June 27, 2008
VIA EDGAR AND MESSENGER
United States Securities and Exchange Commission
Division of Corporation Finance
100 F Street, N.W.
Washington, D.C. 20549-0405
Attention: Mr. H. Roger Schwall
| Re: | Plains Exploration & Production Company | |
| Form 10-K for the period ended December 31, 2007 | ||
| Filed February 27, 2008 | ||
| File No. 001-31470 |
Dear Mr. Schwall:
On behalf of Plains Exploration & Production Company (the “Company”), set forth below are the Company’s responses to the comments of the Staff (the “Staff”) of the Securities and Exchange Commission (the “Commission”) regarding the above referenced filing set forth in the letter dated June 19, 2008. For your convenience, we have repeated each of the comments set forth in the Staff’s letter and followed each comment with the Company’s response.
Form 10-K for the Fiscal Year Ended December 31, 2007
Engineering Comments
Business and Properties, page 6
Description of Properties, page 10
Onshore California, page 11
| 1. | We have reviewed your response to prior comment three of our letter of June 10, 2008. Of the six projects you describe, there are 175 million barrels equivalent of proved undeveloped reserves or 56% of the total proved reserves in these projects. In 2007 you indicate you converted 10.5 million barrels, or approximately 6% of the current PUD volume, to proved developed reserves. Based on this rate of development it will take you almost 17 years to just develop these reserves let alone actually produce them. We do not believe that this is sufficient progress to maintain such a high level of proved undeveloped reserves. We note from the reserve report that you anticipate drilling some of these wells well beyond the five years that most in the industry believe should be the maximum time proved undeveloped reserves should be so classified. Please revise your reserves for these projects to provide a more reasonably certain volume of reserves that can be developed in a reasonable period of time. |
Securities and Exchange Commission
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Response:
Collectively these fields have been on production in excess of sixty years with a long-established track record of consistent development activity. Producing rates have been maintained at relatively stable levels over the last fifteen years with steadily increasing producing well counts. Over the last three years, we have drilled a total of 574 wells and spent $500 million in these fields developing reserves. We believe this represents significant progress and compelling evidence of our commitment to develop our proved undeveloped reserves.
The historical and forecasted pace of development in each of these fields is governed by several factors. First and foremost is achieving an appropriate level of strategic balance in view of our entire investment portfolio. As operator with 100% ownership of these assets we control the pace of development and have the ability to either accelerate or slow this pace as overall corporate strategy and other market drivers dictate.
Second, we have forecast a pace of development in our reserve report that is consistent with recent historical levels. We believe this pace should serve as the basis from which we forecast the pace of future development as it considers our own internal resource constraints as well as those of our drilling and other service company contractors.
Also, the forecasted pace of development activity in each field is thoughtfully scheduled in consideration of that field’s location. In the LA Basin, both Inglewood and Montebello are located in urban environments which require good corporate citizenship in order to maintain consistent development programs. This can, and often does, prevent us from drilling at certain times and requires that we maintain a view of the impact our development operations may have on the surrounding community (e.g. traffic, noise level, air quality, etc.). In the San Joaquin Valley, we are generally operating in mature thermal fields that are densely developed and require a significant amount of production curtailment and interruption to steaming operations for safety reasons during drilling operations. We believe that our recent historical and forecasted pace of development in these fields strikes an appropriate balance between consistent and significant development progress with no compromise to high safety standards, while maintaining production and cash flow.
In summary, we believe that we have maintained significant levels of reserve development progress in each of these fields. We have management approval and financial commitment to execute these development plans, and we have a long history of approval by regulatory bodies and government agencies. In addition, we have forecast a reasonable pace of development in our reserve report and therefore we believe that no revision to proved undeveloped reserves is warranted.
