe future infill wells in proved reservoirs are extension or exploration wells.  We believe these fit in the category of Revisions of Previous Estimates based on the evaluation of the results of previously drilled analogous wells or from price increases that also justify additional wells in proved reservoirs.  One may consider this to be the result of new information.  Therefore, please revise your document as previously requested.

Operation of Properties, page 21

3. Regarding response number 7, we believe Item 102 of Regulation S-K applies to specific properties, such as a lease or leases in a field.  We do not believe it applies to broad geographic areas or countries.   We believe that a company the size of Devon Energy has a number of significant properties or fields based on such things as reserves, current production, future production expectations, amount of past or future capital expenditures, number of wells or other important criteria.  It would appear the Barrnett Shale, among others, is a significant field for Devon.  Please revise your document to include this information.

International, page 24

4. Regarding response number 10, please make the proposed changes for the ACG field in an amended 2005 10-K.

Results of Operations, page 32

5. Regarding response number 14, tell us for each year beyond 2001 the ultimate recovery, net reserves and net production for the ACG field in Azerbaijan.

Notes to Consolidated Financial Statements, page 67

Quantities of Oil and Gas Reserves, page 114

6. Regarding response number 16, after you make the revisions to the FASB 69 Reserve Reconciliation Table from the earlier comment above, please also add the appropriate explanations for the significant changes to that table in your amended 2005 10-K report.

Mr. Brian J. Jennings
Devon Energy Corporation
July 5, 2006 page 3
Closing Comments

As appropriate, please amend your filing and respond to these comments within
10 business days or tell us when you will provide us with a response.  You may wish to provide us with marked copies of the amendment to expedite our review.  Please furnish a cover letter with your amendment that keys your responses to our comments and provides any requested information.  Detailed cover letters greatly facilitate our review.  Please understand that we may have additional comments after reviewing your amendment and responses to our comments.

You may contact James Murphy, Petroleum Engineer, at (202) 551-3703 with
questions about engineering comments.  Please contact me at (202) 551-3740 with any other questions.

        S i n c e r e l y ,

        H .  R o g e r  S c h w a l l
        A s s i s t a n t  D i r e c t o r

CORRESP
1
filename1.htm

corresp

[DEVON LOGO]

Brian J. Jennings

Senior Vice President and

Chief Financial Officer

Devon Energy Corporation

20 North Broadway

Oklahoma City, Oklahoma 73102-8260

Direct: 405/552-7838

Direct Fax: 405/552-8109

June 8, 2006

Via EDGAR and

Facsimile No. 202-772-9368

Attention: Gary Newberry,

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 Fiscal Year Ended December 31, 2005

Filed March 3, 2006

File No. 1-32318

Dear Mr. Schwall:

This letter responds to the staff’s comment letter dated May 12, 2006, regarding Devon Energy
Corporation’s Form 10-K for the year ended December 31, 2005, filed March 3, 2006 (File No.
1-32318). Devon’s responses to the staff’s comments are set forth below:

Proved Reserves and Estimated Future Net Revenues, page 18

SEC Comment

    1.

    We note your disclosure of Pre-tax 10% Present Value (“PV10”) and the related footnote in the
table presented. We also note your responses to SEC comments 2 and 3 in your letter to us
dated January 14, 2005. In your January letter, you provided example disclosures to be
included in your future filings which included a quantitative disclosure of the amount of
discounted future taxes that were excluded from your measure PV10. It appears that this
disclosure has not been carried forward in your current filing. We believe a quantitative
disclosure of the difference between PV10 and the Standardized Measure is necessary for an
investor’s understanding of that measure. Please revise your disclosure to include a
quantitative reconciliation of the difference between your measure of PV10 and the
Standardized Measure. Refer to Regulation S-K Item 10(e)(1)(i)(B).

