CORRESP 1 filename1.htm corresp
 

[DEVON LOGO]
 
Brian J. Jennings
Senior Vice President and
Chief Financial Officer
Devon Energy Corporation
20 North Broadway
Oklahoma City, Oklahoma 73102-8260
Direct: 405/552-7838
Direct Fax: 405/552-8109
June 8, 2006
Via EDGAR and
Facsimile No. 202-772-9368
Attention: Gary Newberry,
Division of Corporation Finance
H. Roger Schwall
Assistant Director
U. S. Securities and Exchange Commission
100 F Street, N.E.
Washington, D.C. 20549-7010
Re:   Devon Energy Corporation
Form 10-K for Fiscal Year Ended December 31, 2005
Filed March 3, 2006
File No. 1-32318
Dear Mr. Schwall:
This letter responds to the staff’s comment letter dated May 12, 2006, regarding Devon Energy Corporation’s Form 10-K for the year ended December 31, 2005, filed March 3, 2006 (File No. 1-32318). Devon’s responses to the staff’s comments are set forth below:
Proved Reserves and Estimated Future Net Revenues, page 18
SEC Comment
1.   We note your disclosure of Pre-tax 10% Present Value (“PV10”) and the related footnote in the table presented. We also note your responses to SEC comments 2 and 3 in your letter to us dated January 14, 2005. In your January letter, you provided example disclosures to be included in your future filings which included a quantitative disclosure of the amount of discounted future taxes that were excluded from your measure PV10. It appears that this disclosure has not been carried forward in your current filing. We believe a quantitative disclosure of the difference between PV10 and the Standardized Measure is necessary for an investor’s understanding of that measure. Please revise your disclosure to include a quantitative reconciliation of the difference between your measure of PV10 and the Standardized Measure. Refer to Regulation S-K Item 10(e)(1)(i)(B).

 

 

U.S. Securities and Exchange Commission
June 8, 2006
Page 2
Response
Subsequent to our letter of January 14, 2005 and prior to the filing of our 2005 Form 10-K, we revised the locations of the PV 10% and standardized measure figures as compared to where they were disclosed in the 2003 Form 10-K that was the subject of our prior response. Following these disclosure revisions, we believed that our existing disclosures were adequate with regard to the difference between the two measures. However, with the addition of the following three sentences to the beginning of the second paragraph of footnote 2 on page 19 of our 2005 Form 10-K, all of the disclosures referenced in our January 14, 2005 letter would be included in our current filing:
The present value of after-tax future net revenues discounted at 10% per annum (“standardized measure”) was $23.6 billion at the end of 2005. Included as part of standardized measure were discounted future income taxes of $12.0 billion. Excluding these taxes, the present value (“pre-tax 10% present value”) was $35.6 billion.
We propose the addition of the above disclosure to our 2006 Form 10-K rather than in an amendment of our 2005 Form 10-K.
Management Discussion and Analysis of Financial Condition and Results of Operations, page 36
SEC Comment
2.   Please revise your discussion to provide a separately captioned section discussing off-balance sheet arrangements as required by Regulation S-K Item 303 (a)(4). If you have no such arrangements, amend your filing to disclose this fact.
Response
As of December 31, 2005, Devon had no off-balance sheet arrangements as defined by Item 303 (a)(4). However, we do not find in Item 303 (a)(4) any requirement to specifically disclose the lack of such arrangements and do not believe that such disclosure would be material to investors.
Engineering Comments
Risk Factors, page 13
SEC Comment
3.   Reconcile the statement that reserves estimates “may change substantially over time” with the concept of “reasonable certainty.”
Response
Reasonable certainty has been described in SEC guidance as meaning that reserves are much more likely to increase (positive revision) than to decrease (negative revision) as more data is obtained over the producing life of the property. Estimates of proved reserves are known to include certain levels of imprecision because of the uncertainty in the parameters that are included in the calculation of reserve estimates. This uncertainty applies to all estimation techniques, including those based on volumetric parameters, performance trends, and material balance and reservoir simulation with history match. As production and pressure data are gathered over the life of the reservoir, reserves are almost certain to change, and in some cases change substantially.
Another potentially significant uncertainty inherent in the estimates of proved reserves is economic uncertainty, which can be positive or negative over time. The economic uncertainties include both product price uncertainty and political uncertainties, both domestically and internationally. As examples of price uncertainties, note on page 118 the downward revisions to our estimates of International proved reserves that were attributed to changes in prices. As noted in the reconciliations on page 118, our proved International reserves were revised downward by 14% in 2004 and by 8% in 2005 due solely to changes in prices from one year-end to the next.

