September 14, 2012
Via EDGAR Transmission
Securities and Exchange Commission Division of Corporation Finance 100 F Street, N.E. Washington, D.C. 20549 Attention: H. Roger Schwall
Re: Plains Exploration & Production Company Form 10-K for Fiscal Year Ended December 31, 2011 Filed February 24, 2012 File No. 1-31470 | 811 Main Street, Suite 3700 Houston, TX 77002 Tel: +1.713.546.5400 Fax: +1.713.546.5401 www.lw.com
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Dear Mr. Schwall:
On behalf of Plains Exploration & Production Company, a Delaware corporation (the “Company”), we hereby set forth the following information in response to the comments contained in the letter dated August 23, 2012 from the staff (the “Staff”) of the Securities and Exchange Commission (the “Commission”). The comments of the Staff contained in its letter are repeated below and are followed by a summary of the Company’s response.
Form 10-K for the fiscal year ended December 31, 2011
Oil and Gas Reserves, page 9
| 1. | We note you have elected to present unproved reserve quantities within your annual report. Please explain the reasons for the material variance in the probable undeveloped gas reserves quantities you report in your table on page 11 versus the estimated probable undeveloped gas reserves presented in your third party engineer report, filed as Exhibit 99.1. |
Please confirm the probable reserves you have presented meet the definition set forth in Rule 4-10(a)(18) of Regulation S-X, as well as adhere to the guidance set forth in Section 117 of the Compliance and Disclosure Interpretations.
Response:Information with respect to our proved and probable reserves presented in the Company’s Form 10-K are based on (a) reserve reports prepared by third party engineers and (b) reserve volumes prepared by the Company and not audited by an independent petroleum engineer. Specifically, of the 1,080,967 MMcf of probable undeveloped gas
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reserves reported in our table on page eleven, 38,432 MMcf was prepared by Netherland, Sewell and Associates, Inc. (and presented in their report filed as Exhibit 99.1) and 1,042,535 MMcf was prepared internally by the Company. The probable reserves we have presented meet the definitions set forth in Rule 4-10(a)(18) of Regulation S-X and adhere to the guidance set forth in Section 117 of the Compliance and Disclosure Interpretations.
Hydraulic fracturing, page 30
| 2. | We note your disclosure here and elsewhere that you engage in hydraulic fracturing, that natural gas accounts for the majority of your proved reserves and that you have operations in the Eagle Ford and Haynesville shale formations. Accordingly, in an appropriate location, please provide a more detailed discussion of the hydraulic fracturing process, what it entails, how it is done, etc. Also, if material, please provide risk-factor disclosure addressing the specific operational and financial risks associated with hydraulic fracturing. |
Response:We acknowledge the Staff’s comments and will revise our future filings by including disclosure substantially similar to the language below, updated as applicable based on any regulatory developments. The new disclosure would replace the paragraph of the Company’s Form 10-K entitled “Business and Properties—Regulation—Hydraulic Fracturing” (currently page 30 of the Company’s Form 10-K for the fiscal year ended December 31, 2011).
“Hydraulic Fracturing. Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations such as shales. The process involves the injection of large quantities of water, which contains sand and small amounts of various chemicals, under pressure into the formation to fracture the surrounding rock and stimulate oil and natural gas production. The use of hydraulic fracturing is necessary to produce commercial quantities of oil and natural gas from many reservoirs, especially shale formations such as the Haynesville Shale and Eagle Ford Shale. The process is typically regulated by state oil and natural gas commissions. Our operations utilize the practice of hydraulic fracturing for new oil and natural gas wells. Hydraulic fracturing is also used occasionally to recomplete or restimulate an existing well that has declined in production performance. The practice of hydraulic fracturing continues to receive significant regulatory and legislative attention at the federal, state, and local level. The U.S. Environmental Protection Agency (“EPA”) recently asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel under the Safe Drinking Water Act (“SDWA”) and is in the process of drafting guidance documents on regulatory requirements for companies that plan to conduct hydraulic fracturing using diesel. In addition, on May 11, 2012, the Bureau of Land Management proposed regulations that would require public disclosure of the chemicals used in hydraulic fracturing and impose certain permitting and testing requirements on such operations on federal lands. Various
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federal agencies in addition to the EPA (including the Department of Energy) continue to study hydraulic fracturing and may propose additional regulations. From time to time, legislation has been introduced in Congress to amend the SDWA to eliminate exemptions for most hydraulic fracturing activities. In addition to the SDWA, the EPA recently approved final rules that establish new air emission controls for natural gas and natural gas liquids production, processing and transportation activities, including New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds, and a separate set of emission standards to address hazardous air pollutants frequently associated with production and processing activities, which rules were published in the Federal Register on August 16, 2012. Similar efforts to review the practice and impose new regulatory conditions are taking place at the state and local level in states where we operate, several of which have adopted or are considering new regulations and statutes, including California, Texas and Wyoming. These new requirements will (and future regulatory and legislative changes, if enacted, could) create new permitting and financial assurance requirements, require us to adhere to certain construction specifications, fulfill monitoring, reporting and recordkeeping obligations, and meet plugging and abandonment requirements. Although we would not be impacted to a greater degree than other similarly situated oil and gas companies, the imposition of stringent new regulatory and permitting requirements related to the practice of hydraulic fracturing could significantly increase our cost of doing business, create an adverse effect on our operations, and depending on the specifics of any particular proposal that is enacted, could be material.”
