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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 of major 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
with certainty that there is continuity of production for the existing
productive formation (emphasis added).” Supplementally, submit to us the engineering and
geologic justificati