Securities and Exchange Commission
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| 2. | It appears, from information found on the Division of Oil & Gas in California’s website, that most of your California properties are producing at high water cuts but we could find no disclosure to this effect. If this is true, please provide this disclosure in future filings. |
Response
It is true that most of our onshore California properties are producing at high water cuts and we will provide disclosure to this effect in future filings.
| 3. | Please tell us the current operational status of the Arroyo Grande field. We note that in your 2004 10-K you indicated that you began final planning, engineering and permitting for the installation of a reverse osmosis water treatment plant needed to remove water from the producing reservoir and increase operating efficiency. You stated you expected to install those facilities during 2005 and 2006 and then accelerate the drilling of new wells in 2006. This is the same information you provided us in response three but installation of the water plant is apparently now not until the last quarter of 2009 when you say you will resume development activities. |
In 2004 you reported that you had 54.8 million barrels equivalent proved reserves of which 49.2 million were proved undeveloped. Based on your response three you have about the same level of both proved developed and undeveloped reserves indicating little progress in development of undeveloped reserves in this field. Although you indicated in 2004 you would have an accelerated drilling of new wells in 2006, according to the DOG the number of producing wells actually declined from 134 wells in 2004 to 130 wells in 2006 and according to your reserve report the number of producing wells in 2008 is 118. Because these undeveloped reserves have remained in the same classification for at least five years and the earliest that you may develop them is in 2009 and the water plant is still not installed, it appears that you need to remove these from the proved category as they are not certain enough to be considered proved at this time.
Response:
A significant amount of activity and progress has been achieved with respect to the water plant and continued development of reserves that we believe warrant continued recognition of these undeveloped reserves as proved.
In 2004, we developed a Memorandum of Understanding with San Luis Obispo County to pursue an option to discharge water from a reverse osmosis treatment plant (“ROP”) to Lake Lopez. During 2005, through close collaboration with the County flood control division and, after numerous environmental assessments were completed, we decided to pursue an alternate solution for water discharge. In 2006, we successfully completed Phase II of the ROP pilot for an alternate point of discharge. Subsequently, we submitted applications to both County and State agencies to fabricate and install the ROP and for a permit for that alternate point of discharge.
Securities and Exchange Commission
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To date, we have achieved two significant permit milestones: 1) approval from the State for discharge of the ROP treated produced water, and 2) initial approval from the County planning commission for construction of the ROP. We expect all appeals to be completed, and final permits to be issued from the County supervisors during 2008. Detailed design of the facilities is nearing completion with procurement of equipment and material scheduled to commence this fall. Construction is estimated to be completed in late 2009.
The Company could not forecast the rework of our water discharge plan and the ensuing time required to obtain approvals for our plan. However, we proceeded with other portions of our development plan in order to maintain our reserve development schedule. Further evidence of our commitment and confidence in the current schedule is that we have spent $21 million of development capital and have drilled 47 proved undeveloped locations over the last two years in Arroyo Grande. Further, we plan to drill 40 additional proved undeveloped locations in 2008 (beginning in August) and 38 in 2009.
We direct the Staff to our response to comment three in our letter dated June 10, 2008 in which we explained that the proved undeveloped reserves associated with these activities have not been migrated into the developed category since we still have additional significant capital expenditures related to the ROP. Also the phrase “optimally resume development activity” in the same response was not intended to convey a historical and/or current lack of activity but, rather, that, once the ROP has been installed, we would resume the conversion of proved undeveloped reserves to the developed category.
In summary, we believe that we have maintained both consistent and significant levels of reserve development progress. Moreover, we have management approval and financial commitment to execute this development plan and we have confidence in our development plan schedule and, therefore, we believe that no revision to proved undeveloped reserves is warranted.
| 4. | You have provided past disclosure on the Arroyo Grande field that you are down-spacing the injection patterns from five acres to 1-1/4 acres to accelerate recoveries. Please tell us if any of the 330 wells you have classified as proved undeveloped are included in this down-spacing activity. |
Response:
No, none of the 330 proved undeveloped locations recognized at December 31, 2007 are included to down-space the active steam flood area.
