[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.
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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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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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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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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 interests in Jack and Cascade. Our third lower Tertiary discovery is St. Malo (Walker Ridge 678). Additional appraisal drilling on St. Malo is pending partner approval and rig availability. We have a 22.5% working interest in the St. Malo discovery.
Canada
We are among the largest independent oil and gas producers in Canada and operate in most of the producing basins in Western Canada. As of December 31, 2005, 30%, or 636 MMBoe, of our proved reserves were in Canada. Properties in Canada also produced 27%, or 62 MMBoe, of our total 2005 production.
Many of the Canadian basins where we operate are accessible for drilling only in the winter when the ground is frozen. Consequently, the winter season, from December through March, is the most active drilling period. We expect to drill about 380 wells in the 2005-2006 winter program in Canada.
We hold approximately 410,000 net undeveloped acres in the Deep Basin in West-Central Alberta, where we drilled 179 wells in 2005 and have another active drilling program planned for 2006. The profitability of our operations in the Deep Basin is enhanced by our ownership in nine gas processing plants in the area. Deep Basin reservoirs tend to be rich in liquids, producing up to 50 barrels of NGLs with each MMcf of gas. Our working interest in the Deep Basin is 46%. Our most significant properties in the Deep Basin include Wapiti, Pinto and Bilbo. Wapiti contributed five MMBoe to our total 2005 production and represented 39 MMBoe of our proved reserves at December 31, 2005. Pinto contributed three MMBoe to our total 2005 production and represented 17 MMBoe of our proved reserves at December 31, 2005. Bilbo contributed three MMBoe to our total 2005 production and represented 38 MMBoe of our proved reserves at December 31, 2005.
Other important oil and gas exploration and development areas in Canada include the Peace River Arch, Northeast British Columbia, Central Alberta and the Lloydminster region of Alberta and Saskatchewan. Our working interests in these areas range from 70% to 97%. At Lloydminster, cold flow heavy oil is found in multiple horizons generally at depths of 1,000 to 2,000 feet. In 2005, we acquired 165,000 net acres in the Iron River area within the greater Lloydminster region. We expect to drill 800 wells at Iron River over the next four years. The following is a summary of our 2005 production and our December 31, 2005 proved reserves for the most significant fields in these areas:
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| | | | | | | | | |
| Field | | Production | | Proved Reserves |
| | | (MMBoe) | | (MMBoe) |
| Dunvegan | | | 3 | | | | 46 | |
| Manatokan | | | 3 | | | | 34 | |
| Narraway | | | 3 | | | | 16 | |
| Lloydminster | | | 2 | | | | 12 | |
| Wargen | | | 2 | | | | 11 | |
The oil sands of Eastern Alberta are a vast North American hydrocarbon resource. We hold over 75,000 net acres of oil sands leases in Alberta. In 2004, we received final regulatory approval to proceed with development of our Jackfish thermal oil sands project, in which we have a 100% working interest. The project is expected to produce 35 MBbls per day of heavy oil when fully operational in 2008. We expect to drill 34 horizontal wells at Jackfish in 2006 along with the construction of the Access dual pipeline. Access will transport diluent and blended crude oil between Jackfish and Edmonton.
International
Beyond our core properties in the United States and Canada, we also look outside North America for longer-term reserve and production growth. At December 31, 2005, these international areas accounted for 12%, or 244 MMBoe, of our worldwide proved reserves. Our international properties also contributed 12%, or 28 MMBoe, to our total 2005 production.
The most significant international producing property is the ExxonMobil-operated Zafiro oil field on Block B, offshore Equatorial Guinea in West Africa. Our working interest in Block B is approximately 24%, and our proved reserves at December 31, 2005 were 78 MMBoe. During 2005, our share of production from Zafiro was 14 MMBoe. We expect to drill nine development wells on Block B in 2006. We drilled a discovery on the Esmeralda prospect on Block B in 2005. We have also identified exploratory prospects on Block B and on three additional blocks in Equatorial Guinea. Three exploratory wells are planned on Block P in 2006. We drilled a discovery well on the Venus prospect on Block P in 2005.
Our second most significant international producing asset is our Panyu project offshore China. We have a 24.5% working interest in this project. Panyu, in the Pearl River Mouth of the South China Sea, was discovered in 1998. Panyu production began late in 2003. We drilled and completed five successful development wells and tested two exploratory prospects during 2005. During 2005, our share of production from China was six MMBoe. Our proved reserves at December 31, 2005 were 16 MMBoe.
We also have an active offshore exploration program in Brazil. We made a discovery in 2004 offshore Brazil on Block BM-C-8. Development of this Polvo discovery commenced in 2005 and first production is expected in 2007. We have a 60% working interest in Polvo. In addition, we, in partnership with Petrobras on three blocks, were the successful bidder on three offshore blocks in Brazil’s bid round seven in 2005. We expect to drill five exploration wells in Brazil in 2006.
In Azerbaijan, we have a 5.6% carried working interest in the Azeri-Chirag-Gunashli, or ACG, oil development project in the Caspian Sea. At December 31, 2005, our share of ACG field proved reserves was 86 MMBoe. In 2005, our share of oil production from the ACG field was less than one MMBoe. However, oil production from the ACG field began ramping up in 2005 after the Central Azeri platform came on-line. Based on economic factors existing at December 31, 2005, our net share of ACG production is expected to increase to between 30 to 35 MBbls per day in early 2007 when payout is reached.
