SEC Company Response from DEVON ENERGY (DVN) — Jan 11, 2013
DEVON ENERGY CORP/DE (DVN) (CIK 0001090012)
Date: Jan. 11, 2013 · CIK: 0001090012 · Accession: 0001193125-13-010608
AI Filing Summary & Sentiment
Reasoning
File numbers found in text: 001-32318
Referenced dates: December 13, 2012
Letter
Via EDGAR Attention: Ms. Svitlana Sweat, Division of Corporation Finance United States Securities and Exchange Commission Re: Devon Energy Corporation Form 10-K for the Fiscal Year Ended December 31, 2011 Filed February 24, 2011 File No. 001-32318
Dear Mr. Schwall:
This letter responds to the staff’s comment letter dated December 13, 2012, regarding Devon Energy Corporation’s Form 10-K for the year ended December 31, 2011, filed February 24, 2012 (File No. 001-32318). Devon’s responses to the staff’s comments are set forth below:
Form 10-K for Fiscal Year Ended December 31, 2011
Oil and Gas Properties, page 4
Production, Production Prices and Production Costs, page 10
SEC Comment
1. We note you disclose the production and average sales price by final product sold on page 10 and elsewhere in your filing on Form 10-K. In regards to disclosure by final product sold, we note on page 7 you state that Jackfish is a “non-conventional oil sands” project. Furthermore, in the section entitled “Projects Overview” under “Operations-Jackfish Projects” on your company website (http://www.devonenergy.com/Operations/Canada/Pages/jackfish_project), you state steam assisted gravity drainage is “being used to extract the bitumen over the life of the projects”; however, it does not appear that you make reference to or distinguish between bitumen and oil as final sales products in your filing on Form 10-K as required by Item 1204(a) of Regulation S-K. Revise your presentation to break out bitumen separately or tell us why you do not believe that is appropriate. See also Instruction 3 to Item 1204 of Regulation S-K.
Response
Jackfish is currently our only project with bitumen production, which totaled 13 million, 9 million and 8 million barrels in 2011, 2010 and 2009, respectively. This production represented 5%, 4% and 3% of our total production for 2011, 2010 and 2009, respectively. We will revise our presentation to break out bitumen production and average sales prices separately as required by Item 1204(a) in future filings.
Table of Contents
H. Roger Schwall
United States Securities and Exchange Commission
Page
January 11, 2013
Notes to Consolidated Financial Statements
Note 6 – Income Taxes, page
SEC Comment
2. We note that you recognized deferred income tax expense of $725 million during the fiscal year ended December 31, 2011 related to the assumed repatriations of earnings from your foreign subsidiaries. We also note the disclosure per page 39 of your filing which states that the majority of your cash and short-term investments consist of the proceeds from your international offshore divestitures which are held by certain of your foreign subsidiaries. This disclosure also states that you do not currently expect to repatriate such amounts to the United States. Please tell us the factors considered by management in its conclusion that these amounts will not be repatriated. Your response should also outline your plans for the permanent reinvestment of the undistributed earnings of your foreign subsidiaries. Refer to FASB ASC 740-30-25-17. In connection with your response, please quantify the amount of cash and short-term investments held by your foreign subsidiaries.
Response
Of the $7.1 billion of cash and short-term investments we held at December 31, 2011, $6.9 billion was held by our foreign subsidiaries, of which $4.3 billion was deemed repatriated. We had recognized $936 million of deferred income tax expense for deemed repatriations through the year ended December 31, 2011 (see deferred tax liability for taxes on unremitted foreign earnings on page 67 of our December 31, 2011 Form 10-K). We recognized virtually all this deferred income tax expense in 2009, 2010 and 2011, including the $725 million recognized in 2011.
While we have recognized deferred income taxes for deemed repatriations on a portion of our unremitted foreign earnings, we have determined that certain of our unremitted foreign earnings are being permanently reinvested. To form our permanent reinvestment conclusions, we consider the financial requirements of our U.S. companies and our foreign subsidiaries, the tax consequences of any remittances, and the operational and fiscal objectives of our U.S. companies. More specifically, we consider our cash and investments on hand, forecasted after-tax cash flows, and availability of other cash resources, including commercial paper borrowings and debt offerings in the U.S. in a favorably low interest-rate environment.
