July 29, 2010
United States Securities and Exchange Commission
Division of Corporation Finance
100 F St. N.E.
Washington, D.C.
20549
Attention: H. Roger Schwall, Assistant Director
Dear Mr. Schwall:
| Re: | Response Submitted in the Matter of Nexen Inc.'s Form 10-K for Fiscal Year Ended December 31, 2009 filed February 25, 2010 |
File No. 1-6702
The discussion herein responds to the comments in the letter dated July 2, 2010 (the "Comment Letter") to Nexen Inc. (the "Company", "we" or "our") from the staff (the "Staff") of the Division of Corporation Finance of the U.S. Securities and Exchange Commission (the "SEC"). Please note that we have reproduced the Staff’s comments and have followed with our response.
Form 10-K for the Fiscal Year Ended December 31, 2009
General
| 1. | In light of recent events involving the Gulf of Mexico, please review your disclosure to ensure that you have disclosed all material information regarding your potential liability in the event that one of your rigs is involved in an explosion or similar event in any of your offshore locations. For example, and without limitation, please address the following: |
| · | Disclose the applicable policy limits related to your insurance coverage; |
| · | Disclose whether your existing insurance would cover any claims made against you by or on behalf of individuals who are not your employees in the event of personal injury or death, and whether your customers would be obligated to indemnify you against any such claims; |
| · | Clarify your insurance coverage with respect to any liability related to any resulting negative environment effects; and |
| · | Clarify the “specified monetary limits” referenced at page 17 with respect to your obligations to indemnify customers or business partners in connection with legal and financial consequences of spills of industrial waste and other liquids. |
In this regard, discuss what remediation plans or procedures you have in place to deal with the environmental impact that would occur in the event of an oil spill or leak from your offshore operations.
Response to comment 1
| On page 57 of our quarterly report in Form 10-Q, filed on July 21, 2010, we included a new risk factor entitled “Deep Water Operations” that addresses certain of the liability issues you raise. We don’t believe the matters raised in the second and fourth bullets above relate to our business and therefore no disclosure by us would be appropriate. |
| As for remediation plans or procedures, we have a number of documented practices implemented internally and under contract with various specialist service providers. The Deepwater Horizon incident has caused us to commence a thorough review of our worldwide drilling and operating procedures to minimize risks that a similar incident could happen, as well as our response and remediation plans and procedures in the unlikely event that it did. As part of this review, we are monitoring and will continue to monitor the organizational and technological evolutions in spill containment and remediation that have occurred to date and are assessing the adoption of evolving best practices. Since developments with respect to this incident are dynamic and evolving, detailed disclosures in this regard would not be helpful at this point. Accordingly, we believe that it is appropriate that this matter be addressed in future filin gs. |
Business and Properties, page 1
Understanding the Oil and Gas Business, page 6
Synthetic (Insitu Long Lake), page 7
| 2. | We note your statement that OPTI has the exclusive Canadian license for the OrCrude™ technology, and that you acquired the right to use this technology with OPTI within approximately 100 miles of Long Lake, as well as the right to use the technology elsewhere in Canada and the rest of the world (excluding Israel) subject to certain rights of OPTI to participate. Considering that Long Lake constitutes 31.45% of your total proved reserves and you disclose the OrCrude™ technology as a key competitive advantage in developing this resource, please tell us what consideration you gave to filing your joint venture agreement with OPTI or the other agreements by which you have obtained the rights to the Orcrude™ technology. See Item 601(b)(10)(ii)(B) of Regulation S-K. |
Response to comment 2
We have several agreements with OPTI, including agreements with respect to our rights to the OrCrudeTM technology. At the time of entering into the agreements in 2004 and again at the time the Form 8-K rules were amended in
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2008, we considered whether the agreements should be filed as material contracts or included as exhibits to our annual or periodic reports under applicable SEC requirements. We concluded that filing was not required because the proved reserves attributable to Long Lake can be developed economically with or without this technology. The key competitive advantage that the technology provides is that it reduces our economic exposure to high energy input costs and low bitumen/heavy oil prices. For these reasons, while access to this technology is important, neither our business nor our ability to produce our reserves at Long Lake depends on it to a material extent.
| SAGD and Upgrader Integration, page 8 |
| Phase 1, page 9 |
| 3. | We note your disclosure that describes the process of heating the reservoir for several months followed by a ramp up of production for 12-24 months to peak levels. It appears this process may represent both development activities followed by production activities. Please tell us and disclose if material, how you account for the costs associated with these activities under U.S. and Canadian GAAP at each stage of the project. |
Response to comment 3
Bitumen will not flow in its natural state and must be heated within the reservoir in order to be produced in insitu oil and gas operations. Heat is required to maintain production as well as develop new areas of the lease with future well pad development.
