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.

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

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.

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.

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 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.

H. Roger Schwall

United States Securities and Exchange Commission

Page 6

January 11, 2013

Response

The only PUD reserves scheduled for development beyond five years from the initial disclosure date are in the Jackfish project and the property mentioned in our response to the Staff’s fifth comment. The property mentioned in our response to the Staff’s comment #5 was not subjected to the third-party audit.

SEC Comment

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.

Response

In future filings, the report will include these items. Following this letter, we have attached an example of the proposed reserve report that reflects this change.

SEC Comment

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 complete 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 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 “proved 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 attributed 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 entitled “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 the 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.

H. Roger Schwall

United States Securities and Exchange Commission

Page 7

January 11, 2013

• 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 proved 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 been 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 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.

Response

The following bulleted items correspond to the bullets in the Staff’s comment above:

• In future filings, the report will include a discussion of only those procedures used in the preparation of the report. Following this letter, we have attached an example of the proposed reserve report that reflects this change.

• The audit was performed utilizing the reserves definitions as set forth in Rule 4-10(a) of Regulation S-X.

• Deterministic methods were used in the preparation of the audit of the properties in the report.

• The audit was performed utilizing the reserves definitions as set forth in Rule 4-10(a) of Regulation S-X, Regulation S-K and FASB ASC 932.

• The audit was performed utilizing the reserves definitions as set forth in Rule 4-10(a) of Regulation S-X. In future filings, the references to the COGEH Glossary of Terms will be removed. Following this letter, we have attached an example of the proposed reserve report that reflects this change.

SEC Comment

13. We note the reserve report does not include 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 under Item 1202(a)(7) of Regulation S-K.

Response

In future filings, the report will include the qualifications of the AJM Deloitte person primarily responsible for overseeing the reserves audit. Following this letter, we have attached an example of the proposed reserve report that reflects this change.

H. Roger Schwall

United States Securities and Exchange Commission

Page 9

January 11, 2013

SEC Comment

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 geologic 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.

Response

In future filings, the report will not include the references to well maps and geologic procedures. Following this letter, we have attached an example of the proposed reserve report that reflects this change.

* * * * * * * *

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

Fifth Avenue Place 600, 425 – 1 Street SW Calgary AB T2P 3L8 Canada   Tel: 403-648-3200 Fax: 403-265-0862 www.deloitte.ca

January 25, 2012

Devon Energy Corporation

20 North Broadway

Oklahoma City, Oklahoma

USA 73102

Attention: Mr. Bob Fant

Re: Devon Canada Corporation

December 31, 2011 reserve audit opinion

At your request and authorization, Deloitte & Touche LLP (“AJM Deloitte”) has audited the reserves management processes and practices of Devon Canada Corporation (“Devon Canada”) as of December 31, 2011. Our audit was completed on December 15, 2011 and included such tests and procedures as we considered necessary under the circumstances to render our opinion.

During the course of our examination, we audited in excess of 89 percent of Devon Canada’s total proved reserves for certain properties within Western Canada. AJM Deloitte’s estimate for the audited properties varied from Devon Canada’s estimates by less than 10 percent. When compared to Devon Canada’s parent corporation, Devon Energy Corporation, AJM Deloitte audited 22 percent of the company’s total proved reserves.

The scope of the audit consisted of the independent preparation of our own estimates of the proved reserves and the comparison of our proved reserve results to the estimates prepared by the company. When compared on a field by field basis, some estimates prepared by Devon Canada are greater than and some are less than those prepared by AJM Deloitte. However, in our opinion, the estimates prepared by Devon Canada are in aggregate reasonable, are within the established audit tolerance of plus or minus 10 percent and the estimates have been prepared in accordance with generally accepted petroleum engineering practices and procedures. These practices and procedures are detailed within the Canadian Oil and Gas Evaluation Handbook (“COGEH”), set out by the Society of Petroleum Evaluation Engineers (“SPEE”) as well as the Society of Petroleum Engineers’ (“SPE”) Standards Pertaining to the Estimation and Auditing of Oil and Gas Reserves. We believe that such assumptions, data, methods, and procedures are appropriate for the purpose served by the report. For the purpose of this audit only deterministic methods were used. The proved 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.