 

 

U.S. Securities and Exchange Commission
June 8, 2006
Page 3
Our comments in the risk factor discussion on page 13 are intended to explain the inherent risks and uncertainties in finding, exploiting and producing oil and gas reserves. We do not believe that our comments conflict with the concept of “reasonable certainty.”
Properties, page 16
Proved Reserves and Estimated Future Net Revenue, page 16
SEC Comment
4.   Revise the document to include the definition of proved reserves as found in Rule 4-10(a) of Regulation S-X.
Response
We will add the following disclosure to page 16:
The SEC defines proved oil and gas reserves as the estimated quantities of crude oil, natural gas and NGLs which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.
We propose the addition of the above disclosure to our 2006 Form 10-K rather than in an amendment of our 2005 Form 10-K.
SEC Comment
5.   Tell us if the independent engineers that prepared and audited your proved reserves did their own geological mapping for the reserve work they performed.
Response
In some cases, where maps are required to estimate reserves, independent engineers prepare their own maps completely from raw data. However, in most cases, independent engineers begin with company maps and revise them to reflect their interpretation of structure. In many cases, net pay isopach maps are drawn by the independent engineers to reflect their interpretation of the distribution of the reservoir volume. In all cases, the maps used by independent engineers are prepared, accepted or modified as necessary in their opinion and are intended to be, in their opinion, accurate representations of the subsurface using the data as known at the time.
SEC Comment
6.   You state that in the past five years your annual performance related revisions have averaged approximately 1% of the previous year’s estimate. According to FASB 69 paragraph 30, revisions should include reserve additions from development drilling. Please advise us if you include these as revisions.
Response
Paragraph 30 of FASB 69 deals with the disclosure of the standardized measure of discounted future net cash flows. Therefore, we have assumed that you intended to reference paragraph 11(a) of FASB 69, and the balance of our response is based on this assumption.
Paragraph 11(a) (Revisions of Previous Estimates) states that “revisions represent changes in previous estimates of proved reserves, either upward or downward, resulting from new information (except for an increase in proved acreage) normally obtained from development drilling and production history or resulting from a change in economic factors.” When reserves related to development drilling can be initially recorded as proved undeveloped

 

 

U.S. Securities and Exchange Commission
June 8, 2006
Page 4
reserves, changes to the booked proved undeveloped reserves after the well is drilled result in revisions to proved reserves. We believe that reserves added from locations which had not previously been recorded in the booked proved reserves and that will require the expenditure of future capital to actually develop such reserves, are properly recognized as “extensions and discoveries” pursuant to paragraph 11(d)(1), as these wells extend the proved acreage of the field, even though that acreage may lie between existing wells.
Prior to the recognition of reserves related to locations not categorized as proved undeveloped, our total recorded proved reserves would not include any estimate of such reserves nor a location related to the recovery of such reserves. Therefore, it appears contradictory to characterize the initial recording of proved undeveloped reserves as revisions to “previous estimates” when there were no such previous estimates recorded.
One of our goals is to book the initial estimate of extended or discovered proved reserves as accurately as possible. We believe the percentage of yearly revisions unrelated to price changes is a useful indicator to our investors of the reliability of our procedures that are followed in initially recording proved reserves. If new proved undeveloped reserves from future development drilling were to be included as “revisions to previous estimates,” it could lead to quantities shown as “revisions” that could be a significant percentage of the prior year estimates, and thus could lead to a erroneous perception that the company’s methods of originally estimating its proved reserves are unreliable.
Operation of Properties, page 21
SEC Comment
7.   Instruction 3 to Item 102 of Regulation S-K requires material disclosure such as reserves, production and interest about significant properties. However, your filing does not appear to contain all of the necessary disclosures for the properties you discuss. Please revise as necessary.
Response
Instruction 3 to Item 102 of Regulation S-K requires the disclosure of material information as to production, reserves, locations, development and the nature of the registrant’s interest. The table on page 21 discloses reserves and value for each of our main geographic regions of operations. More specific information regarding the locations, development and nature of our interest in the primary fields within each of these main geographic regions is provided on pages 22 through 25. It appears to us that the only information mentioned in Instruction 3 that is missing is production data related to the main geographic regions of operations.
Accordingly, we propose the addition of a table on page 21 which will disclose 2005 production volumes of oil, gas and NGLs for each of the Permian Basin, Mid-Continent, Rocky Mountain, Gulf Coast Onshore, Gulf Offshore, Canada and International geographic regions.
We propose the addition of the above disclosure to our 2006 Form 10-K rather than in an amendment of our 2005 Form 10-K.
We do not consider any of our individual properties to be of “major significance,” therefore the information described in Instruction 3(A) and 3(B) is not applicable.
SEC Comment
8.   Tell us if you include any reserves based on plant ownership rather than leasehold interest. If so, revise your document to disclose these separately from the other reserves, if material.
Response
All of our reserves are attributable to leasehold interests.

