April 27, 2005
Via facsimile and U.S. mail
Securities and Exchange Commission
Division of Corporate Finance
450 Fifth Street, N.W., Mail Stop 4-5
Washington, D.C. 20549-0405
Attention: H. Roger Schwall
| Re: | Pioneer Natural Resources Company | |
| Form 10-K, Filed February 22, 2005 | ||
| File No. 1-13245 |
Dear Mr. Schwall:
We are writing to respond to the engineering comments of the Staff of the Securities and Exchange Commission with respect to our Form 10-K in the comment letter dated March 29, 2005 (the “Comment Letter”), addressed to Richard P. Dealy, Executive Vice President and Chief Financial Officer of Pioneer Natural Resources Company (“Pioneer” or the “Company”).
Comment Responses
The bold typeface, numbered paragraphs and headings below are taken from the Comment Letter. Our response to each such comment follow in plain text.
Form 10-K for the year ended December 31, 2004
Business, page 5
| Evergreen Merger, page 5 | ||||
| 1. | We note your reference to Evergreen’s Raton Basin coal bed methane reserves. Supplementally, tell us the methodology you used to estimate your proved CBM reserves here. As a minimum, address: | |||
| General Comment:The proved coal bed methane (“CBM”) reserves recognized in conjunction with the merger with Evergreen Resources, Inc. (“Evergreen”) in September 2004 were estimated using standard petroleum engineering principles and practices that are applicable to CBM. Specifically, the reserves for proved developed producing wells were estimated from a combination of decline curve analysis (where adequate well history was available to project a well’s decline) and type curve analysis (where the production data to-date was not adequate to project a well’s decline). | ||||
H. Roger Schwall
Securities and Exchange Commission
Page 2
April 27, 2005
| In either case, the reserve forecasts were tied to a volumetric estimate of the original gas-in-place (“GIP”) and the recovery of a given percentage of the GIP. Typical recoveries were estimated to be between 50 percent and 85 percent of the original GIP, depending on coal permeability, depth, initial pressure, coal adsorptive capacity and estimates of reservoir abandonment pressure. Reserves for proved undeveloped locations were estimated using volumetrics and type curves based on offsetting producing wells. |
| a) | Gas production rate criteria for attributing proved reserves to newly drilled exploration locations; |
| Response:Gas production rates for reserve estimates of newly drilled wells are based on type curves from offsetting producing wells. As actual production data from the well becomes available, the reserve forecast is reviewed periodically and subsequently adjusted, if necessary. GIP estimates are made for the spacing unit area to ensure that the reserve estimates do not exceed a reasonable estimate of the recoverable GIP. |
| b) | Criteria for use of inclining production projections; |
| Response:Inclining gas production in CBM wells is very typical due to the physics of methane desorption and increased relative permeability to gas early in the life of a well. Pioneer operates more than 1,250 CBM wells in the Raton Basin in southern Colorado. These wells produce from the Vermejo and Raton coals and have demonstrated the inclining production profile. Therefore, our typical well performance and type curve is based on the expectation that gas production will incline during the early life of a well. Consequently, reserve forecasts for newly drilled wells and proved undeveloped locations will typically have an inclining production gas rate period in the reserve projection based on the historical well performance in this area. |
| The primary exception to this case would be that of an infill well which is drilled later in the life of the reservoir, where significant pressure drawdown has occurred and free gas saturation is present. In these cases, a well will more typically see its peak gas rate when it begins to produce and decline thereafter, more like a conventional gas well. |
| c) | Criteria for use of declining production projections; |
| Response:Declining production projections are used on wells where the gas rate has peaked and production has begun to decline. Typical CBM well declines in the Raton Basin are exponential in nature. In cases where the gas production rate has not peaked, a type curve forecast is applied. |
| d) | Criteria for use of volumetric method and volumetric parameters used, particularly drainage area; |
| Response:The volumetric method is used to estimate GIP and recoverable reserves by applying a recovery factor to the GIP. The volumetric recoverable reserves are then used to constrain the individual well forecasts on a spacing unit by spacing unit basis, typically 160 acres. Drainage areas are not explicitly estimated for each well. Other volumetric parameters in the CBM GIP equation are estimated as follows: |
H. Roger Schwall
Securities and Exchange Commission
Page 3
April 27, 2005
GIP = Area times coal thickness times coal density times gas content
| Parameter | Data Source | |
| Area | Spacing unit size | |
| Coal thickness | High resolution density logs using a 2.0 grams per cubic centimeter cut-off value | |
| Coal density | High resolution density logs and bulk density measurements from core samples | |
| Gas content | Actual desorption measurements or calculated from isotherms at the estimated reservoir pressure |