U.S. Securities and Exchange Commission

June 8, 2006

Page 2

Response

Subsequent to our letter of January 14, 2005 and prior to the filing of our 2005 Form 10-K, we
revised the locations of the PV 10% and standardized measure figures as compared to where they were
disclosed in the 2003 Form 10-K that was the subject of our prior response. Following these
disclosure revisions, we believed that our existing disclosures were adequate with regard to the
difference between the two measures. However, with the addition of the following three sentences
to the beginning of the second paragraph of footnote 2 on page 19 of our 2005 Form 10-K, all of the
disclosures referenced in our January 14, 2005 letter would be included in our current filing:

The present value of after-tax future net revenues discounted at 10% per annum (“standardized
measure”) was $23.6 billion at the end of 2005. Included as part of standardized measure were
discounted future income taxes of $12.0 billion. Excluding these taxes, the present value
(“pre-tax 10% present value”) was $35.6 billion.

We propose the addition of the above disclosure to our 2006 Form 10-K rather than in an amendment
of our 2005 Form 10-K.

Management Discussion and Analysis of Financial Condition and Results of Operations, page
36

SEC Comment

    2.

    Please revise your discussion to provide a separately captioned section discussing
off-balance sheet arrangements as required by Regulation S-K Item 303 (a)(4). If you have no
such arrangements, amend your filing to disclose this fact.

Response

As of December 31, 2005, Devon had no off-balance sheet arrangements as defined by Item 303 (a)(4).
However, we do not find in Item 303 (a)(4) any requirement to specifically disclose the lack of
such arrangements and do not believe that such disclosure would be material to investors.

Engineering Comments

Risk Factors, page 13

SEC Comment

    3.

    Reconcile the statement that reserves estimates “may change substantially over time” with the
concept of “reasonable certainty.”

Response

Reasonable certainty has been described in SEC guidance as meaning that reserves are much more
likely to increase (positive revision) than to decrease (negative revision) as more data is
obtained over the producing life of the property. Estimates of proved reserves are known to
include certain levels of imprecision because of the uncertainty in the parameters that are
included in the calculation of reserve estimates. This uncertainty applies to all estimation
techniques, including those based on volumetric parameters, performance trends, and material
balance and reservoir simulation with history match. As production and pressure data are gathered
over the life of the reservoir, reserves are almost certain to change, and in some cases change
substantially.

Another potentially significant uncertainty inherent in the estimates of proved reserves is
economic uncertainty, which can be positive or negative over time. The economic uncertainties
include both product price uncertainty and political uncertainties, both domestically and
internationally. As examples of price uncertainties, note on page 118 the downward revisions to
our estimates of International proved reserves that were attributed to changes in prices. As noted
in the reconciliations on page 118, our proved International reserves were revised downward by 14%
in 2004 and by 8% in 2005 due solely to changes in prices from one year-end to the next.

U.S. Securities and Exchange Commission

June 8, 2006

Page 3

Our comments in the risk factor discussion on page 13 are intended to explain the inherent risks
and uncertainties in finding, exploiting and producing oil and gas reserves. We do not believe
that our comments conflict with the concept of “reasonable certainty.”

Properties, page 16

Proved Reserves and Estimated Future Net Revenue, page 16

SEC Comment

    4.

    Revise the document to include the definition of proved reserves as found in Rule 4-10(a) of
Regulation S-X.

Response

We will add the following disclosure to page 16:

The SEC defines proved oil and gas reserves as the estimated quantities of crude oil, natural
gas and NGLs which geological and engineering data demonstrate with reasonable certainty to be
recoverable in future years from known reservoirs under existing economic and operating
conditions, i.e., prices and costs as of the date the estimate is made. Prices include
consideration of changes in existing prices provided only by contractual arrangements, but not
on escalations based upon future conditions.

We propose the addition of the above disclosure to our 2006 Form 10-K rather than in an amendment
of our 2005 Form 10-K.

SEC Comment

    5.

    Tell us if the independent engineers that prepared and audited your proved reserves did their
own geological mapping for the reserve work they performed.

Response

In some cases, where maps are required to estimate reserves, independent engineers prepare their
own maps completely from raw data. However, in most cases, independent engineers begin with
company maps and revise them to reflect their interpretation of structure. In many cases, net pay
isopach maps are drawn by the independent engineers to reflect their interpretation of the
distribution of the reservoir volume. In all cases, the maps used by independent engineers are
prepared, accepted or modified as necessary in their opinion and are intended to be, in their
opinion, accurate representations of the subsurface using the data as known at the time.

