Exhibit 99.2

    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 examination 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. 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 and proved plus probable 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. 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 believe that such assumptions, data, methods, and procedures are appropriate for the purpose served by the report.

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.

In general terms, Devon Canada’s corporate structure is such that lands are held within either Devon Canada Partnership (“DCP”) or Devon NEC Corporation (“NEC”). For the purpose of this evaluation, properties which consist of both DCP and NEC lands are reported separately.

The Evaluation Procedure section included in this report details the reserves definitions, price and market demand forecasts and general procedure used by AJM Deloitte in its reserve estimates. 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.

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 study, 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 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 third party report for Devon Energy Corporation, which appears in the December 31, 2011 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

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Evaluation procedure

Definitions and methodology

Effective as of December 2011

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Table of Contents

Definitions

• Procedure

• Reserve definitions

Resource and reserve estimation

Production forecasts

Land schedules and maps

Geology

Royalties and taxes

Capital and operating considerations

Price and market demand forecasts

Glossary of terms

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Procedure

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^nd Edition. The reader is referred to the Handbook for a complete description of the particular process quoted as follows.

Resources or reserves evaluation

A “Resources or Reserves Evaluation” is the process whereby a qualified reserves evaluator estimates the quantities and values of oil and gas resources or reserves by interpreting and assessing all available pertinent data. The value of an oil and gas asset is a function of the ability or potential ability of that asset to generate future net revenue, and it is measured using a set of forward-looking assumptions regarding resources or reserves, production, prices, and costs. Evaluations of oil and gas assets, in particular reserves, include a discounted cash flow analysis of estimated future net revenue.

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 information for a small number of properties, or for a large number of properties as tests for the 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.

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Reserves review

A “Reserves Review” is the process whereby a reserves auditor conducts a high-level assessment of reserves information to determine if it is plausible. The steps consist primarily of enquiry, analytical procedure, analysis, review of historical reserves performance, and discussion with the Corporation’s reserves management staff.

“Plausible” means the reserves data appear to be worthy of belief based on the information obtained by the independent qualified reserves auditor in carrying out the aforementioned steps. Negative assurance can be given by the independent reserves auditor, but an opinion cannot. For example, “Nothing came to my attention that would indicate the reserves information has not been prepared and presented in accordance with principles and definitions adopted by the SPEE (Calgary Chapter), and APEGGA (Practice Standard for the Evaluation of Oil and Gas Reserves for Public Disclosure).

Reviews do not require examination of the detailed document that supports the reserves information, unless this information does not appear to be plausible.

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Reserve definitions

Reserve classification

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. These definitions are as follows:

Proved oil and gas reserves

Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids 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.

• Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and (B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.

• Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

• Estimates of proved reserves do not include the following:

a. oil that may become available from known reservoirs but is classified separately as “indicated additional reserves”;

b. crude oil, natural gas and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors;

c. crude oil, natural gas and natural gas liquids, that may occur in undrilled prospects; and

d. crude oil, natural gas and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources.

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Proved developed oil and gas reserves

Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

The SEC does not further subdivide proved developed reserves. AJM Deloitte further subdivides proved developed reserves between proved developed producing and proved developed non-producing reserves, as follows. The definition and guidelines are documented in the Petroleum Resources Management System (“PRMS”) prepared by the Oil and Gas Reserves Committee of the Society of Petroleum Engineers (SPE), World Petroleum Council (WPC), the American Association of Petroleum Geologists (AAPG), and the Society of Petroleum Evaluation Engineers (SPEE).

Proved Developed Producing Reserves: Proved developed producing reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate. Improved recovery reserves are considered producing only after the improved recovery project is in operation.

Proved Developed Non-Producing Reserves: Proved developed non-producing reserves include shut-in and behind-pipe reserves. Shut-in reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe reserves are expected to be recovered from zones in existing wells which will require additional completion work or future recompletion prior to the start of production. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

Proved Undeveloped Reserves: Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of

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production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

Probable reserves

Probable reserves are those additional reserves which analysis of geoscience and engineering data indicates are less likely to be recovered than proved reserves but more certain to be recovered than possible reserves. It is equally likely that actual remaining quantities recovered will be greater than or less than the sum of the estimated proved plus probable reserves (2P).

