 | Devon Energy Corporation 20 North Broadway Oklahoma City, OK 73102-8260 | 405 552 4702 Phone 405 552 7692 Fax danny.heatly@dvn.com |
June 25, 2010
Via EDGAR and Facsimile No. 703 813 6982
Attention: Mr. Norman Gholson, Division of Corporation Finance
Attention: Mr. Norman Gholson, 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
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 the Fiscal Year Ended December 31, 2009 Filed February 25, 2010 Schedule 14A Filed April 28, 2010 Response Letters Dated April 14, 2010 and April 22, 2010 File No. 1-32318 |
Dear Mr. Schwall:
This letter responds to the staff’s comment letter dated June 11, 2010, regarding Devon Energy Corporation’s Form 10-K for the year ended December 31, 2009, filed February 25, 2010, and its Schedule 14A filed April 28, 2010 (the “Proxy Statement”) (File No. 1-32318). Devon’s responses to the staff’s comments are set forth below:
Form 10-K for the Fiscal Year Ended December 31, 2009
Preparation of Reserves Estimates and Reserves Audits, page 20
SEC Comment
| 1. | We note your response to prior comment four from our letter dated March 31, 2010, including your statement that the Director of the Reserve Evaluation Group “has experience in reserves estimation” for projects in specified areas. Please enhance your disclosure to provide details regarding this experience. For example, please describe his role in such projects. Also, we note that the disclosure on page 20 of your Annual Report onForm 10-K states that the Director and key members of the Group have qualifications that “include any or all of” the bulleted items on page 20. Please clarify which of these bulleted items apply specifically to the Director. Provide us with a revised version of your proposed enhanced disclosure. |
Response
We propose that our future disclosures will include the following language:
| The current Director of the Group has been involved with reserves estimation in accordance with SEC definitions and guidance since 1987. He has experience in |
| U.S. Securities and Exchange Commission | page 2 | |
| June 25, 2010 |
| reserves estimation for projects in the United States (both onshore and offshore), as well as in Canada, Asia, the Middle East and South America. He has been employed by Devon for the past eight years, including the past two in his current position as Director of Reserves and Economics. During his career with Devon and others, he was the primary reservoir engineer for projects including, but not limited to: |
Hugoton Gas Field (Kansas)
Sho-Vel-Tum CO2 Flood (Oklahoma)
West Loco Hills Unit Waterflood and CO2 Flood (New Mexico)
Dagger Draw Oil Field (New Mexico)
Clarke Lake Gas Field (Alberta, Canada)
Panyu 4-2 and 5-1 Joint Development (Offshore South China Sea)
ACG Unit (Caspian Sea)
Sho-Vel-Tum CO2 Flood (Oklahoma)
West Loco Hills Unit Waterflood and CO2 Flood (New Mexico)
Dagger Draw Oil Field (New Mexico)
Clarke Lake Gas Field (Alberta, Canada)
Panyu 4-2 and 5-1 Joint Development (Offshore South China Sea)
ACG Unit (Caspian Sea)
| As the primary reservoir engineer, he was responsible for reserves estimation on each of these projects. These reserves estimates were utilized internally and for SEC filings. | ||
| From 2003 to 2010, he has served as the reservoir engineering representative on our internal Peer Review Team, reviewing reserves and resource estimates for projects including, but not limited to: |
Mobile Bay Norphlet Discoveries (Gulf of Mexico Shelf)
Cascade Lower Tertiary Development (Gulf of Mexico Deepwater)
Polvo Development (Campos Basin, Brazil)
Cascade Lower Tertiary Development (Gulf of Mexico Deepwater)
Polvo Development (Campos Basin, Brazil)
| With regard to the penultimate sentence of your comment, we direct you to the first sentence of the paragraph following the bulleted items on page 20 of our Form 10-K, which states, “The current Director of the Group and the Group’s key members all have the qualifications listed above.” |
Proved Oil, Natural Gas and NGL Reserves
Proved Undeveloped Reserves, page 23
SEC Comment