Costs incurred in the process of initially heating the reservoir and during the ramp up phase were capitalized until the integrated facility was ready for productive use. Once the facility was in productive use, costs to heat the existing well pads and costs to heat future well pad developments are accounted for as a production activity and treated as an expense. The accounting is the same under Canadian and US GAAP. The costs are not material and, as such, do not require separate disclosure.
| Public Perception of Oil Sands Development, page 46 |
| 4. | Tell us whether there is any pending environmental legislation which would impact your oil sands exploration or development operations. |
| Response to comment 4 |
| All pending environmental legislation which would impact our oil sands operations was addressed on pages 37 to 39 of our annual report on Form 10-K. |
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Management’s Discussion and Analysis of Financial Condition and Results of Operations, page 51
Strategy Progress, page 52
| 5. | We note your disclosure on page 53 that “During 2009, our proved oil and gas reserves additions replaced 205% of our oil and gas production (198% after royalties) before the year-end transition to new SEC reserves rules. Excluding economic revisions, we replaced 187% of our oil and gas production (202% after royalties). The difference in economic revisions between before and after royalties reflects an increase in oil sands royalties related to higher oil prices.” Please expand your disclosure surrounding this reserves replacement ratio to address the following: |
| · | Identify the status of the proved reserves that have been added (e.g., proved developed vs. proved undeveloped). |
| · | Explain to investors the nature of the reserve additions, and whether or not the historical sources of reserve additions are expected to continue, and the extent to which external factors outside of managements’ control impact the amount of reserve additions from that source from period to period. |
| · | Explain the nature of and the extent to which uncertainties still exist with respect to newly discovered reserves, including, but not limited to regulatory approval, changes in oil and gas prices, and the availability of additional development capital and the installation of additional infrastructure. |
| · | Indicate the time horizon of when the reserve additions are expected to be produced to provide investors a better understanding of when these reserve additions could ultimately be converted to cash inflows. |
| · | Disclose how management uses this measure. |
| · | Disclose the limitations of this measure. |
Response to comment 5
We describe our reserves and the related processes in a separate section of Properties in our Form 10-K (pages 24 through 31) rather than in the MD&A. While not included on the referenced page 52, we believe all information material to our reserves is disclosed in our Form 10-K as follows:
| ● | The nature and status of the proved reserves is provided on pages 24 and 25 where we show the annual additions for total reserves and for proved undeveloped reserves. This also addresses the nature of and time horizon of the development of the proved undeveloped reserves. |
| ● | The status of any specific material uncertainties and significant future actions are also described on page 26. For instance, we describe the need to develop the mine at Syncrude and to continue to drill wells at Long Lake as production from existing wells decline. |
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| ● | The amount of future capital required to develop the undeveloped reserves is provided in the standardized measure disclosure in the supplementary information to the financial statements on pages 156 and 157. |
| ● | The general uncertainties including price changes, regulatory changes, and future investment decisions are described on page 29. |
| ● | Pages 43 and 44 describe risk factors pertaining to our need to replace reserves and the need for additional capital to be incurred to develop the proved undeveloped reserves. These underscore the importance of a reserve replacement ratio. |
In response to your comments, however, we will in future filings, address the following:
| ● | We will cross-reference the MD&A to the reserves analysis and the risk factors, and provide more cross-referencing within the reserves section to the other pertinent sections. |
| ● | We will include a statement that our current year’s additions are not necessarily indicative of future annual additions which will be dependant on such factors as oil and gas prices, capital allocations, nature of our drilling programs, success and expected timing of proceeding with development of reserves discovered. |
| ● | We will state that management only uses the reserves replacement ratio as a proxy for our success in replacing reserves produced and that we tend to look at various time periods of one year and longer when considering this ratio. |
“2009 VS 2008 – Lower Oil and Gas DD&A Increased Net Income by $241 Million,” page 67
| 6. | We note your disclosure that indicates you expensed $49 million of acquisition costs associated with your Perth project. Please expand your disclosure to explain why you have decided not to proceed with the development of this project. |
Response to comment 6
We acquired the Perth project when we purchased our UK oil and gas business in 2004. It was one of many prospects acquired in the transaction. In 2009, as part of our normal course review of our undeveloped discoveries, we determined that technical challenges associated with the existence of high levels of H2S negatively impacted the economics of the Perth project such that development of the asset prior to lease expiration was unlikely.