 

 

U.S. Securities and Exchange Commission
June 8, 2006
Page 5
SEC Comment
9.   Advise us if you will produce all the reserves from your PSC’s prior to the end of the contract terms.
Response
All reserves booked under production sharing contracts are expected to be produced within the limits of the corresponding contract terms.
International, page 24
SEC Comment
10.   You state that you estimate the ACG field in Azerbaijan contains over 5 billion barrels of gross proved oil reserves and that you have a 5.6% working interest. SEC rules only allow you to disclose reserves that are net to your interest. Also, as you have a 5.6% interest this would indicate that your net reserves are approximately 245 million barrels. However, you have only disclosed a total of 244 million barrels for proved reserves for your entire international operations. Please reconcile these apparent inconsistencies and revise your document as necessary.
Response
The calculation in your comment appears to assign a 12.5% royalty to the ACG field in order to arrive at the estimated 245 million barrels net to Devon’s interest. The ACG contract is a rate-of-return contract that results in a royalty rate considerably more than 12.5%. In fact, the year-end 2005 effective royalty rate was over 70%. Accordingly, Devon’s net reserves in the ACG field at year-end 2005 were approximately 85.8 million barrels.
We propose to delete the sentence on page 25 that refers to the five billion barrels of gross reserves. In its place we will add the following statement:
Devon’s net proved reserves in the ACG field at the end of 2005 totaled approximately 85.8 million barrels.
We propose the addition of the above disclosure to our 2006 Form 10-K rather than in an amendment of our 2005 Form 10-K.
Selected Financial Data, page 28
Operating Results, page 28
SEC Comment
11.   Tell us if the average prices shown here include the effects of hedging. If so, you should revise the document to note this in the filing.
Response
Yes, the average prices include the effects of hedging. As disclosed in footnote 2 on page 29, “The preceding price data includes the effect of derivative financial instruments and fixed-price physical delivery contracts.”
SEC Comment
12.   Tell us if the average production and operating expenses include production taxes. If not, you should revise your document to include these.

 

 