| 2. | We note your response to our prior comment five with regard to your proved undeveloped reserves related to your Jackfish project. Please address the following additional comments regarding this project: |
| • | Your response states that the development schedule for the Jackfish proved undeveloped reserves extends through the year 2025. Please provide us with a summary of the development plan(s) with narrations to explain the extended stages of the Jackfish project(s). | ||
| • | Your response also refers to the Jackfish field as a single development project. Please clarify whether you consider the development of the Jackfish field to be one development project or several separate projects. We refer you to the interpretation in Question 108.01 of the Oil and Gas |
| U.S. Securities and Exchange Commission | page 3 | |
| June 25, 2010 |
| Rules Compliance and Disclosure Interpretations released on October 26, 2009. | |||
| • | Please address the consequences of early termination of the Jackfish project in terms of loss capital verses [sic] reduced return on capital. Explain whether a final investment decision has been made on the entire project, not just on Phase 1 of the project. We refer you to the interpretation in Question 131.04 of the Oil and Gas Rules Compliance and Disclosure Interpretations released on October 26, 2009. | ||
| • | Please provide us a detailed map of the Jackfish field which identifies the portion of the field which you have or are in the process of developing and the portion that remains undeveloped. | ||
| • | Please explain the significant terms of the Jackfish lease contract, including the expiration date. |
Response
Regarding your first bulleted comment, in order to maintain maximum plant capacity at both Jackfish and Jackfish 2 central processing facilities, pad development has been staged over the life of the projects. Table 1 and Table 2 below outline the proven undeveloped reserves for each project, respectively, and the year in which development is expected to occur.
Table 1: Jackfish Reserves Summary at December 31, 2009
| Net PUD | ||||||||||||
| Development | Reserves | Development | ||||||||||
| Status | Reservoir | (MBbls) | Year | |||||||||
| PUD | Pad E | 13,034 | 2010 | |||||||||
| PUD | Pad F | 13,269 | 2011 | |||||||||
| PUD | Pad G | 12,460 | 2012 | |||||||||
| PUD | Pad H | 11,141 | 2014 | |||||||||
| PUD | Pad I | 13,370 | 2015 | |||||||||
| PUD | Pad J | 13,400 | 2016 | |||||||||
| PUD | Pad K | 11,194 | 2017 | |||||||||
| PUD | Pad L | 11,776 | 2018 | |||||||||
| PUD | Pad M | 5,838 | 2019 | |||||||||
| PUD | Pad N | 9,646 | 2021 | |||||||||
| PUD | Pad O | 11,081 | 2022 | |||||||||
| PUD | Pad P | 8,647 | 2023 | |||||||||
| PUD | Pad Q | 9,984 | 2024 | |||||||||
| PUD | Pad R | 7,152 | 2025 | |||||||||
PUD Total | 14 pads | 151,992 | ||||||||||
| U.S. Securities and Exchange Commission | page 4 | |
| June 25, 2010 |
Table 2: Jackfish 2 Reserves Summary at December 31, 2009
| Net PUD | ||||||||||||
| Development | Reserves | Development | ||||||||||
| Status | Reservoir | (MBbls) | Year | |||||||||
| PUD | PAD AA | 8,148 | 2010 | |||||||||
| PUD | PAD BB | 15,348 | 2010 | |||||||||
| PUD | PAD CC | 14,670 | 2010 | |||||||||
| PUD | PAD DD | 9,771 | 2010 | |||||||||
| PUD | PAD EE | 15,674 | 2014 | |||||||||
| PUD | PAD FF | 12,240 | 2013 | |||||||||
| PUD | PAD GG | 12,771 | 2020 | |||||||||
| PUD | PAD HH | 13,736 | 2019 | |||||||||
| PUD | PAD II | 7,704 | 2025 | |||||||||
| PUD | PAD JJ | 14,223 | 2016 | |||||||||
| PUD | PAD KK | 9,868 | 2025 | |||||||||
| PUD | PAD LL | 7,455 | 2024 | |||||||||
| PUD | PAD NN | 10,200 | 2017 | |||||||||
| PUD | PAD OO | 11,723 | 2022 | |||||||||
| PUD | PAD PP | 12,169 | 2015 | |||||||||
| PUD | PAD SS | 12,765 | 2021 | |||||||||
| PUD | PAD TT | 10,079 | 2022 | |||||||||
PUD Total | 17 pads | 198,544 | ||||||||||
Regarding your second bulleted point, the development of both Jackfish and Jackfish 2 are considered to be separate projects by the regulatory bodies within Canada, specifically, Alberta’s Energy Resources Conservation Board, the Canada Revenue Agency and Alberta Environment.