SEC Comment

    6.

    You state that in the past five years your annual performance related revisions have averaged
approximately 1% of the previous year’s estimate. According to FASB 69 paragraph 30,
revisions should include reserve additions from development drilling. Please advise us if you
include these as revisions.

Response

Paragraph 30 of FASB 69 deals with the disclosure of the standardized measure of discounted future
net cash flows. Therefore, we have assumed that you intended to reference paragraph 11(a) of FASB
69, and the balance of our response is based on this assumption.

Paragraph 11(a) (Revisions of Previous Estimates) states that “revisions represent changes in
previous estimates of proved reserves, either upward or downward, resulting from new information
(except for an increase in proved acreage) normally obtained from development drilling and
production history or resulting from a change in economic factors.” When reserves related to
development drilling can be initially recorded as proved undeveloped

U.S. Securities and Exchange Commission

June 8, 2006

Page 4

reserves, changes to the booked proved undeveloped reserves after the well is drilled result in
revisions to proved reserves. We believe that reserves added from locations which had not
previously been recorded in the booked proved reserves and that will require the expenditure of
future capital to actually develop such reserves, are properly recognized as “extensions and
discoveries” pursuant to paragraph 11(d)(1), as these wells extend the proved acreage of the field,
even though that acreage may lie between existing wells.

Prior to the recognition of reserves related to locations not categorized as proved undeveloped,
our total recorded proved reserves would not include any estimate of such reserves nor a location
related to the recovery of such reserves. Therefore, it appears contradictory to characterize the
initial recording of proved undeveloped reserves as revisions to “previous estimates” when there
were no such previous estimates recorded.

One of our goals is to book the initial estimate of extended or discovered proved reserves as
accurately as possible. We believe the percentage of yearly revisions unrelated to price changes
is a useful indicator to our investors of the reliability of our procedures that are followed in
initially recording proved reserves. If new proved undeveloped reserves from future development
drilling were to be included as “revisions to previous estimates,” it could lead to quantities
shown as “revisions” that could be a significant percentage of the prior year estimates, and thus
could lead to a erroneous perception that the company’s methods of originally estimating its proved
reserves are unreliable.

Operation of Properties, page 21

SEC Comment

    7.

    Instruction 3 to Item 102 of Regulation S-K requires material disclosure such as reserves,
production and interest about significant properties. However, your filing does not appear to
contain all of the necessary disclosures for the properties you discuss. Please revise as
necessary.

Response

Instruction 3 to Item 102 of Regulation S-K requires the disclosure of material information as to
production, reserves, locations, development and the nature of the registrant’s interest. The
table on page 21 discloses reserves and value for each of our main geographic regions of
operations. More specific information regarding the locations, development and nature of our
interest in the primary fields within each of these main geographic regions is provided on pages 22
through 25. It appears to us that the only information mentioned in Instruction 3 that is missing
is production data related to the main geographic regions of operations.

Accordingly, we propose the addition of a table on page 21 which will disclose 2005 production
volumes of oil, gas and NGLs for each of the Permian Basin, Mid-Continent, Rocky Mountain, Gulf
Coast Onshore, Gulf Offshore, Canada and International geographic regions.

We propose the addition of the above disclosure to our 2006 Form 10-K rather than in an amendment
of our 2005 Form 10-K.

We do not consider any of our individual properties to be of “major significance,” therefore the
information described in Instruction 3(A) and 3(B) is not applicable.

SEC Comment

    8.

    Tell us if you include any reserves based on plant ownership rather than leasehold interest.
If so, revise your document to disclose these separately from the other reserves, if material.

Response

All of our reserves are attributable to leasehold interests.

U.S. Securities and Exchange Commission

June 8, 2006

Page 5

SEC Comment

    9.

    Advise us if you will produce all the reserves from your PSC’s prior to the end of the
contract terms.

Response

All reserves booked under production sharing contracts are expected to be produced within the
limits of the corresponding contract terms.

International, page 24

SEC Comment

    10.