Our plans to permanently reinvest a portion of the unremitted earnings of our foreign subsidiaries are based on our investment programs and related cash flow forecasts of our respective U.S. and foreign operations. Specifically, our U.S. operations are self-funding through earnings and cash flow from the underlying assets or debt issuance due to a very strong balance sheet and favorable borrowing conditions. However, the capital investment needs of our Canadian operations are expected to exceed the cash inflows largely because of on-going investments in our multi-billion dollar, long-lead time and capital-intensive oil sands development projects. Accordingly, the unremitted foreign earnings that have funded or will fund our ongoing Canadian operations are deemed permanently reinvested.
Supplemental Information on Oil and Gas Operations (Unaudited), page 88
Proved Reserves, page 91
SEC Comment
Table of Contents
H. Roger Schwall
United States Securities and Exchange Commission
Page
January 11, 2013
3. We note you disclose the net quantities and changes in your proved oil reserves on page 91. It does not appear that you make reference to or distinguish between bitumen and oil as product types in disclosing your net reserve quantities here or elsewhere in your filing on Form 10-K. The table should reflect products in the form in which they are sold. Thus, if you sell bitumen it should be broken out separately from oil, even if it will be upgraded to synthetic oil or gas by the purchaser. If you upgrade the bitumen to synthetic oil or gas prior to sale, then present those quantities separately as synthetic oil or synthetic gas. See Item 1202(a)(4) of Regulation S-K and FASB ASC 932-235-50-4.
Response
Jackfish is currently our only project with bitumen proved reserves, which totaled 457 million, 440 million and 403 million barrels at December 31, 2011, 2010 and 2009, respectively. These proved reserves represented 15% of our total proved reserves as of each year ended December 31, 2011, 2010 and 2009. We will revise our presentation to break out bitumen proved reserves separately as required by Item 1204(a)(4) and FASB ASC 932-235-50-4 in future filings.
Proved Undeveloped reserves, page 95
SEC Comment
4. We note your disclosure of the total quantity of proved undeveloped reserves at the 2011 year end and the material changes in proved undeveloped reserves that occurred during the year, including the net quantities of proved undeveloped reserves converted into proved developed reserves as required by Items 1203(a) and 1203(b) of Regulation S-K. Please expand your disclosure to also address the investments, including the capital expenditures, made during the year to convert your proved undeveloped reserves to proved developed. See Item 1203(c) of Regulation S-K.
Response
During 2011, we invested approximately $1.3 billion to convert our proved undeveloped (“PUD”) reserves to proved developed. In future filings, we will include in the discussion of PUD reserves expanded disclosure that includes the amount of capital expenditures incurred to convert our PUD reserves to proved developed such as the following: “Costs incurred for the year ended December 31, 2011, related to the development of proved undeveloped reserves were $1.3 billion.”
SEC Comment
5. We note you disclose that revisions during 2011 other than price decreased your proved undeveloped reserves primarily due to the evaluation of certain U.S. onshore dry-gas areas, which the Company “does not expect to develop in the next five years.” For purposes of determining the five year period, Item 1203(d) of Regulation S-K identifies the initial disclosure and date thereof as the starting reference date. Please tell us if any of your proved undeveloped volumes disclosed as of December 31, 2011, other than those attributed to Jackfish or included in the revision as noted, will take more than five years since initial disclosure to develop.
Response
Excluding our Jackfish PUD reserves, we had 0.75 million Boe of PUD reserves, which represented 0.02% of our total proved reserves, that are expected to take more than five years to develop since initial disclosure. These PUD reserves relate to one immaterial Canadian property in which the gas cap is scheduled for development upon the depletion of the oil leg of the reservoir in accordance with the regulations of the Energy Resources Conservation Board of Alberta. These reserves are consistent with the definition of undeveloped oil and gas reserves in Rule 4-10(a)(31)(ii) of Regulation S-X.
Table of Contents
H. Roger Schwall
United States Securities and Exchange Commission
Page
January 11, 2013
SEC’s Modernization of Oil and Gas Reporting, page 96
SEC Comment
6. We note you disclose that the Company’s 2009 reserves increased approximately 2% as a result of adopting the provisions in the new rules permitting the use of reliable technologies to establish the reasonable certainty of proved reserves. Furthermore, you state “this increase is included in the 2009 extensions and discoveries total.” We note your 2011 extensions and discoveries amount to 14.7% of the opening balance of total proved reserves on a boe basis and were attributed to your activities in the Cana-Woodford Shale, Barnett Shale, Permian Basin, Jackfish, Rocky Mountain and Granite Wash areas. Additionally, we note your 2010 extensions and discoveries amount to 13% of the opening balance of total proved reserves on a boe basis and were attributed to your activities in the Cana-Woodford Shale, Barnett Shale, Jackfish, Permian Basin, Rocky Mountain and Carthage areas. Please tell us if any of the volumes relating to extensions and discoveries for years ending 2011 and 2010 are attributable to reliable technologies and if so whether you consider the related volumes material in light of Item 1202(a)(6) of Regulation S-K.