Regarding your third bulleted point, as of December 31, 2009, neither the Jackfish project nor the Jackfish 2 project have reached payout, and therefore neither have provided a return on investment to date. Jackfish started production in late 2007, and Jackfish 2 is still in the construction stage. Early termination of the Jackfish project would result in 67% of the invested capital being unrecovered while an early termination of the Jackfish 2 project would result in a loss of 100% of invested capital.
The final investment decision has been made for both Jackfish and Jackfish 2 projects and approved by Devon’s Board of Directors as per sanction documents in June 2004 and June 2008, respectively.
Regarding your fourth bulleted point, the maps attached to this letter, entitled Area Map for Jackfish and Area Map for Jackfish 2, outline the proven developed subsurface drainage areas that are currently producing, and the proven undeveloped drainage areas. Please refer to Tables 1 and 2 above for development timing.
| U.S. Securities and Exchange Commission | page 5 | |
| June 25, 2010 |
Regarding your fifth bulleted point, the oilsands rights associated with PDP and PUD reserves in the Jackfish area are leased under the provisions of Alberta Crown Oilsands Lease No. 7499050004 (primary term expiry in 2014), 7401010008 and 7401050038 (primary terms expiry in 2016).
The oilsands rights associated with PDP and PUD reserves in the Jackfish 2 area are leased under the provisions of Alberta Crown Oilsands Lease No. 7401090041 and 7401090008 (primary term expiry in 2016).
All leases in the Jackfish and Jackfish 2 areas shall be continued after the primary term based on the production and reserves present in the leased lands, pursuant to the statutorily enacted continuation mechanism and procedure for Alberta Crown oilsands leases.
Proved Reserves Cash Flow, page 24
SEC Comment
| 3. | We note your response to our prior comment seven which states that your year-end costs included in future net revenues are estimated using averages of several prior months’ actual costs. Tell us how your methodology complies with the guidance under ASC Topic 932-235-50-31B that states these costs shall be computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. In this respect, explain how your use of average actual costs incurred provides a basis which enables you to determine current costs as of year-end. |
Response
Our response deals separately with the two general types of costs included in the calculation of future net revenues — (1) production costs and (2) development costs. Our methodology for estimating the year-end production costs begins by using historical average costs. As noted in our response of April 14, 2010, averages of prior months’ costs are used because not all costs are incurred on a consistent month-to-month basis throughout a year. Focusing only on year-end costs will result in omitting the costs of activities that are incurred on a regular annual basis, but not necessarily at the end of the year.
Well workovers are a good example to illustrate this. Workovers are not conducted every month of a year and they may not, and often do not, occur as of year-end. In fact, although Devon has significant workover activity each year, very few workovers are performed on the last day of the year. During the life of many reservoirs, workover activities are routinely performed to maintain or stimulate production levels. Whether such workovers are performed in February, June or December, by using averages throughout the year we include the appropriate amount of workover activity in our cost estimates. The use of historical averages therefore ensures that our estimates of future production costs include all cost activities that are expected to be necessary to produce our proved reserves in the future.
| U.S. Securities and Exchange Commission | page 6 | |
| June 25, 2010 |
Unlike the benchmark commodity prices that are used to estimate year-end oil and gas prices in the calculation of future cash inflows, there are no sources of similar year-end benchmark costs. Generally, averages of several months’ actual costs are a good approximation of year-end costs. However, as we develop and finalize our cost estimates, we examine cost trends in the weeks and months leading up to year-end. We are always mindful of current cost trends, including divergent trends in the geographic regions in which we operate. Operating costs can change rapidly, particularly during periods of significant changes in commodity prices. We also have certain operating costs, such as insurance, that are negotiated at set rates for specific periods of time. Changes in these negotiated rates can occur at anytime throughout a year. Therefore, if cost trends for specific operating activities at the end of the year have trended materially higher or lower than earlier in the year, we will replace average costs with more-current estimates to provide a fair representation of year-end costs.
Regarding development costs, such costs are estimated by examining the prior year’s cost structure to determine average well costs for individual project areas. This cost structure is then adjusted to account for known inflationary or deflationary changes in specific components of the cost structure that have occurred in the weeks and months leading up to year-end. Items that may be reviewed for significant contractual changes include, but are not limited to, drilling rigs, stimulation services, cementing services, oilfield tubulars and other significant tangible items.