We also hold interests in Angola, Cote d’Ivoire, Egypt, Gabon, Ghana, Indonesia, Nigeria, and Russia. Exploratory wells in Egypt and Nigeria are planned for 2006.
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International, page 24
SEC Comment
| 4. | | Regarding response number 10, please make the proposed changes for the ACG field in an amended 2005 10-K. |
Response
Pursuant to a teleconference with Mr. James Murphy on July 27, 2006, the changes referred to will be made in future filings.
Results of Operations, page 32
SEC Comment
| 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. |
Response
Following is the information requested in your comment.
| | | | | | | | | | | | | | | | | | | | | |
| | | 2001 | | | 2002 | | | 2003 | | | 2004 | | | 2005 | |
| Gross remaining reserves (MBbls) | | | 4,199,998 | | | | 4,545,789 | | | | 4,668,991 | | | | 4,755,399 | | | | 5,261,496 | |
| Gross cumulative production (MBbls) | | | 134,219 | | | | 181,497 | | | | 229,273 | | | | 277,907 | | | | 375,958 | |
| | | | | | | | | | | | | | | | |
| Gross ultimate recovery (MBbls) | | | 4,334,217 | | | | 4,727,286 | | | | 4,898,264 | | | | 5,033,306 | | | | 5,637,454 | |
| | | | | | | | | | | | | | | | |
| Annual increase | | | | | | | 9 | % | | | 4 | % | | | 3 | % | | | 12 | % |
| | | | | | | | | | | | | | | | | | | | | |
| Devon’s net remaining reserves (MBbls) | | | 145,779 | | | | 125,143 | | | | 129,235 | | | | 94,637 | | | | 85,762 | |
| Devon’s net production (MBbls) | | | 194 | | | | 242 | | | | 207 | | | | 205 | | | | 464 | |
| | | | | | | | | | | | | | | | | | | | | |
| Year-end realized ACG price per Bbl | | $ | 16.87 | | | $ | 26.89 | | | $ | 26.56 | | | $ | 35.99 | | | $ | 53.98 | |
As discussed with Mr. Murphy on July 27, 2006, the terms of the production sharing contract, coupled with the increasing oil price as shown in the above table, are the reasons why Devon’s net reserves have declined during this time period even though the gross reserves have increased.
Notes to Consolidated Financial Statements, page 67
Quantities of Oil and Gas Reserves, page 114
SEC Comment
| 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. |
Response
Pursuant to our teleconference with Mr. Murphy on July 27, 2006, we propose to add footnote disclosure of the amount of our annual extensions and discoveries that relate to infill drilling, and such disclosure will be made in future filings. As an indication of the changes we propose to make in future filings, following are the footnotes we previously proposed in our letter of June 8, 2006, as amended to separately disclose the infill drilling activity. As agreed to with Mr. Murphy on July 27, 2006, the quantities and locations of extensions and discoveries from our
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infill drilling activity are shown as “xxx” due to the length of time it will take us to determine such quantities for the last three years.
Noteworthy amounts included in the categories of proved reserve changes for the years 2005, 2004 and 2003 in the above tables include:
| | • | | Extensions and discoveries —The 2005 total includes 118 MMBoe in Canada related to the Jackfish Steam-Assisted Gravity Drainage project which is expected to begin production in 2008; 40 MMBoe related to the Canadian Deep Basin area; and 54 MMBoe added in the United States related to the Barnett Shale area. |
| |
| | | | Of the 401 MMBoe of 2005 extensions and discoveries, xxx MMBoe relates to additions from Devon’s infill drilling activities, including xxx MMBoe related to the xxx area and xxx MMBoe related to the xxx area. |
| |
| | | | The 2004 total includes 32 MMBoe related to the Canadian Deep Basin area, and 29 MMBoe and 28 MMBoe related to the Barnett Shale and Carthage areas, respectively, of the United States. |
| |
| | | | Of the 268 MMBoe of 2004 extensions and discoveries, xxx MMBoe relates to additions from Devon’s infill drilling activities, including xxx MMBoe related to the xxx area and xxx MMBoe related to the xxx area. |
| |
| | | | The 2003 total includes 30 MMBoe related to the Barnett Shale area in the United States. The total also includes Canadian additions of 22 MMBoe related to the Deep Basin area and 15 MMBoe related to Lloydminster heavy oil reserves. |
| |
| | | | Of the 188 MMBoe of 2003 extensions and discoveries, xxx MMBoe relates to additions from Devon’s infill drilling activities, including xxx MMBoe related to the xxx area and xxx MMBoe related to the xxx area. |
| |
| | • | | Purchase of reserves —The 2003 total includes 554 MMBoe acquired in the merger with Ocean described in Note 2. The Ocean reserves were primarily located in the United States, Equatorial Guinea and other various International countries. |
| |
| | • | | Sale of reserves —The 2005 total includes 176 MMBoe of reserves located in the United States and Canada that were divested as part of a plan originally announced in September 2004 as discussed in Note 6. |
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