Devon Energy Corporation

December 31, 2011 reserve audit opinion

Page 2

AJM Deloitte was provided with Devon Canada’s base hydrocarbon prices (oil, gas, condensate and natural gas liquids) as of December 31, 2011 in order to estimate the company’s net after royalty reserves. In accordance with SEC requirements all prices and costs (capital and operating) were held constant. The effects of derivative instruments designated as price hedges of oil and gas quantities if any, are not reflected in AJM Deloitte’s individual property evaluations. An oil equivalent conversion factor of 6.0 Mcf per 1.0 barrel oil was used for sales gas.

The extent and character of ownership and all factual data supplied by Devon Canada Corporation were accepted as presented. A field inspection and environmental/safety assessment of the properties was not made by AJM Deloitte and the consultant makes no representations and accepts no responsibilities in this regard.

It should be understood that our audit does not constitute a complete reserves study of the oil and gas properties of your company. In the conduct of our examinations we have not independently verified the accuracy and completeness of all the information and data furnished by your company with respect to ownership interests, oil and gas production, historical costs of operations and development, product prices, and agreements relating to current and future operations and sales of production. We have, however, specifically identified to you the information and data upon which we relied so that you can subject it to procedures you consider necessary. Furthermore, if in the course of our examination something came to our attention that brought into question the validity or sufficiency of any of the information or data, we did not rely on that information or data until we had satisfactorily resolved our questions or independently verified it.

The accuracy of any reserve and production estimates is a function of the quality and quantity of available data and of engineering interpretation and judgment. While reserve and production estimates adhere to Regulation S-K, 229.1202 and Regulation S-X, 4-10(a) (as applicable), the estimates should be accepted with the understanding that reservoir performance subsequent to the date of the estimate may justify revision, either upward or downward. If government regulations change, the net after royalty recoverable reserve volumes may change materially.

We are independent with respect to the company as provided in the standards pertaining to the estimating and auditing of oil and gas reserves information included in COGEH and the Association of Professional Engineers, Geologists and Geophysicists of Alberta (“APEGGA”).

This audit is for the information of your company and for the information and assistance of its independent public accountants in connection with their review of, and report upon, the financial statements of your company. Supporting data documenting the audit, along with data provided by Devon Canada, are on file in our office. The results of our third party audit, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by Devon Energy Corporation.

Devon Energy Corporation

December 31, 2011 reserve audit opinion

Page 3

Devon Energy Corporation makes periodic filings on Form 10-K with the SEC under the 1934 Exchange Act. Furthermore, Devon Energy Corporation has certain registration statements filed with the SEC under the 1933 Securities Act into which any subsequently filed Form 10-K is incorporated by reference. We have consented to the incorporation by reference in the registration statements on Form S-X of Devon Energy Corporation to the references to our name as well as to the references to our audit for Devon Energy Corporation, which appears in the December 31, 2010 annual report on Form 10-K of Devon Energy Corporation. Our written consent for such use is included as a separate exhibit to the filings made with the SEC by Devon Energy Corporation.

Yours truly,

Original signed by: “Robin G. Bertram”

Robin G. Bertram, P. Eng.

Associate Partner

Deloitte & Touche LLP

/ct

Audit procedure

Definitions and methodology

Effective as of December 2011

Table of Contents

Definitions

•   Procedure	3
•   Reserve definitions	4
Resource and reserve estimation	4
Production forecasts	4
Land schedules	5
Geology	5
Royalties and taxes	6
Capital and operating considerations	7
Pricing overview	8

2

Procedure

AJM Deloitte has prepared its report in accordance with SEC Regulation S-K, 229.1202 and Regulation S-X, 210.4-10.