We believe the general use of average costs, with adjustments as necessary for end-of-year changes that might occur, produces a fair representation of estimated production and development costs in accordance with Topic 932. Our methodology, or a derivation of it, to estimate year-end costs is widely used in the oil and gas industry. Representatives, including myself, from selected oil and gas companies met with Mr. Wayne Carnall, Mr. Ronald Winfrey and other SEC staff members on July 16, 2009 to discuss the FASB’s proposed amendments to Topic 932 and other issues related to the SEC’sModernization of Oil and Gas Reporting. During that meeting, it was discussed that while the SEC’s new rules changed the historical methodology to calculate prices used to estimate future cash inflows, they did not change the methodology to calculate the related future costs. A discussion of how companies have historically estimated future costs included an acknowledgement by the SEC representatives that companies’ estimates of year-end costs have generally included the use of historical averages. No SEC staff members in attendance proposed that the use of averages to estimate year-end costs would not continue to be an acceptable method to estimate year-end costs.
Exhibits 99.1, 99.2 and 99.3
SEC Comment
| 4. | We note your response to prior comment one from our letter dated April 8, 2010. We may have further comments after the completion of our discussions with Ryder Scott Company. |
Response
| We will await any further comments from you on this matter. |
| U.S. Securities and Exchange Commission | page 7 | |
| June 25, 2010 |
SEC Comment
| 5. | We note your response to prior comment eight from our letter dated March 31, 2010, including your statement that “We will ensure that in our future filings such third-party reports include a declarative statement that is more easily identified.” Please provide us with an example of the enhanced disclosure. |
Response
We propose to include the following language in the third-party reports in our future filings:
| The assumptions, data, methods, and procedures are appropriate for the purposes served by the report. |
SEC Comment
| 6. | Please obtain revised reports that disclose the relevant benchmark prices and weighted average prices from the total company reserve report. See Item 1201(a)(8)(v) of Regulation S-K. Such weighted average prices should be provided by the geographic area required to be provided in the reserves table pursuant to Item 1202(a)(2) of Regulation S-K. We note that the report in Exhibit 99.1 states the benchmark prices but not the adjusted weighted average prices from the relevant reserve report; Exhibit 99.2 does not state either the benchmark prices or the adjusted weighted average prices; and Exhibit 99.3 refers to “hydrocarbon prices ....in affect [sic] at December 31, 2009.” Also, please enhance the disclosures in the Exhibit 99.3 report to clarify the methodology used for calculating the prices. For example, the reference at page 16 of such report to the hydrocarbon prices in effect at December 31, 2009 does not appear to comply with Rule 4-10(a)(22) of Regulation S-X. |
Response
We will ensure that the third-party reports included in our future filings disclose the relevant benchmark prices. Benchmark prices were provided to each of the preparers of the third-party reports. These prices were determined in accordance with Rule 4-10(a)(22)(v) of Regulation S-X by using the unweighted average of the first-day-of-the-month price for the preceding 12-month period.
However, with regard to weighted average prices, each of the third-party reports represents only a portion of our total company reserves. No individual report, nor any combination of reports, is representative of any single geographic area required to be provided in our Form 10-K. Consequently, inclusion of weighted average prices in the third-party reports would have no relevance.
The reference to “hydrocarbon prices ... in affect [sic] at December 31, 2009” should be interpreted to mean “the appropriate prices for use in the preparation of a reserves report to be filed with the SEC with an effective date of December 31, 2009.” This price was calculated in accordance with the provisions ofModernization of Oil and Gas Reporting.
| U.S. Securities and Exchange Commission | page 8 | |
| June 25, 2010 |
Schedule 14A Filed April 28, 2010
SEC Comment
| 7. | We note your disclosure in response toItem 402(s) of Regulation S-K, and specifically your statement on page 32 that “the Committee believes the total executive compensation program does not encourage executives to take unnecessary or excessive risk.” Please describe the process you undertook to reach this conclusion. |
Response
Devon’s compensation committee has primary responsibility for the oversight of Devon’s compensation programs. In exercising this oversight, the committee has helped shaped Devon’s compensation programs to ensure the amounts and types of compensation paid serve the best interests of Devon and its shareholders. To allow Devon to effectively execute on its operating strategy, our executive compensation program is designed to strike the appropriate balance between near-term operational and financial success and long-term value creation. As described in the “Compensation Philosophy and Objectives — Overview” section of the CD&A on page 22 of the Proxy Statement, one of the goals of Devon’s compensation program is to, among other things, provide balanced incentives for the achievement of near-term and long-term objectives, without motivating executives to take unnecessary risk.