    You state that you estimate the ACG field in Azerbaijan contains over 5 billion barrels of
gross proved oil reserves and that you have a 5.6% working interest. SEC rules only allow you
to disclose reserves that are net to your interest. Also, as you have a 5.6% interest this
would indicate that your net reserves are approximately 245 million barrels. However, you
have only disclosed a total of 244 million barrels for proved reserves for your entire
international operations. Please reconcile these apparent inconsistencies and revise your
document as necessary.

Response

The calculation in your comment appears to assign a 12.5% royalty to the ACG field in order to
arrive at the estimated 245 million barrels net to Devon’s interest. The ACG contract is a
rate-of-return contract that results in a royalty rate considerably more than 12.5%. In fact, the
year-end 2005 effective royalty rate was over 70%. Accordingly, Devon’s net reserves in the ACG
field at year-end 2005 were approximately 85.8 million barrels.

We propose to delete the sentence on page 25 that refers to the five billion barrels of gross
reserves. In its place we will add the following statement:

Devon’s net proved reserves in the ACG field at the end of 2005 totaled approximately 85.8
million barrels.

We propose the addition of the above disclosure to our 2006 Form 10-K rather than in an amendment
of our 2005 Form 10-K.

Selected Financial Data, page 28

Operating Results, page 28

SEC Comment

    11.

    Tell us if the average prices shown here include the effects of hedging. If so, you should
revise the document to note this in the filing.

Response

Yes, the average prices include the effects of hedging. As disclosed in footnote 2 on page 29,
“The preceding price data includes the effect of derivative financial instruments and fixed-price
physical delivery contracts.”

SEC Comment

    12.

    Tell us if the average production and operating expenses include production taxes. If not,
you should revise your document to include these.

U.S. Securities and Exchange Commission

June 8, 2006

Page 6

Response

Yes, the average production and operating expenses include production taxes. Please note the table
on page 36, which indicates that the amounts of production and operating expenses per Boe include
lease operating expenses and production taxes.

Results of Operations, page 32

SEC Comment

    13.

    You disclose, before the effect of hedging, your 2005 average oil price to be $48.49 per
barrel. However, according to the EIA website, the average 2005 oil price of Brent and WTI
was $54.60 and $56.58 per barrel, respectively. Please reconcile to us your reported average
oil prices to us with those on the EIA website.

Response

WTI and Brent are probably the two most commonly referenced types of crude oil. However, as the
EIA website also points out, there are about 161 different internationally traded crude oils that
vary in terms of characteristics, quality and market penetration. Crude oil is referred to as
either “light” or “heavy” depending on its API gravity, with light crude being those with the
higher API gravity. Crude oil is also referred to as either “sweet” or “sour” depending on its
sulfur content, with sweet crude containing lower levels of sulfur. Both WTI and Brent are
characterized as light sweet crude. Light sweet crude demands the highest market price of all the
various grades of crude. As such, WTI and Brent are used as “reference prices,” but a significant
portion of world oil production is of lower quality than W

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
100 F Street, N.E.
WASHINGTON, D.C. 20549-7010

DIVISION OF
CORPORATION FINANCE MAIL STOP 7010
        May 12, 2006

Mr. Brian J. Jennings
Chief Financial Officer
Devon Energy Corporation
20 North Broadway
Oklahoma City, Oklahoma  73102-8260

 Re: Devon Energy Corporation
  Form 10-K for Fiscal Year Ended December 31, 2005
Filed March 3, 2006
  File No. 1-32318

Dear Mr. Jennings:

We have reviewed your filing and have the following comments.  We have
limited our review of your filing to those issues we have addressed in our comments.
Where indicated, we think you should revise your document in response to these comments.  If you disagree, we will consider your explanation as to why our comment is inapplicable or a revision is unnecessary.  Please be as detailed as necessary in your explanation.  In some of our comments, we may ask you to provide us with information so we may better understand your disclosure.  After reviewing this information, we may raise additional comments.

 Please understand that the purpose of our review process is to assist you in your compliance with the applicable disclosure requirements and to enhance the overall disclosure in your filing.  We look forward to working with you in these respects.  We welcome any questions you may have about our comments or any other aspect of our review.  Feel free to call us at the telephone numbers listed at the end of this letter.