As the Perth prospect costs represented 0.3% of the net book value of our property, plant and equipment and less than 5% of our net income, we believe that the project and related expensed acquisition costs are not material to investors or to our financial statements. On this basis, we concluded that additional disclosure was not required.
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Note 21. Differences between Canadian and US Generally Accepted Accounting Principles, page 144
| 7. | We are unable to locate a cash flow statement prepared under U.S. GAAP. Please tell us how you considered the cash flow reconciliation requirement of Item 17(c)(2)(iii) of Form 20-F. |
Response to comment 7
We consider the cash flow reconciliation requirement of Item 17(c)(2)(iii) of Form 20-F to be met by our Canadian GAAP cash flow statement as we have not identified any US/Canadian GAAP differences related to the cash flow statement. In future filings, we will clarify whether or not we have identified any US/Canadian GAAP differences related to the cash flow statement.
| Oil and Gas Producing Activities (Unaudited), page 151 |
E. Standardized Measure of Discounted Future Net Cash Flows and Changes Therein, page 156
| 8. | Please note there is no provision for a separate line item titled “Future Dismantlement and Site Restoration Costs, Net” within FASB ASC Topic 932-235-50-29 through 50-33 or Example 5. As such, please modify your presentation accordingly. |
| Response to comment 8 |
We believe these costs are to be included in future development costs. We have chosen to include this as a separate line item to enhance our disclosure. Although the referenced section of the FASB ASC Topic does not require this line item, the regulation does not expressly prohibit its use. Canadian analysts and investors expect this line item because Canadian reserves regulators require it and we have received positive feedback from the analyst community on the separate disclosure of this line item. Accordingly, we believe this is useful additional information and readers can readily add the numbers if they require the combined total.
| Part IV. Exhibits, Financial Statement Schedules, page 204 |
| Exhibits 23.2-23.9 |
| 9. | The closing paragraphs of the McDaniel’s reports state in part that each report was prepared for exclusive use of Nexen Inc., and that it may not be reproduced, distributed, or made available, in whole or in part to any person other than Nexen Inc. without McDaniel’s knowledge and consent. Similarly, the DeGolyer and MacNaughten and Ryder Scott reports state their reports were prepared at the request of Nexen and should not be used for purposes other than those for which it is intended. As Item 1202(a)(8) of Regulation S-K requires these reports, please obtain and file revised versions which retain no language that could suggest either a limited audience or a limit on potential investor reliance. |
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| Response to comment 9 |
In response to the Staff’s comment, we will file revised versions of the referenced reports with the limitations on use removed.
| Engineering Comments |
| Business and Properties, page 1 |
| Proved Developed and Undeveloped Reserves, page 25 |
| 10. | We note the tabular reconciliation of your proved undeveloped reserves before royalty. Please expand this to disclose similar information on an after-royalties basis. |
| Response to comment 10 |
We will include this information in our future filings. We respectfully submit that our 2009 disclosures not be amended as the after-royalties reconciliation does not provide materially different information than the before-royalties reconciliation.
| 11. | We note your statement, “Excluding Long Lake, we expect to convert over 90% of our PUDs to producing in the next four years. Long Lake PUDs will be converted over the next 27 years as new wells are drilled to offset declines from the initial SAGD wells.” Please tell us: |
| · | The portion of your PUD reserves that will be converted in the next five years. Support any Long Lake PUD reserves booked beyond Phase 1. Tell us your schedule for future PUD conversion. |
| · | The reasons that you cannot develop the Long Lake PUD reserves within five years of booking. Address the fact that you control the pace of development. |
| · | The attributes that make the 27+ years of Long Lake activities a single development project. Refer to our “Compliance and Disclosure Interpretations”, particularly Questions 108.01 and 131.03. These are located at: |
http://www.sec.gov/divisions/corpfin/guidance/oilandgas-interp.htm
Response to comment 11
Excluding Long Lake, all of our PUDs will be converted within the next 5 years.
We have not booked any proved reserves beyond Phase 1.
