NEXEN INC. 801 - 7 Avenue SW Calgary AB Canada T2P 3P7 Email kevin_reinhart@nexeninc.com |
September 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 September 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
| 1. | We note your response to prior comment 1 from our letter dated July 2, 2010 and your new risk factor entitled “Deep Water Operations” in your Form 10-Q filed on July 21, 2010. Please clarify how the “pollution cleanup” that appears covered up to US $1.5 billion, net of your working interest in the well, differs from the “costs relating to damage to natural resources” that appears only covered up to US $50 million. Please also explain the certain sub-limits for each of the areas covered by the US $1.5 billion insurance plan. |
Response to comment 1
Our insurance for "Pollution Cleanup" covers (i) reasonable and necessary expenses incurred, (ii) liability to any governmental entity for clean-up and removal costs and expenses, and (iii) liability for costs and expenses of governmental action, in each case to the extent reasonable and necessary to
2
minimize or remediate, or prevent further, injuries to persons or loss or damage to the property of others arising out of seepage, pollution or contamination.
Our insurance for "Liability for Damage to Natural Resources" covers sums for which Nexen may be liable as a result of loss of or damage to, including loss of use of, “natural resources” arising out of seepage, pollution or contamination. Natural Resources include land, fish, wildlife, biota, air, water, ground water, drinking water supplies and other such resources. It is not necessary that Natural Resources are “property” in the sense that any individual or group has title to them.
Generally, our sub-limits within the $1.5 billion of coverage are as follows:
| ● | Property Damage: $1.1 billion combined limit for physical damage, operator’s extra expense (including control of well and redrill costs), and consequential business interruption |
| ● | Offshore Pollution Liability: $800 million |
| ● | General (non-pollution) Third Party Liability: $450 million |
| 2. | Please provide information about your indemnification obligations, and those of your operating or non-operating partners and third parties performing services on any of your offshore operations. Please also explain why bullet 2 is inapplicable. It appears that if you are the operator on a well, such as for the Buzzard field and platform or at Knotty Head, you could be a liable party in case of events such as the Deepwater Horizon incident. |
Response to comment 2
On our operated properties in the Gulf of Mexico, our agreements with oilfield service contractors typically provide for operator/contractor indemnity obligations that are consistent with industry standards. For property and personnel claims, each party assumes liability for any damages or loss to its own property and personnel, except in circumstances where the damage or loss suffered by one party is due to the gross negligence or willful misconduct of the other party in which case the party at fault is liable. For environmental claims, the operator assumes liability for any damages or costs that arise, except where the damage or cost arises due to the gross negligence or willful misconduct of the services contract or in which case the party at fault is liable. The only exception to this is in respect of our drilling contracts with Ensco where we assume liability for all environmental damages, costs and losses regardless of fault of the services contractor.
Under our joint operating agreements, all partners share in any damages or costs of any kind that arise from joint operations in an amount equal to their participating interest, except where the damages or costs arise due to the gross negligence or willful misconduct of the operator in which case the operator becomes 100% liable.
3
The combination of bullets 2 and 4 led us to believe that your comments were not applicable to our operations since our crude oil and natural gas sales contracts do not result in any liability on the part of the customer. As stated in our Form 10-Q filed July 21, 2010, Nexen maintains both onshore and offshore general third-party liability insurance which generally provides coverage for claims made against us by third parties whom have suffered bodily injury and/or property damage and for which we are liable to compensate arising by contract or tort law.
We will amend our future filings to clarify that our existing insurance policies provide coverage for any claims made against us or contractors acting on our behalf in the event of personal injury or death.
| 3. | In regard to remediation plans or procedures, in your response to prior comment 1 from our letter dated July 2, 2010 you state that disclosure would not be helpful at this time because you are still assessing the adoption of evolving best practices. Please describe your current remediation plans and procedures, and discuss what you are considering changing to adopt best practices. Please also confirm that you will disclose your adopted best practices as soon as such internal review is complete. |
Response to comment 3
We have in place regional spill response plans, which detail procedures for rapid and effective response to spill events that may occur as a result of our offshore operations including access to third party responders. Our plans are structured around industry best practice and meet or exceed regulatory requirements in all the jurisdictions in which we operate. In the United States, the Bureau of Ocean Energy Management, Regulatory and Enforcement (formally the Minerals Management Service) approves our response plan for each well drilled. Nexen has also contracted with O’Brien’s Response Management, a division of SEACOR Holdings Inc., for additional and specialized personnel to ensure Nexen’s global response to a marine oil spill is resourced appropriately. Nexen’s emergency response plans a re reviewed annually and updated as required.