Response
In both 2011 and 2010, our extensions and discoveries included volumes that are based upon reliable technologies. However, the volumes represent less than 2% of our reserves at the beginning of each year. Therefore, absent acknowledgement of the impact of a rule change, which was the case for our 2009 disclosure, we considered the 2011 and 2010 amounts to be immaterial.
Standardized Measure, page 97
SEC Comment
7. We note you state “future cash inflows, development costs and production costs were computed using the same assumptions for prices and costs that were used to estimate Devon’s proved oil and gas reserves at the end of each year.” You also state “for 2011, the prices averaged $67.31 per barrel of oil, $3.51 per Mcf of gas and $39.28 per barrel of natural gas liquids”; however, these average prices do not appear to correspond to your disclosures on prices found on pages 10, 27 or 29 of your filing on Form 10-K. Please explain why these prices differ from the prices provided elsewhere in your disclosure on Form 10-K.
Response
As required by FASB ASC 932-235 and disclosed on page 96, the future cash inflows and resulting average realized prices on page 97 are calculated using prices that represent the unweighted arithmetic average of the first-day-of-the-month price for the preceding 12-month period (i.e., January 1, 2011 to December 1, 2011). While a portion of our production is sold based on first-day-of-the-month prices, a portion is sold based on daily prices, particularly our oil and NGL production. Additionally, the composition of each of our commodity products sold changes over time because of variations in production development schedules and decline rates. Consequently, our overall average realized prices for each commodity will change over the producing life of our proved reserves and, thus, will not necessarily be the same as those for 2011. Therefore, because we do not sell all our production based on first-day-of-the-month prices and the composition of our product sales changes over time, the prices on pages 10, 27 and 29 will not match the prices on page 97.
Table of Contents
H. Roger Schwall
United States Securities and Exchange Commission
Page
January 11, 2013
In future filings, we will more clearly indicate the prices used for our standardized measure are future prices with disclosure such as: “For 2011, the future average realized prices averaged $67.31 per barrel of oil, $3.51 per Mcf of gas and $39.28 per barrel of natural gas liquids.”
SEC Comment
8. We note you include as a single line item entry “development costs incurred that reduced future development costs” in your disclosure of the principal changes in the Company’s standardized measure of discounted future net cash flows on page 98. Please tell us how you have considered the requirements in FASB ASC 932-235-50-35 as illustrated in Example 6: Changes in the Standardized Measure for Discounted Cash Flows found in FASB ASC 932-235-55-7; wherein, the changes in estimated future development costs are presented separately from the previously estimated development costs incurred during the period.
Response
For 2011, 2010 and 2009, the changes in our estimates of future development costs were decreases of approximately $400 million, $300 million and $200 million, respectively. In our disclosure of the principal changes in our standardized measure on page 98, we included these amounts within our caption “revisions of quantity estimates.” In future filings, we will revise our presentation of the principal changes in our standardized measure to those illustrated in FASB ASC 932-235-50-35, including the separate presentation of the changes in estimated future development costs.
Exhibit 99.2
SEC Comment
9. We note the reserve report on page 1 states “the scope of the audit consisted of the independent preparation of our own estimates of the proved and proved plus probable reserves”; furthermore, you state “the proved and proved plus probable reserve estimates prepared by both Devon Canada and AJM conform to the reserve definitions as set forth in the SEC’s Regulation S-X Part 210.4-10(a) and as clarified in subsequent Commission Staff Accounting Bulletins.”
We note information relating to probable reserves is not disclosed in Form 10-K. Either file a revised report which does not reference information relating to probable reserves or amend the Form 10-K to include that information.
Response
In future filings, the reference to probable reserves will be removed. Following this letter, we have attached an example of the proposed reserve report that reflects this change.