Form 10-K for the Fiscal Year Ended December 31, 2005

Mr. Brian J. Jennings
Devon Energy Corporation
May 12, 2006 page 2

Proved Reserves and Estimated Future Net Revenues, page 18

1. We note your disclosure of Pre-tax 10% Present Value (“PV10”) and the related footnote in the table presented.  We also note your responses to SEC comments 2 and 3 in your letter to us dated January 14, 2005.  In your January letter, you provided example disclosures to be included in your future filings which included a quantitative disclosure of the amount of discounted future taxes that were excluded from your measure PV10.  It appears that this disclosure has not been carried forward in your current filing.  We believe a quantitative disclosure of the difference between PV10 and the Standardized Measure is necessary for an investor’s understanding of that measure.  Please revise your disclosure to include a quantitative reconciliation of the difference between your measure of PV10 and the Standardized Measure. Refer to Regulation S-K Item 10(e)(1)(i)(B).

Management Discussion and Analysis of Fina ncial Condition and Results of Operations,
page 36

2. Please revise your discussion to provide a separately captioned section discussing off-balance sheet arrangements as required by Regulation S-K Item 303(a)(4).  If you have no such arrangements, amend your filing to disclose this fact.

Engineering Comments

Risk Factors, page 13

3. Reconcile the statement that reserves estimates “may change substantially over time” with the concept of “reasonable certainty.”

Properties, page 16

Proved Reserves and Estimated Future Net Revenue, page 16

4. Revise the document to include the definition of proved reserves as found in Rule 4-10(a) of Regulation S-X.

5. Tell us if the independent engineers that prepared and audited your proved reserves did their own geological mapping for the reserve work they performed.

6. You state that in the past five years your annual performance related revisions have averaged approximately 1% of the previous year’s estimate.  According to

Mr. Brian J. Jennings
Devon Energy Corporation
May 12, 2006 page 3

FASB 69 paragraph 30, revisions should include reserve additions from development drilling.  Please advise us if you include these as revisions.

Operation of Properties, page 21

7. Instruction 3 to Item 102 of Regulation S-K requires material disclosure such as reserves, production and interest about significant properties.  However, your filing does not appear to contain all of the necessary disclosures for the properties you discuss.  Please revise as necessary.

8. Tell us if you include any reserves based on plant ownership rather than leashold interest.  If so, revise your document to disclose these separately from the other reserves, if material.

9. Advise us if you will produce all the reserves from your PSC’s prior to the end of the contract terms.

International, page 24

10. You state that you estimate the ACG field in Azerbaijan contains over 5 billion barrels of gross proved oil reserves and that you have a 5.6% working interest.  SEC rules only allow you to disclose reserves that are net to your interest.  Also, as you have a 5.6% interest this would indicate that your net reserves are approximately 245 million barrels.  However, you have only disclosed a total of 244 million barrels for proved reserves for your entire international operations.  Please reconcile these apparent inconsistencies and revise your document as necessary.

Selected Financial Data, page 28

Operating Results, page 28

11. Tell us if the average prices shown here include the effects of hedging.  If so, you should revise the document to note this in the filing.

12. Tell us if the average production and operating expenses include production taxes.  If not, you should revise your document to include these.

Results of Operations, page 32

Mr. Brian J. Jennings
Devon Energy Corporation
May 12, 2006 page 4

13. You disclose, before the effect of hedging, your 2005 average oil price to be $48.49 per barrel.  However, according to the EIA website, the average 2005 oil price of Brent and WTI was $54.60 and $56.58 per barrel, respectively.  Please reconcile to us your reported average oil prices to us with those on the EIA website.

14. Supplementally, tell us if you attributed proved reserves to locations that are not adjacent to productive wells.  Submit to us the engineering and geologic justification for PUD reserves you have claimed that are not in legal, technically justified locations offsetting (adjacent to) productive wells.  Otherwise, affirm to us that none of your claimed PUD reserves are attributed to such locations.