Additionally, in our future filings we will revise our existing risk factor relating to hydraulic fracturing (currently page 42 of the Company’s Form 10-K for the fiscal year ended December 31, 2011). The revised risk factor would be substantially similar to the following:
“Legislation and regulatory initiatives relating to hydraulic fracturing could increase our cost of doing business and adversely affect our operations.
Our operations utilize the practice of hydraulic fracturing for new oil and natural gas wells and is also occasionally used to recomplete or restimulate an existing well that has declined in production performance. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into rock formation to stimulate oil and natural gas production. The use of hydraulic fracturing is necessary to produce commercial quantities of oil and natural gas from many reservoirs, especially shale formations such as the Haynesville Shale and the Eagle Ford Shale. The process is typically regulated by state oil and natural gas commissions, and continues to receive significant regulatory and legislative attention at the federal, state, and local level. The EPA recently asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel under the SDWA and is in the process of drafting guidance documents on regulatory requirements for companies that plan to conduct
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hydraulic fracturing using diesel. In addition, on May 11, 2012, the Bureau of Land Management proposed regulations that would require public disclosure of the chemicals used in hydraulic fracturing and impose certain permitting and testing requirements on such operations on federal lands. Various federal agencies in addition to the EPA (including the Department of Energy) continue to study hydraulic fracturing and may propose additional regulations. From time to time, legislation has been introduced in Congress to amend the federal SDWA to eliminate exemptions for most hydraulic fracturing activities. In addition to the SDWA, the EPA recently approved final rules that establish new air emission controls for natural gas and natural gas liquids production, processing and transportation activities, including New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds, and a separate set of emission standards to address hazardous air pollutants frequently associated with production and processing activities, which rules were published in the Federal Register on August 16, 2012. Similar efforts to review the practice and impose new regulatory conditions are taking place at the state and local level in states where we operate, several of which have adopted or are considering new regulations and statutes, including California, Texas and Wyoming. These new requirements will (and future regulatory and legislative changes, if enacted, could) create new permitting and financial assurance requirements, require us to adhere to certain construction specifications, fulfill monitoring, reporting and recordkeeping obligations, and meet plugging and abandonment requirements. The imposition of stringent new regulatory and permitting requirements related to the practice of hydraulic fracturing could significantly increase our cost of doing business and adversely affect our operations, and depending on the specifics of any particular proposal that is enacted, could be material.”
In addition, we note that natural gas does not account for the majority of our proved reserves. As of December 31, 2011, oil and liquids account for 59% of our proved reserves and natural gas accounts for 41% of our proved reserves.
* * *
In connection with the Company’s response to the Staff comments, the Company acknowledges 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 proceeding initiated by the Commission or any person under the federal securities laws of the United States. |
Thank you for your review of this additional information. If you have any questions regarding the foregoing, please do not hesitate to contact the undersigned at (713) 546-7418.
September 14, 2012
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| Very truly yours, |
| /s/ Sean T. Wheeler |
| Sean T. Wheeler |
| of LATHAM & WATKINS LLP |
| cc: | John F. Wombwell, Executive Vice President, General Counsel |
and Secretary, Plains Exploration & Production Company
Michael E. Dillard, Latham & Watkins LLP