Long Lake Phase 1 is a single development project in accordance with SEC Compliance and Disclosure Interpretations for the following reasons:
| ● | it is an integrated SAGD production and upgrading facility where: 1) part of the oil produced is used to generate a synthetic gas which is used as an energy source for the heating of water to make steam for injection into the reservoir, as a source of hydrogen for use in upgrading the oil produced and in generating power for the operations; and 2) water from the condensed steam recovered from the wells and also used in the upgrader process is mixed for purification and recycling; |
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| ● | the facility has a 40+ year useful life with ongoing maintenance and requires a large amount of reserves to operate it at capacity throughout its useful life; |
| ● | the investment decision was made on the basis of an economic assessment of the combined activities so as to reduce our exposure to high energy input costs and low bitumen sales prices; |
| ● | the initial economic analysis and investment decision included the ongoing maintenance costs and investment in future drilling and related infrastructure; |
| ● | future drilling costs are small relative to the overall cost of the project and are relatively low compared to the value of the margins generated making them highly certain of being drilled. |
Wells are only drilled as necessary to keep the facility at capacity over its useful life to maximize the economics of the capital investment. Drilling requirements are based on well productivity and reservoir recovery and drilling is expected to take place over the next 27 years.
| 12. | Your 2009 PUD reserve conversion rate (about 4% of year-end 2008 PUD reserves) implies a much longer period for full PUD development than 5 years. Please explain the circumstances causing this outcome and disclose your PUD conversion information for each of the last three years. You may refer to “Guidance for Management’s Discussion and Analysis for Companies Engaged in Oil and Gas Producing Activities”, pages 85-88 of our adopting release 33-8995, “Modernization of Oil and Gas Reporting” available at www.sec.gov/rules/final/2008/33-8995.pdf. |
| Response to comment 12 |
Our PUDs at the end of 2008 were comprised of 232 million barrels relating to Long Lake and 191 million relating to our other activities. We refer you to our response to Comment 11 for details on the Long Lake PUD conversions. Our 2009 conversion for the remaining PUDs is low reflecting the following two projects where work is underway but the conversions won’t be recognized until they are completed:
| ● | As described on pages 25 – 26 of our Form 10-K, 105 million barrels relates to the new Syncrude mine development that will commence in 2012. These reserves were considered as part of the economic decision to proceed with the upgrader expansion completed in 2006. The work is expected to be completed and the PUDs converted in 2013. |
| ● | Development of our Usan field offshore West Africa is underway. At the end of 2008, we recognized 28 million barrels of PUDs and did not convert any during 2009. These will be transferred to developed upon completion of the four year facility construction period which is expected to be in 2012. |
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We note that a three year reconciliation of PUD conversions is not required by the applicable regulations. In addition, we don’t believe a three year history of our conversion is useful as a predictor of future performance given the changing nature of our PUD base as it pertains to large discrete projects. Instead, we believe it is more relevant to describe the progress we are making on our PUD conversions. We will, in future filings, enhance our disclosures to more specifically address our progress on the conversion of our material PUDs.
| Risk Factors, page 40 |
| 13. | Please expand your risk factors to explain the consequences should your provisions for containment of a drilling well blowout(s) prove inadequate. |
Response to comment 13
In our Quarterly Report on form 10-Q filed on July 21, 2010, we included a new risk factor entitled “Deep Water Operations” on page 57 that addresses the Staff’s comment.
| Application of New Bitumen Upgrading Process, page 45 |
| 14. | We note the disclosure of proved synthetic crude oil reserves on page 24 and elsewhere attributable to your Long Lake activities including OrCrude™ upgrading. Please reconcile your statement “There is no certainty that the commercial upgrader at Long Lake will sustain or achieve the results which are now being seen or forecast” with the requirement that proved reserves (including synthetic crude oil) “ … be estimated with reasonable certainty to be economically producible …” Address the fact that scaled up, economic upgrading of bitumen to synthetic crude oil has not been demonstrated by the OrCrude™ method. |
| Response to comment 14 |
The Long Lake integrated facility, including the OrCrude™ process and commercial upgrader, is working as designed to produce the products intended. This includes upgrading bitumen produced to a premium synthetic crude which is being sold into the market.
The facility is operating at less than full capacity as it goes through the ramp up process. Each of the major units have been run at full capacity but not all units have yet been run concurrently at full capacity. The risk factor you referenced reflects the fact that we are in the ramp up process and there is still some uncertainty as we have not yet proven conclusively that it will operate at full capacity.
The proved reserves recognized can be produced economically during the facility’s useful life at the rates currently being achieved and thus meet the level of certainty required for proved recognition. If for some future reason the facility doesn’t support upgrading the bitumen reserves, they can still be economically produced and sold through the SAGD process.
