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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

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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.

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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,

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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