In support of our offshore Gulf of Mexico operations, Nexen is a member of Clean Gulf Associates (CGA), a not-for-profit association of over 140 producing and pipeline companies operating in the Gulf of Mexico. CGA was created to provide a means of effectively staging response equipment and providing immediate spill response for its member companies. The Marine Spill Response Corporation (MSRC), a national, private, not-for-profit marine spill response organization, maintains CGA’s marine spill response equipment (including skimmers, fast response vessels, fast response containment-skimming units, a large skimming containment barge, numerous containment systems, wildlife cleaning and rehabilitation facilities and dispersant inventory) throughout the Gulf of Mexico in a ready state. MSRC also has contracts in place with many
4
environmental contractors around the country, and numerous other companies which provide support services during spill response. In addition, CGA maintains a contract with Airborne Support Inc. (ASI), to provide aircrafts and dispersant capabilities.
In the event that CGA and MSRC resources are already being utilized, or we require additional resources, Nexen has access to additional resources through Oil Spill Response Limited, the world’s largest oil spill preparedness and response organization, dedicated to resourcing responses to oil spills globally. Nexen also has access to resources from National Response Corporation and Wild Well Control Inc.
In light of the Macondo incident in the Gulf of Mexico, Nexen is reviewing its emergency response plans. We have engaged independent consultants to assist in that process.
We confirm that following completion of our internal review we will disclose in our offshore emergency response plans and procedures.
Risk Factors, page 40
Public Perception of Oil Sands Development, page 46
| 4. | We note your disclosure in response to prior comment 4 from our letter dated July 2, 2010 that you have disclosed all pending environmental legislation which would impact your oil sands operations. Either here or in an appropriate location, provide more details about the matters and “perceptions” that you allude to in this risk factor. |
| Response to comment 4 |
As described on page 46, our risk factor related to the public perception of oil sands development refers to greenhouse gas emissions, and water and land use practices. The specific matters falling within those categories change frequently and are the subject of innumerable media reports on oil sands development that have this year included: the impact of tailings ponds on migratory birds, the sourcing of water for operations from rivers, pollution of fresh water rivers by oil sands operations, the amount of carbon dioxide emitted in the production of oil from oil sands relative to the production of oil from conventional sources, and the impact on land by certain types of oil sands production techniques such as open pit mining. Not all of these reports are factual or credible. As a result, we believe it would be misleading to include the specific details. Instead, we believe presenting the general categories of perceptions to be the most appropriate way to address the risk to our business. We also note the matters raised by this risk factor are discussed in more detail in pages 37-39 of the Form 10-K and in our Sustainability Report, to which interested readers are referred on page 39 of the Form 10-K.
5
Engineering Comments
Business and Properties, page 1
Proved Developed and Undeveloped Reserves, page 26
| 5. | We note your response number 11. Please provide us with the “economic assessment of the combined activities” and the “economic analysis” that you reference. Indicate for us the assumptions underlying those analyses. Provide us also with your projected 27 year annual production schedule and demonstrate for us at what point you anticipate the project will achieve “breakeven”. |
Response to comment 5
Nexen sanctioned the Long Lake Project in early 2004. As part of our assessment at that time, we identified a number of economic risks associated with typical SAGD bitumen production, including the cost of natural gas used in the steam generation process and the cost of blending the sales bitumen with diluent (condensate). At that time, bitumen price was less than half of WTI and natural gas prices were more than double the price of bitumen on an energy equivalent basis. As described on pages 8 and 9 of our 2009 Form 10-K, the OrCrudeTM upgrading technology offered a solution to these costs by reducing the need to purchase natural gas to fuel the boilers and eliminating the need to purchase condensate for blending due to field upgrading . It also provided a synthetic crude oil which receives a price higher than bitumen. Compared to standard SAGD bitumen production, the OrCrudeTM facility required a larger initial capital investment, but offered future cost savings and reduced exposure to gas, diluent and bitumen prices versus a non-integrated facility.
Our economic assessment for our Long Lake project at the end of 2009, as presented in our Oil and Gas Producing Activities disclosures on pages 151-158 in our 2009 Form 10-K, shows that our capitalized costs for the upgrader and reserves development of $5,223 million in section (b) exceeds the future net cash inflows from proved properties of $4,998 million in section (e) using 2009 average prices. Our internal assessment of the project based on proved plus probable reserves and forecast commodity prices and costs indicate that we expect to achieve cost recovery on the project in about 15 years. The large upfront investment of the integrated project requires a significant amount of reserves to be developed efficiently over the facilities expected life.
We expect to ramp up production of synthetic crude oil to approximately 60,000 barrels per day (39,000 net to our working interest) within the next few years and maintain this capacity for more than 40 years through ongoing field development in order to match the capacity of the upgrader.
Our reserves analysis at the end of the year assumed a synthetic crude oil realized price of $67.84 per barrel over the life of the project, reflecting 2009 average prices. The proved plus probable case assumes production ramps up to facility capacity over the next few years and remains relatively constant as the
6
reserves are developed. Upon completion of development, the production declines until the economic limit is reached.