| e) | Methodology for attribution of proved undeveloped reserves; |
| Response:Proved undeveloped reserves are attributed to well locations using the same volumetric approach as used for developed reserves. The recoverable reserves are estimated from the GIP estimates and are used to constrain the type well forecasts which are based on offsetting well performance. |
| f) | Sources of original gas-in-place information, particularly whether derived from desorption data. |
| Response: The original GIP estimates for the Raton and Vermejo coals were made previously for Evergreen by an independent engineering firm. The data sources for the CBM volumetric equation are discussed above in item (d). We currently have gas content data from more than 40 wells in the Raton Basin. These measured gas content values are used in our estimates of GIP. We continue to update and refine our GIP estimates as additional data is gathered. |
Risks Associated with Business Activities, page 11
| Operation of natural gas processing plants, page 12 | ||||
| 2. | We note your gas plant operation discussed here. Please amend your future documents to disclose separately any proved NGL reserves you may have claimed through gas plant ownership. | |||
| Response:The Company does not recognize any incremental proved natural gas liquid (“NGL”) reserves as a result of gas plant ownership. Thus, no future disclosure is deemed necessary. | ||||
| International operations, page 14 | ||||
| 3. | Here and elsewhere (page 106) you discuss the application of the “economic interest method” for the attribution of proved reserves under “production sharing arrangements” with foreign governments. Amend your future documents to disclose the countries and the proved reserves subject to such production sharing arrangements. | |||
| Response:In future filings, when referring to proved reserves attributable to significant production sharing arrangements with foreign governments, the Company will disclose the countries and the proved reserve quantities subject to such significant production sharing arrangements. | ||||
H. Roger Schwall
Securities and Exchange Commission
Page 4
April 27, 2005
Item 2 Properties, page 14
| 4. | You indicate that Netherland, Sewell and Associates audited your year-end 2004 major properties’ proved reserves. In future filings, explain how NSAI “audits” your reserves and include the degree of agreement, in aggregate, between your proved reserve figures and those estimated by NSAI. Disclose the portion of your total reserves included in the audit. | |||
| Response:In future filings, the Company will disclose the process and data assumptions used by Netherland, Sewell & Associates (“NSAI”) to perform its audits of the Company’s proved reserves. The Company will also disclose the portion of its total proved reserves and present value of such reserves (discounted at ten percent) included in the audit. A sample of such future disclosure is included below for your review. | ||||
| NSAI essentially created its own reserve report to which a comparison was made of Pioneer’s corresponding proved reserves and present values discounted at ten percent. Because both reserves and value differences, in the aggregate, were less than ten percent, an unqualified audit letter was provided by NSAI. Differences are typically not fully resolved once, in the aggregate, the reserve estimates are within the ten percent threshold due to the limited cost benefit of continuing such analysis by both the Company and NSAI. Therefore, the Company respectfully submits that disclosing, in the aggregate, the difference between the Company’s estimates of proved reserves and NSAI’s estimates may not be completely accurate and may be misleading to the reader. | ||||
| Sample Disclosure: Netherland, Sewell & Associates (“NSAI”) performed an independent evaluation on 88 percent and 85 percent of the Company’s December 31, 2004 proved reserves and associated present value discounted at ten percent, respectively, as part of their audit of our reserves. In conjunction with the audit, the Company provided to NSAI its external and internal engineering and geoscience technical data and analyses. Based on NSAI’s review of that data, they had the option of honoring the Company’s interpretation, or making their own interpretation. No data was withheld from them. NSAI accepted without independent verification the accuracy and completeness of the historical information and data furnished by the Company with respect to ownership interest; oil and gas production; well test data; oil, NGL and gas prices; operating and development costs; and any agreements relating to current and future operations of the properties and sales of production. However, if in the course of their evaluation something came to their attention which brought into question the validity or sufficiency of any such information or data, NSAI did not rely on such information or data until they had satisfactorily resolved their questions relating thereto or had independently verified such information or data. NSAI issued an unqualified audit opinion on the Company’s proved reserves based upon their evaluation. | ||||