The SEC further sub-divides probable reserves. AJM Deloitte further sub-divides probable reserves into developed and undeveloped and producing and non-producing, as follows:

Probable Developed reserves are expected quantities to be recovered from existing wells and facilities. Reserves are considered developed only after the necessary equipment has been installed, or when the costs to do so are relatively minor compared to the cost of a well. Developed reserves may be subcategorized as producing or non-producing.

Producing: Probable reserves that are expected to be recovered from completion intervals which are open and producing at the time of the estimate. Improved recovery reserves are considered producing only after the improved recovery project is in operation.

Non-Producing: Probable reserves include shut-in and behind-pipe reserves. Shut-in reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe reserves are expected to be recovered from zones in existing wells, which will require additional completion work or future recompletion prior to the start of production. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

Probable Undeveloped reserves are quantities expected to be recovered through future investments: (1) from new wells on undrilled acreage in known accumulations, (2) from deepening existing wells to a different (but known) reservoir, or (3) where a relatively large expenditure (eg. when compared to the cost of drilling a new well) is required to (a) recomplete an existing well or (b) install production or transportation facilities for primary or improved recovery projects.

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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. This will be stated within the detailed property reports.

Deterministic

Reserves and resources were estimated either by i) volumetric, ii) decline curve analysis, iii) material balance techniques, or iv) performance predictions.

Volumetric reserves were estimated using the wellbore net pay and an assigned drainage area or, where sufficient data was available, the reservoir volumes calculated from isopach maps. Reservoir rock and fluid data were obtained from available core analysis, well logs, PVT data, gas analysis, government sources, and other published information either on the evaluated pool or from a similar reservoir in the immediate area. In mature (producing) reservoirs decline curve analysis and/or material balance was utilized in all applicable evaluations.

Statistical analysis

Whenever there is the need within an evaluation to assign reserves based on analogy or when volumetric reserves are being assigned, AJM Deloitte utilizes a variety of different tools in support of. When evaluating Western Canadian prospects, typically AJM Deloitte uses petroCUBE™.

The petroCUBE program is a web-based (www.petroCUBE.com) product co-developed by AJM Deloitte and geoLOGIC Systems Inc. petroCUBE provides geostatistical, technical, and financial information for conventional hydrocarbon plays throughout the Western Canadian Sedimentary Basin (“WCSB”).

The information provided by petroCUBE is an unbiased independent perspective into the historical performance of the conventional hydrocarbon activity in the WCSB. The statistical information is presented by commodity type (gas, oil) with each commodity further analyzed by geographic area and play type.

Analysis output includes cumulative frequency resource distribution curves, chance of success tables, production performance profiles for each play type and area, unrisked and risked resources, and initial production rates on a per well zone basis, and full cycle economic and play parameters.

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Cumulative frequency curves show how the volumes for a play are distributed. These calculations include the average volumes for a play (P₅₀), volumes for the best 10 percent of the wells (P₁₀), the minimum volumes developed by 90 percent of the wells (P₉₀).

Reserves assigned are compared to those volumes noted in the cumulative frequency curves for the corresponding area and play type. Typically an expected or proved plus probable reserve is a P₅₀ volume.

Probabilistic

Because of the uncertainty inherent in reservoir parameters, probabilistic analysis, which is based on statistical techniques, provides a formulated approach by which to obtain a reasonable assessment of the petroleum initially in place (PIIP) and/or the recoverable resource. Probabilistic analysis involves generating a range of possible outcomes for each unknown parameter and their associated probability of occurrence. When probabilistic analysis is applied to resource estimation, it provides a range of possible PIIPs or recoverable resources.

In preparing a resource estimate, AJM Deloitte assesses the following volumetric parameters: areal extent, net pay thickness, porosity, hydrocarbon saturation, reservoir temperature, reservoir pressure, gas compressibility factor, recovery factor, and surface loss. A team of professional engineers and geologists experienced in probabilistic resource evaluation considered each of the parameters individually to estimate the most reasonable range of values. Working from existing data, the team discusses and agrees on the low (P₉₀) and high (P₁₀) values for each parameter. To help test the reasonableness of the proposed range, a minimum (P₉₉) and maximum (P₁) value are also extrapolated from the low and high values. After ranges have been established for each parameter, these independent distributions are used to determine a P₉₀, P₅₀, and P₁₀ result which comprise AJM Deloitte’s estimated range of PIIP or recoverable resource.