U.S. Securities and Exchange Commission
June 8, 2006
Page 6
Response
Yes, the average production and operating expenses include production taxes. Please note the table on page 36, which indicates that the amounts of production and operating expenses per Boe include lease operating expenses and production taxes.
Results of Operations, page 32
SEC Comment
13.   You disclose, before the effect of hedging, your 2005 average oil price to be $48.49 per barrel. However, according to the EIA website, the average 2005 oil price of Brent and WTI was $54.60 and $56.58 per barrel, respectively. Please reconcile to us your reported average oil prices to us with those on the EIA website.
Response
WTI and Brent are probably the two most commonly referenced types of crude oil. However, as the EIA website also points out, there are about 161 different internationally traded crude oils that vary in terms of characteristics, quality and market penetration. Crude oil is referred to as either “light” or “heavy” depending on its API gravity, with light crude being those with the higher API gravity. Crude oil is also referred to as either “sweet” or “sour” depending on its sulfur content, with sweet crude containing lower levels of sulfur. Both WTI and Brent are characterized as light sweet crude. Light sweet crude demands the highest market price of all the various grades of crude. As such, WTI and Brent are used as “reference prices,” but a significant portion of world oil production is of lower quality than WTI and Brent, and accordingly is sold at prices that are discounted to WTI and Brent prices.
For 2005, only around 20% of Devon’s oil production met WTI or Brent quality characteristics. The remaining 80% of oil produced in 2005 was heavier and/or sourer than WTI and Brent grades of crude. Therefore, the difference between Devon’s average price of $48.49 and the WTI and Brent prices of $56.58 and $54.60 is due primarily to the lower prices for grades of crude oil that are inferior in quality to WTI and Brent.
The timing of a company’s oil production will also cause discrepancies between its reported average prices and averages of WTI or Brent such as those posted on the EIA website. The average prices on the EIA website are simple averages, with each day’s price throughout the year evenly weighted in the average price. However, a company will not produce the same quantities of oil each day throughout the year. The timing of new production coming on line, or acquisitions and sales of existing production, or production deferred due to hurricanes, will cause a company’s average reported sales price to be a weighted (not simple) average. For example, Devon produced approximately 64 million barrels of oil in 2005. However, due to the impact of property divestitures that occurred in the first half of the year, combined with the impact of Gulf of Mexico properties that were damaged by 2005 hurricanes, our production in the first half of 2005 was approximately 35 million barrels, compared to 29 million barrels produced in the second half of 2005. Oil prices were increasing throughout 2005, and Devon’s oil production was weighted more toward the first half of the year when prices were lower. Therefore, even if 100% of Devon’s 2005 oil production had been crude with WTI quality characteristics, Devon’s reported average oil price for 2005 would have been lower than a daily average of an index price that weights every day’s price evenly throughout the year.
We provide forward-looking estimates in our annual Form 10-Ks that include estimates of the discount to WTI prices that we expect to realize from our crude oil production in the upcoming year. On page 57 of our 2004 Form 10-K, we disclosed that in 2005, we expected the average price of our domestic oil production (before the effects of hedges) to be approximately 93% of WTI, and approximately 78% for our Canadian oil production and approximately 87% for our International oil production. The actual percentages for domestic, Canadian and International oil production were 94%, 75% and 90%, respectively. As noted on page 54 of our 2005 Form 10-K, we expect our 2006 realized oil prices will be at slightly higher discounts to WTI than in 2005.

 

 

U.S. Securities and Exchange Commission
June 8, 2006
Page 7
SEC Comment
14.   Supplementally, tell us if you attributed proved reserves to locations that are not adjacent to productive wells. Submit to us the engineering and geologic justification for PUD reserves you have claimed that are not in legal, technically justified locations offsetting (adjacent to) productive wells. Otherwise, affirm to us that none of your claimed PUD reserves are attributed to such locations.
Response
The only field in which proved undeveloped reserves are booked which are not adjacent to productive wells is the ACG field in Azerbaijan. This field has demonstrated pressure communication across large distances, and our rationale for calculating our proved reserves in this field was presented to the SEC staff, including Mr. Ron Winfrey, in late 2001 during the staff’s review of our Registration Statement on Form S-4 (No. 333-68694) filed in connection with Devon’s merger with Mitchell Energy and Development Corp. Since our discussions with the staff over four years ago, the field has exceeded all expectations, development of the field is continuing and nothing has come to our attention that would cause us to change our previous conclusions.
Notes to Consolidated Financial Statements, page 67
Quantities of Oil and Gas Reserves, page 114
SEC Comment
15.   Please revise your document to disclose reserves under Production Sharing Contracts separately from those reserves attributed to leasehold arrangements.
Response
All of our International reserves are attributable to production sharing contracts. This is disclosed on page 118.
SEC Comment
16.   Your reserve table indicates that you increased reserves in each of the last three years from 12 to 19% per year through extensions and discoveries. Please expand your disclosure to include details on these additions as instructed by FASB 69. Revise your disclosure if necessary for the three years presented to indicate new reserves from development and infill drilling as revisions rather than extensions and discoveries as instructed by FASB 69.
Response
We propose to add the following disclosure to page 118 following the reconciliation tables:
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.
 
      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.
 
      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.