Reserves audit

A “Reserves Audit” is the process carried out by a qualified reserves auditor that results in a reasonable assurance, in the form of an opinion, that the reserves information has in all material respects been determined and presented according to the principles and definitions adopted by the Society of Petroleum Evaluation Engineers (“SPEE”) (Calgary Chapter), and Association of Professional Engineers, Geologists and Geophysicists of Alberta (“APEGGA”) and are, therefore free of material misstatement.

The reserves evaluations prepared by the Corporation have been audited, not for the purpose of verifying exactness, but the reserves information, company policies, procedures, and methods used in estimating the reserves will be examined in sufficient detail so that AJM Deloitte can express an opinion as to whether, in the aggregate, the reserves information presented by the Corporation are reasonable.

AJM Deloitte may require its own independent evaluation of the reserves to test for reasonableness of the Corporation’s evaluations. The tests to be applied to the Corporation’s evaluations insofar as their methods and controls and the properties selected to be re-evaluated will be determined by AJM Deloitte, in its sole judgment, to arrive at an opinion as to the reasonableness of the Corporation’s evaluations.

3

Reserve definitions

Reserve classification

Reserves are classified by AJM Deloitte in accordance with the definitions that are described in the United States Securities and Exchange Commission Regulation S-X Part 210.4-10(a).

Resource and reserve estimation

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 the information available and is generally used in resource evaluations and when utilized will be stated within the detailed property reports. Both techniques comply as defined in Regulation S-X, 210.4-10(a).

Production forecasts

Production forecasts were based on historical trends or by comparison with other wells in the immediate area producing from similar reservoirs. Non-producing gas reserves were forecast to come on-stream within the first two years from the effective date under direct sales pricing and deliverability assumptions, if a tie-in point to an existing gathering system was in close proximity (approximately two miles). If the tie-in point was of a greater distance (and dependent on the reserve volume and risk) the reserves were forecast to come on-stream in years three or four from the effective date. These on-stream dates were used when the company could not provide specific on-stream date information.

For reserve volumes that meet all reserve category rules but are behind casing and waiting on depletion of the producing zone, these volumes are forecast to be brought on-stream following the end of the existing production.

4

Land schedule

The evaluated Corporation provided schedules of land ownership which included lessor and lessee royalty burdens. The land data was accepted as factual and no investigation of title by AJM Deloitte was made to verify the records.

Geology

An initial review of each property is undertaken to establish the produced maturity of the reservoir being evaluated. Where extensive production history exists a geologic analysis is not conducted since the remaining hydrocarbons can be determined by productivity analysis.

For properties that are not of a mature production nature a geologic review is conducted. This work consists of:

• developing a regional understanding of the play,

• assessing reservoir parameters from the nearest analogous production,

• analysis of all relevant well data including logs, cores, and tests to measure net formation thickness (pay), porosity, and initial water saturation,

• auditing of client mapping or developing maps to meet AJM Deloitte’s need to establish volumetric hydrocarbons-in-place.

5

Royalties and taxes

General

All royalties and taxes, including the lessor and overriding royalties, are based on government regulations, negotiated leases or farmout agreements, that were in effect as of the evaluation effective date. If regulations change, the net after royalty recoverable reserve volumes may differ materially.

AJM Deloitte utilizes a variety of reserves and valuation products in determining the result sets.

6

Capital and operating considerations

Reserves estimated to meet the standards for constant prices and costs, are based on Regulation S-X 210.4-10(a).

Capital costs were provided by the Corporation and reviewed by AJM Deloitte for reasonableness.

Operating costs were determined from historical data on the property as provided by the evaluated Corporation.

7

Pricing overview

Devon provided AJM Deloitte with hydrocarbon prices (oil, gas condensate, and natural gas liquids) appropriate for use in the preparation of a reserves report to be filed with the SEC with an effective date of December 31, 2011. These prices were calculated in accordance with the definition (22)(v) of Regulation S-X, 210.4-10(a) and were determined by taking the un-weighted average of the prices on the first day of the month for the preceding 12 months (January 1, 2011 through to December 1, 2011).