SEC Comment
10. We note under the section entitled “Production Forecasts” on page 11 of your report, you state that “if the reserves were located in a remote location and/or the reserve volume was of higher risk, the reserves were forecast to come on-stream beyond five years from the effective date” when the company could not provide specific on-stream date information. Please tell us if you have adopted on-stream dates for any of the proved undeveloped reserves contained in your report that are beyond five years of the effe
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CORRESP
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filename1.htm
Correspondence Letter
Table of Contents
Devon Energy Corporation
333 West Sheridan Avenue
Oklahoma City, OK 73102
405 552 4577 phone
jeff.agosta@dvn.com
January 11, 2013
Via EDGAR
Attention: Ms. Svitlana Sweat, Division of Corporation Finance
H. Roger Schwall
Assistant
Director
United States Securities and Exchange Commission
100 F. Street, N.E.
Washington, D.C. 20549
Re:
Devon Energy Corporation
Form 10-K for the Fiscal Year Ended December 31, 2011
Filed
February 24, 2011
File No. 001-32318
Dear Mr. Schwall:
This letter responds to the staff’s comment letter dated
December 13, 2012, regarding Devon Energy Corporation’s Form 10-K for the year ended December 31, 2011, filed February 24, 2012 (File No. 001-32318). Devon’s responses to the staff’s comments are set forth below:
Form 10-K for Fiscal Year Ended December 31, 2011
Oil and Gas Properties, page 4
Production, Production Prices and Production
Costs, page 10
SEC Comment
1.
We note you disclose the production and average sales price by final product sold on page 10 and elsewhere in your filing on Form 10-K. In regards to disclosure by
final product sold, we note on page 7 you state that Jackfish is a “non-conventional oil sands” project. Furthermore, in the section entitled “Projects Overview” under “Operations-Jackfish Projects” on your company
website (http://www.devonenergy.com/Operations/Canada/Pages/jackfish_project), you state steam assisted gravity drainage is “being used to extract the bitumen over the life of the projects”; however, it does not appear that you make
reference to or distinguish between bitumen and oil as final sales products in your filing on Form 10-K as required by Item 1204(a) of Regulation S-K. Revise your presentation to break out bitumen separately or tell us why you do not believe
that is appropriate. See also Instruction 3 to Item 1204 of Regulation S-K.
Response
Jackfish is currently our only project with bitumen production, which totaled 13 million, 9 million and 8 million barrels in 2011, 2010 and
2009, respectively. This production represented 5%, 4% and 3% of our total production for 2011, 2010 and 2009, respectively. We will revise our presentation to break out bitumen production and average sales prices separately as required by
Item 1204(a) in future filings.
Table of Contents
H. Roger Schwall
United States Securities and Exchange Commission
Page
2
January 11, 2013
Notes to Consolidated Financial Statements
Note 6 – Income Taxes, page
66
SEC Comment
2.
We note that you recognized deferred income tax expense of $725 million during the fiscal year ended December 31, 2011 related to the assumed repatriations of
earnings from your foreign subsidiaries. We also note the disclosure per page 39 of your filing which states that the majority of your cash and short-term investments consist of the proceeds from your international offshore divestitures which are
held by certain of your foreign subsidiaries. This disclosure also states that you do not currently expect to repatriate such amounts to the United States. Please tell us the factors considered by management in its conclusion that these amounts will
not be repatriated. Your response should also outline your plans for the permanent reinvestment of the undistributed earnings of your foreign subsidiaries. Refer to FASB ASC 740-30-25-17. In connection with your response, please quantify the amount
of cash and short-term investments held by your foreign subsidiaries.
Response
Of the $7.1 billion of cash and short-term investments we held at December 31, 2011, $6.9 billion was held by our foreign subsidiaries, of which $4.3
billion was deemed repatriated. We had recognized $936 million of deferred income tax expense for deemed repatriations through the year ended December 31, 2011 (see deferred tax liability for taxes on unremitted foreign earnings on page 67 of
our December 31, 2011 Form 10-K). We recognized virtually all this deferred income tax expense in 2009, 2010 and 2011, including the $725 million recognized in 2011.
While we have recognized deferred income taxes for deemed repatriations on a portion of our unremitted foreign earnings, we have determined that certain of our unremitted foreign earnings are being
permanently reinvested. To form our permanent reinvestment conclusions, we consider the financial requirements of our U.S. companies and our foreign subsidiaries, the tax consequences of any remittances, and the operational and fiscal objectives of
our U.S. companies. More specifically, we consider our cash and investments on hand, forecasted after-tax cash flows, and availability of other cash resources, including commercial paper borrowings and debt offerings in the U.S. in a favorably low
interest-rate environment.