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| Quantitative and Qualitative Disclosures about Market Risk, page 92 |
| Special Note to Canadian Investors, page 97 |
| 15. | Please reconcile your statement “[T]he reserves disclosures in this document have not been reviewed by the independent qualified reserves consultants whereas NI 51-101 requires them to review it” with the third party reports of three independent petroleum engineers you included as exhibits to your document. |
Response to comment 15
We engaged the independent petroleum engineers to review certain of our reserves estimates. They were not requested nor did they review our disclosures related to our reserves. The only review of our Form 10-K they performed was to ensure that our description of their work and conclusions reached were accurately described. We therefore believe the referenced statement is accurate.
| Exhibits 23.2, 23.3, 23.4 |
| 16. | Item 1202(a)(8) of Regulation S-K specifies disclosure items pertaining to third party engineering reports. Please obtain modification of these three reports so that they present: |
| · | The proportion of your total probable reserves that were evaluated; |
| · | The 12 month average benchmark product prices and the average adjusted prices used to determine reserves; |
| · | The aggregate percentage difference between your proved reserve estimates and those of your third party engineer; and |
| · | The aggregate percentage difference between your probable reserve estimates and those of your third party engineer. |
Response to comment 16
We have reviewed exhibits 23.2, 23.3, 23.4 and note that the proportion of total probable reserves that were evaluated was included within each report. For your reference, we direct you to paragraph 1 in the section entitled “Nexen Estimates”, in each exhibit.
We do not believe that disclosure of the benchmark and average adjusted prices used in the estimation process is required by applicable regulations. Furthermore, we do not believe it provides useful information to the users as prices used will differ from company to company based on their particular properties. Instead, we believe it is sufficient for us to make an explicit statement that we followed the price requirements and for the independent engineers to state that they have also followed the rules and guidelines in expressing their opinions on our estimates.
We do not believe it is appropriate to disclose the percentage differences between our estimate of proved and probable reserves and that of the independent engineers. They were engaged to determine whether our estimates when compared to their estimates are reasonable within the established audit
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tolerance guidelines rather than to prepare estimates for disclosure. When material differences are initially identified, we work together to share information and interpretations to get within an acceptable range. At that time further refinements are no longer pursued. This process is described on page 30 of our Form 10-K. In light of these factors, we believe their estimate is irrelevant once they are materially the same and a second set of estimates would be potentially confusing to readers.
Exhibit 23.6
17. Please obtain modification of this report so that it presents:
| · | The 12 month average benchmark product prices and the average adjusted prices used to determine reserves; |
| · | The aggregate percentage difference between your proved reserve estimates and those of your third party engineer; and |
| · | The aggregate percentage difference between your probable reserve estimates and those of your third party engineer. |
Response to comment 17
Please refer to our response to comment 16.
Exhibit 23.7
18. Please obtain modification of this report so that is presents:
| · | The proportion of your total probable reserves that were reviewed. Two different figures are presented – 15 percent and 4 percent; |
| · | A discussion of the methods employed by the engineer to arrive at the conclusion that your reserve estimates are “reasonable within the established audit tolerance guidelines…”; |
| · | The 12 month average benchmark product prices and the average adjusted prices used to determine reserves; |
| · | The aggregate percentage difference between your proved reserve estimates and those of your third party engineer; and |
| · | The aggregate percentage difference between your probable reserve estimates and those of your third party engineer. |
Response to comment 18
We have reviewed Exhibit 23.7 and we can confirm that 4% is the quantity of total probable reserves that were reviewed. We will correct this upon refiling of the amended engineering report as described under Comment 9.
We describe the difference between an evaluation and an audit on page 31 of our Form 10-K and indicate that the independent engineer’s work on the Syncrude estimates are based on an audit rather than an evaluation. McDaniel’s also describes their process in their report included as Exhibit 23.7. We do not believe that a more detailed description of their work would provide more
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meaningful information to the reader as it should be clear from the disclosures that the work performed differs from the other evaluations.
For our responses to the rest of your comments, please refer to our response to comment 16.
Exhibit 23.9
19. Please obtain modification of this report so that it presents:
| ● | The 12 month average benchmark product prices and the average adjusted prices used to determine reserves; |
| ● | The aggregate percentage difference between your proved reserve estimates and those of your third party engineer; and |
| ● | The aggregate percentage difference between your probable reserve estimates and those of your third party engineer. |
Response to comment 19
Please refer to our response to comment 16.
We trust the foregoing satisfies your queries and we are available to provide any additional information you require to complete this review. We acknowledge that:
| ● | the Company is responsible for the adequacy and accuracy of the disclosure 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 |
| ● | the Company may not assert staff comments as a defense in any proceedings initiated by the Commission or any person under the federal securities laws of the United States. |
Yours very truly,
NEXEN INC
/s/ Kevin J. Reinhart
Kevin J. Reinhart
Executive Vice President
and Chief Financial Officer
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