 

 

U.S. Securities and Exchange Commission
June 8, 2006
Page 8
  •   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.
We propose the addition of the above disclosure to our 2006 Form 10-K rather than in an amendment of our 2005 Form 10-K.
As noted in our response to comment #6, we do not agree with the staff’s interpretation of paragraph 11(a) of FASB 69, and do not believe it appropriate to classify new reserves related to future development and infill drilling as revisions rather than extensions and discoveries.
Standardized Measure of Discounted Future Net Cash Flows, page 119
SEC Comment
17.   Reconcile for us the year-end prices of $45.50 per barrel of oil, $7.84 per Mcf of gas and $32.46 per barrel of NGLs as stated in the document with the December 30, 2005 closing spot prices for WTI of $61.06 per barrel, Brent of $58.34 and Henry Hub gas of $10.05 per MMBtu.
Response
With regard to the difference between our net realized oil price of $45.50 and the year-end WTI and Brent prices of $61.06 and $58.34, please see our response to comment #13. (The portion of our response to comment #13 regarding the effects of weighted averages of production versus simple averages of prices would not apply to this comment #17.)
Much like WTI and Brent are benchmark references for oil, so is Henry Hub a benchmark reference price for natural gas. And similar to the oil situation discussed in our response to comment #13, a substantial portion of natural gas production is sold at prices that are discounted to Henry Hub. Unlike oil, where the primary cause of a discount price to WTI and Brent is the quality of the crude, the discount to Henry Hub is primarily due to the geographic location of the gas production.
The Henry Hub is the largest centralized point for natural gas spot and futures trading in the United States. The Henry Hub interconnects numerous interstate and intrastate pipelines near Erath, Louisiana. Collectively, these pipelines provide access to markets in the Midwest, Northeast, Southeast and Gulf Coast regions of the United States.
The markets to which natural gas production can be delivered and sold are limited by the pipeline infrastructure in the specific area in which the gas is produced. Accordingly, a substantial portion of gas produced in North America is sold to markets other than those connected to the Henry Hub pipelines. As a result, there are numerous and varied prices paid for natural gas depending on the individual supply and demand dynamics in each region. In fact, a Cambridge Energy Research Associates (“CERA”) study in 2005 noted that the Henry Hub gas price has increasingly become a poor proxy for average North American gas prices.
Prices for gas production that do not access the Henry Hub markets are based on the prevailing prices in the markets that can be accessed. There are numerous price indices across North America that are used as a basis to price natural gas production from each specific geographic region. As noted in your comment, the year-end 2005 Henry Hub price was $10.05 per MMBtu. However, a substantial portion of Devon’s gas reserves are located in geographic regions whose specific gas price indices were significantly lower than Henry Hub at the end of 2005. The following table provides some information for three of such regions. The year-end 2005 price indices for the

 

 

U.S. Securities and Exchange Commission
June 8, 2006
Page 9
Fort Worth Basin, Rocky Mountain and Canadian regions, the relative discounts of these indices to the Henry Hub price of $10.05, and each region’s share of Devon’s year-end 2005 proved natural gas reserves were as follows:
                         
    Regional   Differential   % of Year-End
    Index   to Henry   2005 Natural
    Price   Hub Price   Gas Reserves
Fort Worth Basin
   $ 7.55     $ (2.50 )     27 %
Rocky Mountains
   $ 7.72     $ (2.33 )     15 %
Canada
   $ 8.57     $ (1.48 )     27 %
The prices assigned to Devon’s natural gas reserves in its 2005 standardized measure were based on the prices applicable to reserves in each region across North America. As noted in the above table, at the end of 2005 there were significant discrepancies between the Henry Hub price and the regional prices in these three specific areas that included 69% of Devon’s proved natural gas reserves. These area differentials were the primary reason that Devon’s average year-end 2005 gas price was $7.84 compared to the Henry Hub price of $10.05.
Also note that the Henry Hub index price is denoted as a dollar amount per “MMBtu.” Devon and other natural gas producers report their production and proved reserve quantities in “Mcf’s” as required by FASB 69, and therefore our reported average prices are stated as a dollar amount per Mcf. Comparing prices per Mcf to prices per MMBtu will also cause a certain amount of discrepancy.
*************************
In connection with the above responses to the staff’s comments, Devon acknowledges that:
  •   Devon is responsible for the adequacy and accuracy of the disclosures in the filing;
 
  •   Staff comments or changes to disclosure in response to staff comments do not foreclose the Commission from taking any action with respect to the filing; and
 
  •   Devon may not assert staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States.
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