Our plans to permanently reinvest a portion of the unremitted earnings of our foreign subsidiaries are based on
our investment programs and related cash flow forecasts of our respective U.S. and foreign operations. Specifically, our U.S. operations are self-funding through earnings and cash flow from the underlying assets or debt issuance due to a very strong
balance sheet and favorable borrowing conditions. However, the capital investment needs of our Canadian operations are expected to exceed the cash inflows largely because of on-going investments in our multi-billion dollar, long-lead time and
capital-intensive oil sands development projects. Accordingly, the unremitted foreign earnings that have funded or will fund our ongoing Canadian operations are deemed permanently reinvested.
Supplemental Information on Oil and Gas Operations (Unaudited), page 88
Proved Reserves, page 91
SEC
Comment
Table of Contents
H. Roger Schwall
United States Securities and Exchange Commission
Page
3
January 11, 2013
3.
We note you disclose the net quantities and changes in your proved oil reserves on page 91. It does not appear that you make reference to or distinguish between
bitumen and oil as product types in disclosing your net reserve quantities here or elsewhere in your filing on Form 10-K. The table should reflect products in the form in which they are sold. Thus, if you sell bitumen it should be broken out
separately from oil, even if it will be upgraded to synthetic oil or gas by the purchaser. If you upgrade the bitumen to synthetic oil or gas prior to sale, then present those quantities separately as synthetic oil or synthetic gas. See
Item 1202(a)(4) of Regulation S-K and FASB ASC 932-235-50-4.
Response
Jackfish is currently our only project with bitumen proved reserves, which totaled 457 million, 440 million and 403 million barrels at
December 31, 2011, 2010 and 2009, respectively. These proved reserves represented 15% of our total proved reserves as of each year ended December 31, 2011, 2010 and 2009. We will revise our presentation to break out bitumen proved reserves
separately as required by Item 1204(a)(4) and FASB ASC 932-235-50-4 in future filings.
Proved Undeveloped reserves, page 95
SEC Comment
4.
We note your disclosure of the total quantity of proved undeveloped reserves at the 2011 year end and the material changes in proved undeveloped reserves that
occurred during the year, including the net quantities of proved undeveloped reserves converted into proved developed reserves as required by Items 1203(a) and 1203(b) of Regulation S-K. Please expand your disclosure to also address the investments,
including the capital expenditures, made during the year to convert your proved undeveloped reserves to proved developed. See Item 1203(c) of Regulation S-K.
Response
During 2011, we invested approximately $1.3 billion to convert our proved
undeveloped (“PUD”) reserves to proved developed. In future filings, we will include in the discussion of PUD reserves expanded disclosure that includes the amount of capital expenditures incurred to convert our PUD reserves to proved
developed such as the following: “Costs incurred for the year ended December 31, 2011, related to the development of proved undeveloped reserves were $1.3 billion.”
SEC Comment
5.
We note you disclose that revisions during 2011 other than price decreased your proved undeveloped reserves primarily due to the evaluation of certain U.S. onshore
dry-gas areas, which the Company “does not expect to develop in the next five years.” For purposes of determining the five year period, Item 1203(d) of Regulation S-K identifies the initial disclosure and date thereof as the starting
reference date. Please tell us if any of your proved undeveloped volumes disclosed as of December 31, 2011, other than those attributed to Jackfish or included in the revision as noted, will take more than five years since initial disclosure to
develop.
Response
Excluding our Jackfish PUD reserves, we had 0.75 million Boe of PUD reserves, which represented 0.02% of our total proved reserves, that are expected to take more than five years to develop since
initial disclosure. These PUD reserves relate to one immaterial Canadian property in which the gas cap is scheduled for development upon the depletion of the oil leg of the reservoir in accordance with the regulations of the Energy Resources
Conservation Board of Alberta. These reserves are consistent with the definition of undeveloped oil and gas reserves in Rule 4-10(a)(31)(ii) of Regulation S-X.
Table of Contents
H. Roger Schwall
United States Securities and Exchange Commission
Page
4
January 11, 2013
SEC’s Modernization of Oil and Gas Reporting, page 96
SEC Comment
6.
We note you disclose that the Company’s 2009 reserves increased approximately 2% as a result of adopting the provisions in the new rules permitting the use of
reliable technologies to establish the reasonable certainty of proved reserves. Furthermore, you state “this increase is included in the 2009 extensions and discoveries total.” We note your 2011 extensions and discoveries amount to 14.7%
of the opening balance of total proved reserves on a boe basis and were attributed to your activities in the Cana-Woodford Shale, Barnett Shale, Permian Basin, Jackfish, Rocky Mountain and Granite Wash areas. Additionally, we note your 2010
extensions and discoveries amount to 13% of the opening balance of total proved reserves on a boe basis and were attributed to your activities in the Cana-Woodford Shale, Barnett Shale, Jackfish, Permian Basin, Rocky Mountain and Carthage areas.