| 5. | We note your statement here that the standardized measure is calculated with oil and gas spot prices “prevailing as of the date of computation”. This seems contradictory to the use of year-end prices and costs in the estimation of proved reserves and the computation of the standardized measure as required by Financial Accounting Standard 69. Please affirm to us that you have complied with this requirement. | |||
| Response:The Company confirms that the Standardized Measure of Discounted Future Net Cash Flows associated with proved oil and gas reserves as disclosed within the Company’s 2004 Form 10-K have been calculated using year-end prices and costs in accordance with Statement of Financial Accounting Standards No. 69. | ||||
H. Roger Schwall
Securities and Exchange Commission
Page 5
April 27, 2005
Proved Reserves, page 15
| 6. | Here and elsewhere, your disclosed U.S. proved reserves comprise ~ 84% of your total worldwide reserves. In part, Instruction 3 to Item 102 of Regulation S-K requires “In the case of an extractive enterprise,material information shall be given as to production, reserves, locations, development and the nature of the registrant’s interest. If individual properties are ofmajor significance to an industry segment: A. More detailed information concerning these matters shall be furnished.’ Disclose - as a minimum - the annual production, proved developed and total proved oil and gas reserves for each of your major U.S. properties. | |||
| Response:As is disclosed in “Item 2. — Properties” of the Company’s 2004 Form 10-K, the Company has operations in oil and gas fields that are individually significant to its operations in the U.S. The Company will enhance its discussions and disclosures of its domestic oil and gas properties in Item 2. of its future Form 10-Ks to include either a table presenting the annual production, proved developed and total proved oil and gas reserves for each of its significant areas or include this information within the individual discussion surrounding each significant area. | ||||
Argentine commodity prices, page 38
| 7. | Supplementally, illustrate to us how you incorporated the Argentine export tax into your year-end 2004 proved reserves and standardized measure. | |||
| Response:In January 2002, the Argentine government enacted the “Public Emergency Law” which imposed a 20 percent retention tax on oil exports for the following five years. In August 2004, the fixed tax rate on oil exports was changed to a variable rate for varying West Texas Intermediate (“WTI”) prices. The enactment of the oil export tax also had the intended government impact of causing domestic Argentine oil prices to decline such that domestic Argentine oil prices remain at parity with or approximately equal to net export prices. | ||||
| In the Company’s December 31, 2004 reserve report, the Company did not model the export tax directly as determined by the “Public Emergency Law” because Pioneer is not a crude exporter. However, the Company modeled equivalent export parity prices based on negotiated prices between local refiners and producers (as per the Company’s active contract prices with refiners at that date). In the Company’s December 31, 2004 reserve report, the Company assumed that export parity remains in place for the remaining term of the “Public Emergency Law”. This has the effect of limiting the realized price for crude sales during 2005 and 2006 to approximately $32 per barrel based on the year-end WTI oil price of $43.33 per barrel. Beginning in 2007, the Company assumed the law would expire and Argentine realized oil prices would return to their normal quality differentials from quoted WTI prices without an export parity deduction. | ||||
| Similar to the oil export tax, the impact of the export tax on liquid petroleum gas is included in the December 31, 2004 reserve report through the term of the Public Emergency Law. The Company currently does not have any gas sales subject to the Public Emergency Law. | ||||
Production costs, page 40
| 8. | Supplementally, tell us how oil and gas transportation costs are incorporated in your historical and projected - in your proved reserve estimates and standardized measure - production costs and/or period end product prices. Be advised that in our view, transportation costs should be reflected in either the prices you realize or the costs you incur. |
H. Roger Schwall
Securities and Exchange Commission
Page 6
April 27, 2005
| Response:For both historical and projected transportation costs, all transportation costs incurred prior to custody transfer to the purchaser are reflected in lease operating expense. Any transportation costs post custody transfer are netted out of the revenue streams by the purchasers and therefore are reflected in the realized price reported by the Company. |
Reserve Quantity Information, page 107
| 9. | Rule 4-10(a)(4) of Regulation S-X provides that proved undeveloped oil and gas reserves may be attributed to locations not offsetting productive units only “where it can be demonstrated withcertainty that there iscontinuity of production for the existing productive formation (emphasis added).” Supplementally, submit to us the engineering and geologic justification for any PUD reserves you have claimed which are not in legal, technically justified locations offsetting (adjacent to) productive wells. Otherwise, either affirm to us that none of your claimed PUD reserves are attributed to such locations or delete such volumes from your disclosed proved reserves. | |||