Securities and Exchange Commission
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| 5. | Please tell us the amount of original oil in place in a 1-1/2 acre injection pattern in Arroyo Grande, how you calculated it with the reservoir parameters utilized, what you believe is now remaining and the expected recovery from that volume of oil currently in place. |
Response:
The response to this comment has been provided supplementally under separate cover pursuant to a confidential treatment request under the Freedom of Information Act and applicable regulations of the Commission.
Supplemental Reserve Information, page F-37
Estimated Quantities of Oil and Natural Gas Reserves (Unaudited), page F-38
| 6. | Please provide appropriate explanations for significant reserve changes in the table of reserve changes. Please see paragraph 11 of SFAS 69. |
Response:
Revisions of Previous Estimates
In 2007 we had a total of 93 million barrels equivalent of positive revisions. Of these 93 million barrels, 27 million barrels were in onshore California. These positive revisions were a result of both successful development activities as well as economic life extension resulting from significantly higher oil prices at year-end 2007. We also had 52 million barrels equivalent of positive revisions in the Piceance Basin. Of these 52 million barrels, 45 million barrels were solely due to higher gas price realizations at December 31, 2007 as this amount was evaluated as technically proven at the time of the May 2007 acquisition but was not classified as proved because the reserves were not commercial due to high gas price location differentials in the Rocky Mountains at the time. The remaining 7 million barrels of positive Piceance Basin revisions were a result of both successful development activities over the remainder of 2007 as well as improved gas price realizations at year-end 2007. The balance of 14 million barrels equivalent of positive revisions were primarily in offshore California and the Permian Basin, again resulting from both successful development activities in 2007 as well as significantly higher product prices at year-end 2007.
In 2006 we had a total of 3 million barrels equivalent of downward revisions primarily related to performance of our Inglewood Deep development.
In 2005 we had a total of 12 million barrels equivalent of downward revisions primarily related to performance of our Inglewood Deep development and Rocky Point development projects.
Securities and Exchange Commission
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Improved Recovery
In 2006 we had a total of 11 million barrels equivalent of proved reserve additions related to expansion of improved recovery projects in several of our onshore California fields.
In 2005 we had a total of 20 million barrels equivalent of proved reserve additions related to improved recovery. Of these 20 million barrels equivalent, 10 million barrels equivalent were related to the expansion of existing improved recovery projects in several of our onshore California fields. The remaining 10 million barrels equivalent were related to new improved recovery projects in onshore California.
Purchases of Minerals in Place
In 2007 we had a total of 237 million barrels equivalent of acquisitions resulting from two transactions. The first, occurring in May 2007, was the acquisition of Laramie Energy’s interests in the Piceance Basin. This transaction accounted for 19 million barrels equivalent of additions to proved reserves. The second transaction, occurring in November 2007, was the acquisition of Pogo Producing Company. This transaction accounted for 218 million barrels equivalent of additions to proved reserves.
In 2005 we had a total of 19 million barrels equivalent of acquisitions primarily related to the acquisition of several onshore California fields located in the Los Angeles and Santa Maria Basins.
Extensions and Discoveries
In 2007 we had a total of 31 million barrels equivalent of extensions and discoveries. Of these 31 million barrels equivalent, 19 million barrels equivalent of extensions were in the Piceance Basin resulting from successful drilling during 2007 that extended the proved acreage. Another 3 million barrels equivalent were attributable to new discoveries made in the Gulf of Mexico on the Hurricane Deep and Flatrock prospects. The remaining 9 million barrels of extensions were primarily attributable to the extension of proved acreage in Cymric and Midway Sunset Diatomite, East Texas Austin Chalk and South Texas.
In 2006 we had a total of 8 million barrels equivalent of extensions and discoveries, the majority of which were related to the extension of proved acreage in several of our onshore California fields.
In 2005 we had a total of 4 million barrels equivalent of extensions and discoveries, the majority of which were related to the extension of proved acreage in several of our onshore California fields.