Notes to Consolidated Financial Statements, page 67

Quantities of Oil and Gas Reserves, page 114

15. Please revise your document to disclose reserves under Production Sharing Contracts separately from those reserves attributed to leasehold arrangements.

16. Your reserve table indicates that you increased reserves in each of the last three years from 12 to 19% per year through extensions and discoveries.  Please expand your disclosure to include details on these additions as instructed by FASB 69.  Revise your disclosure if necessary for the three years presented to indicate new reserves from development and infill drilling as revisions rather than extensions and discoveries as instructed by FASB 69.

Standardized Measure of Discounted Future Net Cash Flows, page 119

17. Reconcile for us the year-end prices of $45.50 per barrel of oil, $7.84 per Mcf of gas and $32.46 per barrel of NGLs as stated in the document with the December 30, 2005 closing spot prices for WTI of $61.06 per barrel, Brent of $58.34 and Henry Hub gas of $10.05 per MMBtu.

Closing Comments

 As appropriate, please amend your filing and respond to these comments within
10 business days or tell us when you will provide us with a response.  You may wish to provide us with marked copies of the amendment to expedite our review.  Please furnish a cover letter with your amendment that keys your responses to our comments and provides any requested information.  Detailed cover letters greatly facilitate our review.  Please understand that we may have additional comments after reviewing your amendment and responses to our comments.

Mr. Brian J. Jennings
Devon Energy Corporation
May 12, 2006 page 5

 We urge all persons who are responsible for the accuracy and adequacy of the disclosure in the filing to be certain that the filing includes all information required under the Securities Exchange Act of 1934 and that they have provided all information investors require for an informed investment decision.  Since the company and its management are in possession of all facts relating to a company’s disclosure, they are responsible for the accuracy and adequacy of the disclosures they have made.

 In connection with responding to our comments, please provide, in writing, a statement from the company acknowledging that:

‚ the company is responsible for the adequacy and accuracy of the disclosure in the filing;

‚ staff comments or changes to disclosure in response to staff comments do not foreclose the Commission from taking any action with respect to the filing; and

‚ the company may not assert staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States.

In addition, please be advised that the Division of Enforcement has access to all
information you provide to the staff of the Di vision of Corporation Finance in our review
of your filing or in response to our comments on your filing.

 You may contact Gary Newberry at (202) 551-3761, or April Sifford, Branch Chief, at (202) 551-3684 if you have questions regarding comments on the financial statements and related matters.  You may contact James Murphy, Petroleum Engineer, at (202) 551-3703 with questions about engineering comments.  Please contact me at (202) 551-3740 with any other questions.

        S i n c e r e l y ,

        H .  R o g e r  S c h w a l l
        A s s i s t a n t  D i r e c t o r

CORRESP
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[DEVON LOGO]

Devon Energy Corporation

20 North Broadway

Oklahoma City, Oklahoma 73102-8260

Danny J. Heatly

Vice President — Accounting

(405) 552-4702

May 30, 2006

Securities and Exchange Commission

Division of Corporation Finance — Mail Stop 7010

100 F Street, N.E.

Washington, D.C. 20549-7010

Attention: Mr. Gary Newberry

    Re:

    Devon Energy Corporation

    Form 10-K for the Fiscal Year ended December 31, 2005

    Filed March 3, 2006

    File No. 1-32318

Dear Mr. Newberry:

We are in receipt of your letter dated May 12, 2006, containing comments of your review of the
above-referenced Form 10-K for the Fiscal Year ended December 31, 2005. In such letter, you
requested that we amend our filing and respond to comments within 10 business days or advise when a
response would be provided. Due to our apparent mishandling of your letter, Mr. Brian Jennings,
Chief Financial Officer, did not receive the letter until today, May 30, 2006.

Therefore, we request an extension of the original response time, so that our response is due
within 10 business days from today, May 30, 2006.

Thank you for your consideration of this request, and we apologize for any inconvenience this may
cause.

Sincerely,

/s/ Danny J. Heatly

Danny J. Heatly

Vice President — Accounting

    cc:

    H. Roger Schwall, Assistant Director — SEC

    Brian J. Jennings, CFO — Devon