The committee reviewed and discussed Devon’s executive compensation program with the committee’s independent compensation consultant. In connection with this discussion, the committee noted the following factors that discourage Devon’s executives from taking unnecessary or excessive risk:
| • | Devon’s operating strategy and the related compensation philosophy; | ||
| • | The effective balance, in each case, between cash and equity mix, near-term and long-term focus, corporate and individual performance, and financial and non-financial performance; | ||
| • | A non-formulaic approach to performance evaluation and compensation that does not reward an executive for engaging in risky behavior to achieve one objective to the detriment of other objectives; and | ||
| • | Executive stock ownership pursuant to our stock ownership guidelines. |
Based on this review and discussion, the committee concluded that the total executive compensation program does not encourage Devon’s executives to take unnecessary or excessive risk.
Related Party Transactions, page 14
SEC Comment
| 8. | We note your disclosure regarding related party transactions. Please provide the disclosure required byItem 404(b) of Regulation S-K. |
| U.S. Securities and Exchange Commission | page 9 | |
| June 25, 2010 |
Response
Devon does not have a separate policy regarding the review and approval of transactions with related persons of the type that are required to be reported by Item 404(a) of Regulation S-K. However, as noted on page 14 of the Proxy Statement, Devon believes that any such transactions would be subject to review under its Code of Business Conduct and Ethics. As further noted in the Proxy Statement, the review would be conducted by Devon’s audit committee in accordance with the audit committee’s charter. Devon expects that in determining whether or not to approve any such transactions that may occur in the future, the audit committee would consider all relevant facts and circumstances of the proposed transactions, including any applicable legal standards, such as those standards contained in applicable state corporate law. Devon undertakes to expand upon this disclosure in future filings if it adopts any additional policies and procedures.
Compensation Discussion and Analysis, page 21
Compensation Decisions in 2009, page 29
Long-Term Incentives, page 31
SEC Comment
| 9. | We note your disclosure regarding the approval of long-term equity grants for 2009. Please expand your disclosure to describe all the “other factors” that your compensation committee considered with respect to such grants, or tell us why such other factors were not material. |
Response
In connection with the approval of the long-term incentive awards made to executive officers for 2009, Devon’s compensation committee considered the 2009 benchmarking results as well as the other factors described in “Long-Term Incentives” under the “Overview of Executive Compensation Elements in 2009” section of the CD&A on page 27 of the Proxy Statement. The reference to those other factors describes the process that the committee customarily undertakes when making the annual long-term incentive awards. With respect to the 2009 equity awards, while each of those factors was considered individually and in the aggregate, none of them individually had any material impact on the size of the awards made to any of the executive officers. Instead, the only factor that was individually significant in determining the size of the equity awards (other than the 2009 benchmarking survey) was the factor cited on page 31 of the Proxy Statement, namely, the strategic direction set by Devon’s executive officers during 2009. Based on this assessment, the committee determined it was appropriate to approve grants similar in value to those in the prior year, with the expectation that those values would generally fall within Devon’s market objective of the 50th to 75th percentile of its peers.
| U.S. Securities and Exchange Commission | page 10 | |
| June 25, 2010 |
In connection with the above responses to the staff’s comments, Devon acknowledges that:
| • | Devon is responsible for the adequacy and accuracy of the disclosure in the filings; | ||
| • | Staff comments or changes to disclosure in response to staff comments do not foreclose the Commission from taking any action with respect to the filings; and | ||
| • | Devon may not assert staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States. |
| Sincerely, | ||||
| /s/ Danny J. Heatly | ||||
| Danny J. Heatly | ||||
| Senior Vice President — Accounting and Chief Accounting Officer | ||||
| U.S. Securities and Exchange Commission | page 11 | |
| June 25, 2010 |
| U.S. Securities and Exchange Commission | page 12 | |
| June 25, 2010 |