Please tell us if any of the volumes relating to extensions and discoveries for years ending 2011 and 2010 are attributable to reliable technologies and if so whether you consider the related volumes material in light of Item 1202(a)(6) of
Regulation S-K.
Response
In both 2011 and 2010, our extensions and discoveries included volumes that are based upon reliable technologies. However, the volumes represent less than 2% of our reserves at the beginning of each year.
Therefore, absent acknowledgement of the impact of a rule change, which was the case for our 2009 disclosure, we considered the 2011 and 2010 amounts to be immaterial.
Standardized Measure, page 97
SEC Comment
7.
We note you state “future cash inflows, development costs and production costs were computed using the same assumptions for prices and costs that were used to
estimate Devon’s proved oil and gas reserves at the end of each year.” You also state “for 2011, the prices averaged $67.31 per barrel of oil, $3.51 per Mcf of gas and $39.28 per barrel of natural gas liquids”; however, these
average prices do not appear to correspond to your disclosures on prices found on pages 10, 27 or 29 of your filing on Form 10-K. Please explain why these prices differ from the prices provided elsewhere in your disclosure on Form 10-K.
Response
As required by FASB ASC 932-235 and disclosed on page 96, the future cash inflows and resulting average realized prices on page 97 are calculated using
prices that represent the unweighted arithmetic average of the first-day-of-the-month price for the preceding 12-month period (i.e., January 1, 2011 to December 1, 2011). While a portion of our production is sold based on
first-day-of-the-month prices, a portion is sold based on daily prices, particularly our oil and NGL production. Additionally, the composition of each of our commodity products sold changes over time because of variations in production development
schedules and decline rates. Consequently, our overall average realized prices for each commodity will change over the producing life of our proved reserves and, thus, will not necessarily be the same as those for 2011. Therefore, because we do not
sell all our production based on first-day-of-the-month prices and the composition of our product sales changes over time, the prices on pages 10, 27 and 29 will not match the prices on page 97.
Table of Contents
H. Roger Schwall
United States Securities and Exchange Commission
Page
5
January 11, 2013
In future filings, we will more clearly indicate the prices used for our standardized measure are future prices with disclosure such as: “For 2011, the future average realized prices
averaged $67.31 per barrel of oil, $3.51 per Mcf of gas and $39.28 per barrel of natural gas liquids.”
SEC Comment
8.
We note you include as a single line item entry “development costs incurred that reduced future development costs” in your disclosure of the principal
changes in the Company’s standardized measure of discounted future net cash flows on page 98. Please tell us how you have considered the requirements in FASB ASC 932-235-50-35 as illustrated in Example 6: Changes in the Standardized Measure for
Discounted Cash Flows found in FASB ASC 932-235-55-7; wherein, the changes in estimated future development costs are presented separately from the previously estimated development costs incurred during the period.
Response
For 2011, 2010 and 2009, the
changes in our estimates of future development costs were decreases of approximately $400 million, $300 million and $200 million, respectively. In our disclosure of the principal changes in our standardized measure on page 98, we included these
amounts within our caption “revisions of quantity estimates.” In future filings, we will revise our presentation of the principal changes in our standardized measure to those illustrated in FASB ASC 932-235-50-35, including the separate
presentation of the changes in estimated future development costs.
Exhibit 99.2
SEC Comment
9.
We note the reserve report on page 1 states “the scope of the audit consisted of the independent preparation of our own estimates of the proved and proved plus
probable reserves”; furthermore, you state “the proved and proved plus probable reserve estimates prepared by both Devon Canada and AJM conform to the reserve definitions as set forth in the SEC’s Regulation S-X Part 210.4-10(a) and
as clarified in subsequent Commission Staff Accounting Bulletins.”
We note information relating to
probable reserves is not disclosed in Form 10-K. Either file a revised report which does not reference information relating to probable reserves or amend the Form 10-K to include that information.
Response
In future filings, the
reference to probable reserves will be removed. Following this letter, we have attached an example of the proposed reserve report that reflects this change.
SEC Comment
10.
We note under the section entitled “Production Forecasts” on page 11 of your report, you state that “if the reserves were located in
a remote location and/or the reserve volume was of higher risk, the reserves were forecast to come on-stream beyond five years from the effective date” when the company could not provide specific on-stream date information. Please tell us if
you have adopted on-stream dates for any of the proved undeveloped reserves contained in your report that are beyond five years of the effe