It is important to note that the process used to determine the final P₁₀, P₉₀, and P₅₀ results involves multiplying the various volumetric parameters together. This yields results which require adjustments to maintain an appropriate probability of occurrence. For example, when calculating total reservoir volume (Area x Pay), the chance of getting a volume greater than the P₁₀ Area x P₁₀ Pay is less than 10 percent – the chance of getting the calculated result is only 3.5 percent (p_3.5). As you multiply additional P₁₀ values, the probability of achieving the calculated value becomes less likely. Similarly, multiplying P₉₀ parameters together will yield a result that has a probability greater than P₉₀. As such, when multiplying independent distributions together the results must be adjusted via interpolation to determine final P₉₀ and P₁₀ values.

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The results appearing in this report represent interpolated P₉₀ and P₁₀ values. As defined by COGEH (and the Petroleum Resource Management System “PRMS”), the P₅₀ estimate is the “best estimate” for reporting purposes.

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. 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. These on-stream dates were used when the company could not provide specific on-stream date information.

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Land schedule and maps

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.

Well maps included within this report represent all of the Corporation’s interests that were evaluated in the specified area.

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.

Procedures specific to the project are discussed in the body of the report.

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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.

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Capital and operating considerations

Operating and capital costs were based on current costs escalated to the date the cost was incurred, and are in current year dollars. The economic runs provide the escalated dollar costs as found in the Pricing Table 1 in the Price and Market Demand section.

Reserves estimated to meet the standards of NI 51-101 for constant prices and costs (optimal), are based on unescalated operating and capital costs.

Capital costs were either provided by the Corporation (and reviewed by AJM Deloitte for reasonableness); or determined by AJM Deloitte taking into account well capability, facility requirement, and distance to markets. Facility expenditures for shut-in gas are forecast to occur prior to the well’s first production.

Operating costs were determined from historical data on the property as provided by the evaluated Corporation. If this data was not available or incomplete, the costs were based on AJM Deloitte experience and historical database. Operating costs are defined into three types.

The first type, variable ($/Unit), covers the costs directly associated with the product production. Costs for processing, gathering and compression are based on raw gas volumes. Over the life of the project the costs are inflated in escalated runs to reflect the increase in costs over time. In a constant dollar review the costs remain flat over the project life.

The second type, fixed plant or battery ($/year), is again a fixed component over the project life and reflects any gas plant or battery operating costs allocated back to the evaluated group. The plant or battery can also be run as a separate group and subsequently consolidated at the property level.

The third type takes the remaining costs that are not associated with the first two and assigns them to the well based on a fixed and variable component. A split of 65 percent fixed and 35 percent variable assumes efficiencies of operation over time, i.e.: the well operator can reduce the number of monthly visits as the well matures, workovers may be delayed, well maintenance can also be reduced. The basic assumption is that the field operator will continue to find efficiencies to reduce the costs over time to maintain the overall $/Boe cost. Thus as the production drops over time the 35 percent variable cost will account for these efficiencies. If production is flat all the costs will also remain flat. Both the fixed and variable costs in this type are inflated in the escalated case and held constant in the constant dollar review. These costs also include property taxes, lease rentals, government fees, and administrative overhead.

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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 and these costs were either provided by the Corporation (and reviewed by AJM Deloitte for reasonableness) or based on area averages (only the base abandonment costs were utilized and no consideration for groundwater protection, vent flow repair costs, or gas migration costs were considered). If there were multiple events to abandon the costs were increased by a 25 percent factor. Site reclamation costs were based on information provided by the Corporation or based on area averages. For undeveloped reserve estimates for undrilled locations, both abandonment and site reclamation costs are also included for the purpose of determining whether reserves should be attributed to that property in the first year in which the reserves are considered for attribution to the property.

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Price and market demand forecasts

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 “Modernization of Oil and Gas Reporting: Final Rule” 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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Glossary of terms

AJM Deloitte subscribes to the Glossary of Terms as defined by the Canadian Oil and Gas Evaluation Handbook, Volume 2.

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