Our proved reserves estimate represents a conservative scenario which we expect to exceed as production is established and operating performance improves. The case reflects a 35 year project life with consistent production as we continue field development of new well pads over the next 27 years.
Further to our discussion, our synthetic gas facilities at Long Lake were commissioned in 2009 and have been operating reliably since the initial ramp up period. Our purchases of third-party natural gas have been significantly reduced since these facilities came on stream.
| 6. | We note response number 12. Your response suggests that the conversion rate for 2009 was unusually low. Part V entitled “Guidance for Management’s Discussion and Analysis for Companies Engaged in Oil and Gas Producing Activities” in SEC Release 33-8995 identifies material changes to the items described in Items 1202 through 1208 of Regulation S-K as topics that warrant discussion. Revise your disclosure to address the 4% PUD conversion rate in 2009 as you have done in your supplemental response clarifying, if true, why that conversion rate is atypical. Supplementally, provide us with your three-year PUD conversion rate. |
Response to comment 6
We propose amending our future filings with the following paragraph within the section titled Proved Developed and Undeveloped Reserves in our 2010 annual report.
“In 2009, we converted 18 mmboe (18 after royalties) or about 4% of our PUDs that existed at the end of last year. The conversion rate in 2009 is low because 85% of the PUDs relate to our Long Lake, Syncrude and Usan projects where their conversion is not currently being done on an ongoing basis. At Long Lake, reserves had been previously developed to the extent we believe is sufficient to keep the upgrading facility at capacity for the next few years. We expect to convert the remaining PUDs over the next 27 years as necessary to keep the upgrader full. At Syncrude, all PUDs relate to mine development that will commence in 2012. The PUDs will not be converted until the project is sufficiently completed in about 2013. At our Usan field offshore West Africa, we are in the process of drillin g and completing the wells we expect will be required to fill the facility. These reserves will be converted to proved developed reserves when construction and commissioning of the FPSO and subsea facilities is completed, which is expected to be in 2012. Excluding these PUD reserves, we converted 24% of our other 2008 PUDs to developed in 2009. We anticipate that our PUD conversion rate will vary considerably from year to year due to the stage and nature of projects associated with our crude oil and gas producing assets. The low conversion rate in 2009 is not necessarily indicative of future PUD conversion rates.”
7
Our three-year PUD conversion rate is 21%. Once again, this conversion ratio reflects the three projects noted above. In the next four years, we expect to convert 47% of 2009 PUDs as we proceed with the Syncrude mine and complete the Usan development.
Quantitative and Qualitative Disclosures about Market Risk, page 92
Special Note to Canadian Investors, page 97
| 7. | In part, your response 15 states that your third party engineers “… were not requested nor did they review our disclosures related to our reserves.” Your document references “reserves disclosures” as not reviewed by third party engineers which we interpreted as disclosures of reserve figures as well as information related to reserves. Please clarify this distinction in your disclosure. |
Response to comment 7
This reference to “reserves disclosures” is contained in a list of items prefaced by language that distinguishes between reserves estimates and related reserves disclosures. We will amend our 2010 year-end reserves disclosure to further clarify that independent qualified reserves consultants review our reserves estimates but not the related reserves disclosures.
Exhibits 23.2, 23.3, 23.4
| 8. | Your response 16 declined our request that you obtain changes to your third party engineering reports: |
| ● | The 12 month average benchmark product prices and the average adjusted prices used to determine reserves. Item 1202(8)(v) requires a discussion of the primary economic assumptions. Our position is that a discussion of such assumptions that omits the benchmark and average adjusted prices is clearly incomplete. Please amend your document to disclose these items. |
| ● | The aggregate percentage difference between your proved reserve estimates and those of your third party engineer. The third party reports by DeGolyer and MacNaughton state that your estimates “… are, in aggregate when compared to our estimates on the basis of equivalent barrels, reasonable within the established audit tolerance guidelines as set forth in the Standards Pertaining to the Estimating and audition of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.” There is no statement that the third party’s estimates and yours are within 10% of each other. Reasonable agreement is defined by Society of Petroleum Engineers as within 10%. Since DeGolyer and MacNaughton has stated that it subscribes |
8
| to the standards set by the SPE, such a statement is inappropriate. Please amend your document to include, if true, this statement. If this statement is untrue, please explain to us the justification for the claim of reasonable agreement and tell us the aggregate percentage disagreement between your proved reserve figures and those of your third party engineer. |
| ● | The aggregate percentage difference between your probable reserve estimates and those of your third party engineer. Our comments from the second bullet above apply here also. |
Please also apply this comment to Exhibits 23.6, 23.7, 23.9.