Production
We had a total of 23 million barrels equivalent, 22 million barrels equivalent and 24 million barrels equivalent of production in 2007, 2006 and 2005, respectively.
Securities and Exchange Commission
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Sales of Minerals in Place
In 2006 we had a total of 43 million barrels equivalent of divestments. Of these 43 million barrels equivalent, 30 million barrels equivalent represented our entire interest in several fields in onshore California, both in the LA Basin and San Joaquin Valley. The remaining 13 million barrels equivalent primarily represented our entire interest in a field located in West Texas.
In 2005 we had a total of 26 million barrels equivalent of divestments, the majority of which represented our entire interest in several fields in East Texas.
We propose to include similar disclosure in future filings.
Reserve Report
| 7. | We note from your disclosure in 2007 and from earlier 10-K reports that the LA Basin production appears to be declining at a rate of approximately 7.7% per year for the last three years. We also note from the reserve report that this is the approximate rate of decline assigned to the proved producing category for the LA Basin. However, the decline rate of 7.7% has been supported by the drilling of approximately 134 wells in the last three years. We note that your total proved reserves in the reserve report are the summation of the reserve categories of proved developed producing, proved developed non-producing and proved undeveloped reserves. Therefore, it appears that the total proved reserves may be materially too high due to the fact that you incrementally add every PUD well to the proved producing reserve category decline rate which appears to already be supported by an established level of drilling on the LA Basin properties. |
Please tell us how you accounted for the effect of recent past drilling programs on your base level decline rate of the proved developed producing reserve category or revise your estimate to remove the effects of this past drilling before adding the other reserve categories to it.
Response:
The response to this comment has been provided supplementally under separate cover pursuant to a confidential treatment request under the Freedom of Information Act and applicable regulations of the Commission.
| 8. | We issue the same comment as above for the San Joaquin Basin which is declining at about 12% per year for the last three years after the drilling of 430 wells in the last three years. |
Securities and Exchange Commission
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Response:
The response to this comment has been provided supplementally under separate cover pursuant to a confidential treatment request under the Freedom of Information Act and applicable regulations of the Commission.
| 9. | We note a large difference of about 35% between Plains and Ryder Scott in the proved developed non-producing behind pipe category of reserves. Please tell us how this large difference was reconciled. |
Response:
While the difference between us and Ryder Scott was 35%, this amounts to only 801 thousand barrels equivalent or approximately 0.1% of total proved reserves. As these proved developed non-producing reserves were part of an audit conducted by Ryder Scott, we made no attempt to reconcile these specific items. The overall variance on that audit was 8.6%, well within generally accepted audit tolerance standards, with total coverage of 86% of the proved reserves audited by Ryder Scott.
| 10. | We note estimated capital expenditures of $10.4 million in 2008 and $8 million per year in 2009 through 2018 in the proved producing reserve category of the NW Lompoc and Point Pedernales fields of offshore California. Please provide us with the reasons for these capital expenditures in this reserve category. |
Response:
As discussed in our response to comment one in our letter dated June 10, 2008 these costs consist of capital costs required for production equipment and supporting infrastructure used in the production of oil and gas from our proved developed producing reserves. Because we have an established, consistent history of these types of capital expenditures in these fields, we feel it prudent to forecast a reasonable level of ongoing capital expenditures in this reserve category.
| 11. | We note estimated capital expenditures of $7.2 million in 2008 and $4.9 million per year in 2009 through 2019 in the proved producing reserve category of the Point Arguello and Rocky Point fields of offshore California. Please provide us with the reasons for these capital expenditures in this reserve category. |
Response:
As discussed in our response to comment one in our letter dated June 10, 2008 these costs consist of capital costs required for production equipment and supporting infrastructure used
Securities and Exchange Commission
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in the production of oil and gas from our proved developed producing reserves. Because we have an established, consistent history of these types of capital expenditures in these fields, we feel it prudent to forecast a reasonable level of ongoing capital expenditures in this reserve category.