The effects of derivative instruments designated as price hedges of oil and gas quantities if any, are not reflected in AJM Deloitte’s individual property evaluations.

	Benchmark	Benchmark price ($US)	Weighted average realized report  price ($US)
Oil	NYMEX WTI @ Cushing	$96.19/bbl	$64.34/bbl
Gas	NYMEX Henry Hub	$4.12/MMbtu	$3.55/Mcf
NGL	Mt. Belvieu	$49.88/bbl	$45.08/bbl

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Robin G. Bertram, P. Eng. Associate Partner, Energy and Resource Advisory Services Financial Advisory Calgary Office phone: 403-648-3223 Email: rbertram@deloitte.ca

Profile Robin Bertram is an Associate Partner with Deloitte & Touche LLP, within the Financial Advisory Services department. Robin works with the specialized group Energy and Resource Advisory Services where he directs the work of 15 engineers, geoscientists, and support staff in the assessment of oil and gas resources/reserves and their value. Experience Robin is a professional engineer with more than 25 years of experience in reservoir exploitation, field development, reserve determination and economic evaluations. He has completed resource assessments and evaluations throughout the world, including assessments of shale gas in Canada’s Horn River Basin and Montney plays, heavy oil in California, oil shales in New Zealand’s East Coast Basin and conventional oil in international jurisdictions such as Kurdistan, offshore Ireland, Turkey, and other countries. At AJM Deloitte, Robin provides oversight to the company’s enhanced recovery practice, which encompasses simulations, advanced reservoir studies, and scoping of candidate reservoirs for secondary and tertiary recovery mechanisms. Robin has participated in resource/reserve estimation and valuation for the purpose of: •   corporate reserve reporting •   acquisition, disposition, and mergers of properties and/or companies •   undeveloped land valuation •   corporate re-structuring •   estate settlement •   matrimonial equalization Selected Advisory credentials •   Responsible for the evaluation of heavy oil/oil sands properties utilizing conventional and thermal recovery methods in the: •   Athabasca Oil Sands, •   Brittnell, •   Jackfish (Thermal), •   Long Lake, •   McMullen, •   Northern Lights, •   OPTI Canada, •   selected fields in California and Trinidad.

•   Experience in the various oil sands recovery techniques such as Steam Assisted Gravity Drainage (SAGD), Cyclic Steam Stimulation (CSS), and Cold Heavy Oil Production with Sand (CHOPS).

•   Extensive experience in both deterministic and stochastic methods of reserve and resource estimation and evaluation.

•   Has actively developed AJM’s internal resource evaluation process utilizing probabilistic methods.

•   Coordinated the evaluation of both producing and developing shale gas properties across the Horn River and Montney Basins.

•   Since 2002, he has managed the continuing evaluation and audit of Devon Canada’s total reserve base.

•   Coordinated significant exploration and development drilling programs with involvement in all processes and decisions from selection of locations to production of wells and construction facilities. Held similar positions within Talisman working on assets across Western Canada. Successfully promoted a major property transaction with a competitor, which allowed both companies to efficiently develop joint lands.

Education/Professional designations

•   APEGA Management Certificate, University of Calgary, 1997

•   Bachelor of Science Petroleum Engineering, University of Alberta, 1985

•   The Association of Professional Engineers and Geoscientists of Alberta (APEGA)

•   The Society of Petroleum Engineers (SPE)

•   The Society of Petroleum Evaluation Engineers (SPEE)

Languages

English

Industry involvement

•   2010—Present Society of Petroleum Evaluation Engineers (SPEE)

Ÿ        Chair of the SPEE Calgary Chapter’s COGEH Standing Committee

•   2009—2010 Society of Petroleum Evaluation Engineers (SPEE)

Ÿ        Committee member involved in preparing Monograph No. 3, Guidelines for the Practical Evaluation of Undeveloped Reserves in Resource Plays.

•   1991—1994 CIM

Ÿ        Contributing author to the CIM’s Monograph No. 1, Determination of Oil and Gas Reserves, published in 1994.