Response to comment 8
To address your comments in bullet 1, we will file amended exhibits 23.2, 23.3, 23.4, 23.6, 23.7, 23.9 to our 2009 Form 10-K to insert the respective paragraphs within the methodology and procedures section of each report of third party:
Exhibit 23.2 (UK properties)
| “The reserves estimates in this report are based upon 2009 first-of-the-month fiscal average pricing using benchmark pricing. Oil prices are based upon the Forties crude oil benchmark of US$60.62 per barrel and Dated Brent of US$60.85 per barrel, while gas prices are based upon the National Balancing Point benchmark of UK£0.32 per therm. Specific pricing for each field was adjusted for historical quality and transportation cost differentials, and for currency exchange rates. The resulting adjusted price is referred to as the “realized price.” For total proved reserves, the estimated average realized price is US$58.08 per barrel of oil and US$3.57 per thousand cubic feet of gas, based upon a volume weighted average of the properties evaluated. For total probable reserves, the weighted average realized price for proved plus probable estimates of oil a nd gas reserves is US$58.68 per barrel and US$4.35 per thousand cubic feet, respectively.” |
Exhibit 23.3 (Yemen properties)
| “The reserves estimates in this report are based upon 2009 first-of-the-month fiscal average pricing using benchmark pricing. Oil price is based upon the Dated Brent crude oil benchmark of US$60.85 per barrel. Specific oil pricing was adjusted for historical quality and transportation cost differentials. The resulting adjusted price is referred to as the “realized price” and is estimated to be US$60.46 per barrel of oil for proved and probable reserves.” |
Exhibit 23.4 (Nigeria property)
| “The reserves estimates in this report are based upon 2009 first-of-the-month fiscal average pricing using benchmark pricing. Oil price is based upon the Dated Brent crude oil benchmark of US$60.85 per barrel. Specific oil pricing was adjusted for estimated area quality and transportation cost differentials. The resulting adjusted price is referred to as the “realized price” and is estimated to be US$58.18 per barrel of oil for proved and probable reserves.” |
9
Exhibit 23.6 (Canadian properties excluding Syncrude)
| “The reserves estimates in this report are based upon 2009 first-of-the month fiscal average pricing using benchmark pricing. Oil prices are primarily based upon West Texas Intermediate at Cushing crude oil benchmark of US$61.18 per barrel and Western Canadian Select at Hardisty benchmark of Cdn$59.28 per barrel. Gas prices are based upon AECO benchmark of Cdn$3.72 per gigajoule. Specific pricing for each field was adjusted for historical quality and transportation cost differentials, and for currency exchange rates. The resulting adjusted price is referred to as the “realized price”. For total proved reserves, the estimated average realized prices are Cdn$56.74 per barrel of oil, Cdn$67.84 per barrel of synthetic crude oil, and Cdn$3.66 per thousand cubic feet of gas, based upon a volume weighted average of the properties evaluated. For total probable reserves, th e weighted average realized prices for proved plus probable estimates of reserves are Cdn$56.71 per barrel of oil, Cdn$67.84 per barrel of synthetic crude oil, and Cdn$3.66 per thousand cubic feet of gas.” |
Exhibit 23.7 (Syncrude property)
| “The reserves estimates in this report are based upon 2009 first-of-the-month fiscal average pricing using benchmark pricing. Syncrude synthetic crude oil price is based upon West Texas Intermediate at Cushing crude oil benchmark of US$61.18 per barrel. Syncrude synthetic crude oil pricing was adjusted for historical quality and transportation cost differentials, and currency exchange rates. The resulting adjusted price is referred to as the “realized price” and is estimated to be Cdn$70.85 per barrel of synthetic crude oil for proved and probable reserves.” |
Exhibit 23.9 (US properties)
| “The reserves estimates in this report are based upon 2009 first-of-the month fiscal average pricing using benchmark pricing. Oil prices are based upon the West Texas Intermediate at Cushing crude oil benchmark of US$61.18 per barrel, while gas prices are based upon the Henry Hub benchmark of US$3.82 per mmbtu. Specific pricing for each field was adjusted for historical quality and transportation cost differentials. The resulting adjusted price is referred to as the “realized price.” For total proved reserves, the estimated average realized price is US$57.14 per barrel of oil and US$3.97 per thousand cubic feet of gas, based upon a volume weighted average of the properties evaluated. For total probable reserves, the weighted average realized price for proved plus probable estimates of oil and gas reserves is US$56.93 per barrel and US$3.97 per thousand cu bic feet, respectively.” |
| We will file amended exhibits 23.2, 23.3, 23.4, 23.6, 23.7, 23.9 to our 2009 Form 10-K to address your comments in bullets 2 and 3 by amending the wording in each report as follows: |
| “In our opinion, the proved and proved plus probable reserves for the reviewed properties as estimated by Nexen are, in aggregate when compared to our estimates on the basis of equivalent barrels, reasonable because each is within 10 percent of our estimates.” |
10
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