| 12. | We also note capital expenditures in the proved producing reserve category for every year in every California field except Coalinga. Please tell us the reasons you are assigning annual capital expenditures in this proved reserve category. |
Response:
As discussed in our response to comment one in our letter dated June 10, 2008 these costs consist of capital costs required for production equipment and supporting infrastructure used in the production of oil and gas from our proved developed producing reserves. Because we have an established, consistent history of these types of capital expenditures in these fields, we feel it prudent to forecast a reasonable level of ongoing capital expenditures in this reserve category. The Coalinga field is a royalty property and accordingly no such costs were included in the reserve report.
| 13. | According to the reserve report you plan to drill 56 wells in the Piceance Basin in 2008. Please tell us how many of these wells have been drilled to date and the results. |
Response:
Of the 56 proved undeveloped locations planned for development in 2008, 29 have been drilled and 3 more are currently drilling. Of the 29 locations that have been drilled, we have logged and set pipe on all 29 locations (100% success). Seven of these locations are currently producing at an average rate of 700 mcfd, 6 locations have been completed (fracture stimulated) and are waiting on hook-up for production and the remaining 16 locations are waiting on completion.
In addition to these proved undeveloped locations we have also drilled an additional 18 unproved locations, with the same 100% success rate, and are currently drilling 2 additional unproved locations. Of the 18 locations that have been drilled, one well has been completed and is currently producing at an average rate of 600 mcfd, 2 locations have been completed (fracture stimulated) and are waiting on hook-up for production and the remaining 15 locations are waiting on completion.
| 14. | We also note that you have scheduled the drilling of over 700 wells in the Piceance Basin some of which are apparently not to be drilled until beyond 2022. Please tell us if you have the legal right to drill these wells at this time and if your management has specifically sanctioned them. Please tell us why you believe these reserves, most of which will not be developed until well beyond five years, meet the definition of proved reserves. |
Securities and Exchange Commission
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Response:
As of December 31, 2007, we had 810 proved undeveloped locations in our Piceance Basin properties, all of which are one-offset locations on 10 acre spacing to a proved developed location. Of these 810 proved undeveloped well locations, 696 are located on acreage that is held by production (“HBP”). Another 76 proved undeveloped locations are attributed to acreage that has been converted to HBP as a result of our year to date 2008 drilling activity. The remaining 38 proved undeveloped locations are located on primary term acreage that we expect to convert to HBP prior to primary term expiration through our ongoing development drilling program. This provides us the legal right to drill these wells at the pace proposed in our reserve report.
We currently have 5 rigs actively drilling in the Piceance Basin, with plans to increase to 10 rigs over the next five years. We then plan to maintain this 10-rig activity level until our acreage is fully developed. Both this development plan and the necessary capital funding are approved by management. Over the next five years, we plan to drill 1,000 wells which exceeds our current proved undeveloped location inventory. Our complete Piceance Basin development plan includes a total of 2,500 proved, probable and possible locations.
While our proved undeveloped locations are primarily located on HBP acreage, the majority of our probable and possible locations are attributed to primary term leasehold. Therefore our development strategy also plans for drilling a significant number of probable and possible locations over the next five years in order to establish production on this primary term acreage and secure the long-term rights necessary to preserve our 3P reserve potential.
We believe that this plan demonstrates significant progress, commitment, and reasonable certainty that our current proved undeveloped inventory will be developed and, therefore, meets the definition of proved reserves.
If you have any questions with respect to the foregoing, please call Wright Williamson, Vice President Engineering at (713) 579-6710 or the undersigned at (713) 579-6109.
Very truly yours, |
/s/ John F. Wombwell |
John F. Wombwell |
Executive Vice President and General Counsel |
Securities and Exchange Commission
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| cc: | Wright Williamson | |
| Vice President Engineering | ||
| John Goodgame | ||
| Akin Gump Strauss Hauer & Feld LLP | ||
| James Murphy | ||
| United States Securities and Exchange Commission | ||