| Response:The Company has seven proved undeveloped (“PUD”) reserve locations not offsetting productive locations in its Raton Basin CBM field. At December 31, 2004, Pioneer claimed PUD reserves totaling 4.9 billion cubic feet (“Bcf”) for seven locations on four quarter sections (640 acres) in the Raton and/or Vermejo coal formations that are not directly offset to proved developed producing locations. | ||||
| With over 1,250 producing wells making about 187 million cubic feet per day across more than 200,000 acres, we have been able to demonstrate continuity of the coal packages across a very large area, as well as hydrologic communication on a macro-scale level by mapping the potentiometric surface. We have not cored any wells which did not have gas, so we are confident that these areas will have adequate GIP to be commercially productive based on potentiometric surface mapping. In the case of these seven non-offsetting PUDs, the areas are all “windows” within the existing field which have not yet been developed. Based upon above, the Company believes that these PUD locations are appropriately reflected in its proved reserves. | ||||
| 10. | We note the 2004 reserve review and revisions that you describe in Exhibit I of your supplemental response. Supplementally, explain why you did not apply similar revisions to the Harrier reserves. | |||
| Response:Similar revisions were not applied to Harrier reserves because prior to the well unexpectedly watering out in September 2004, the well had cumulative gas production of 26 Bcf and material balance and reservoir simulation supported the initial booked recoverable reserves of 60 Bcf. A sealing fault, which was thought to be non-sealing in the original reserve booking analysis, prevented originally assigned reserves from being recovered. A sidetrack well was drilled and tested in the third quarter of 2004 to access an adjacent fault block and encountered over 400 feet of gas-bearing sand and was initially assigned 12 Bcf of proved reserves at December 31, 2004, resulting in a net 22 Bcf negative reserve revision during the second half of 2004. Since December 31, 2004, the well has produced over 15 Bcf and continues to produce. | ||||
| 11. | Remove from your proved reserves, any quantities you have claimed that are: | |||
| a) | In undrilled fault blocks; |
| b) | Below the lowest known - penetrated and assessed - structural occurrence of hydrocarbons. |
| Response:At December 31, 2004, Pioneer believed that it did not have any reserves booked in undrilled fault blocks. Also, the Company believed that there were no reserves claimed below the lowest known - penetrated and assessed - structural occurrence of hydrocarbons which did not have |
H. Roger Schwall
Securities and Exchange Commission
Page 7
April 27, 2005
| qualified technical data, including performance data, to support the reserves assigned. Subsequent to year-end, the Company received updated geotechnical analysis, production data and additional technical support from working interest partners which indicated that two Aconcagua proved undeveloped locations were in undrilled fault blocks. Consequently, the Company removed 12.6 Bcf associated with these PUDs in its March 31, 2005 reserve report. |
| 12. | Our review of your supplemental Exhibit A indicates that you may have included helium in your disclosed proved reserve estimates and associated standardized measure. Paragraphs 10 and 30 of Financial Accounting Standard 69 prescribe that only hydrocarbon volumes and their estimated future revenues be disclosed. Remove from your proved reserves any such helium volumes. | |||
| Response:Helium volumes were not included in the Company’s December 31, 2004 proved reserves or associated Standardized Measure of Discounted Future Net Cash Flows of proved reserves. | ||||
Standardized Measure of Discounted Future Net Cash Flows, page 109
| 13. | We note your footnote (a) reference to asset retirement obligations (ARO) here. Address whether your proved undeveloped reserve estimates include consideration of AROon an individual property basis. Be advised we object to the attribution of proved undeveloped reserves to individual properties whose future estimated production and development costs -including asset retirement obligations - result in negative estimated future net income. Remove any such volumes that do not meet this requirement. | |||
| Response:As of December 31, 2004, the Company had not individually allocated asset retirement obligations to some of its proved undeveloped properties. However, the Company has since reviewed the individual proved undeveloped properties including their associated asset retirement obligations and has no instances where the inclusion of such asset retirement obligations resulted in negative estimated future net cash flows attributable to any of its proved undeveloped reserves. In the future, asset retirement obligations will be included on an individual undeveloped property basis to ensure that proved reserves are not attributed to any undeveloped locations that have negative estimated future net income. | ||||
Please direct any questions in connection with the responses set forth in this letter to Richard P. Dealy at 972-969-4054 (direct fax 972-969-3572).
| Very truly yours, | ||||
| /s/ Richard P. Dealy | ||||
| Richard P. Dealy Executive Vice President and Chief Financial Officer | ||||
| Cc: | Darin G. Holderness | |||
| Kerry D. Scott |
