PIONEER NATURAL RESOURCES CO - 10-K Annual Report

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

/ X / ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2004

or

/ / TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from _______ to ________

Commission File Number: 1-13245

Pioneer Natural Resources Company
------------------------------------------------------
(Exact name of registrant as specified in its charter)

Delaware 75-2702753
------------------------------------------- -------------------
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)

5205 N. O'Connor Blvd., Suite 900, Irving, Texas 75039
- ------------------------------------------------ ----------
(Address of principal executive offices) (Zip Code)

Registrant's telephone number, including area code: (972) 444-9001

Securities registered pursuant to Section 12(b) of the Act:

Name of each exchange
Title of each class on which registered
------------------- -----------------------

Common Stock................................... New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark whether the Registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the Registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
YES X NO
--- ---

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of Registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ ]

Indicate by check mark whether the Registrant is an accelerated filer (as
defined in Rule 12b-2 of the Act).
YES X NO
--- ---

Aggregate market value of the voting common equity held by
non-affiliates of the Registrant computed by reference to
the price at which the common equity was last sold as of
the last business day of the Registrant's most recently
completed second fiscal quarter ............................... $4,174,193,054

Number of shares of Common Stock outstanding as of
February 17, 2005.............................................. 143,669,263

Documents Incorporated by Reference:

(1) Proxy Statement for Annual Meeting of Shareholders to be held May 12, 2005
- Referenced in Part III of this report.

TABLE OF CONTENTS

Page

Definitions of Oil and Gas Terms and Conventions Used Herein............. 4

PART I

Item 1. Business................................................. 5

General.................................................. 5
Available Information.................................... 5
Evergreen Merger......................................... 5
Mission and Strategies................................... 5
Business Activities...................................... 6
Operations by Geographic Area............................ 8
Marketing of Production.................................. 8
Competition, Markets and Regulations..................... 9
Risks Associated with Business Activities................ 11

Item 2. Properties............................................... 14

Proved Reserves.......................................... 14
Description of Properties................................ 15
Selected Oil and Gas Information......................... 21

Item 3. Legal Proceedings........................................ 25

Item 4. Submission of Matters to a Vote of Security Holders...... 25

PART II

Item 5. Market for Registrant's Common Stock, Related
Stockholder Matters and Issuer Purchases of Equity
Securities............................................... 25

Securities Authorized for Issuance under Equity
Compensation Plans....................................... 26
Purchases of Equity Securities by the Issuer and
Affiliated Purchasers.................................... 27

Item 6. Selected Financial Data.................................. 28

Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations...................... 29

2004 Highlights and Events............................... 29
2004 Financial and Operating Performance................. 30
Evergreen Merger......................................... 30
2005 Outlook and Activities.............................. 30
Field Fuel Reporting..................................... 33
Critical Accounting Estimates............................ 33
Results of Operations.................................... 35
Capital Commitments, Capital Resources and Liquidity..... 43
New Accounting Pronouncement............................. 46

2

TABLE OF CONTENTS (CONT.)

Page

Item 7A. Quantitative and Qualitative Disclosures About
Market Risk............................................... 47

Quantitative Disclosures.................................. 48
Qualitative Disclosures................................... 52

Item 8. Financial Statements and Supplementary Data............... 55

Index to Consolidated Financial Statements................ 55
Report of Independent Registered Public Accounting Firm... 56
Consolidated Financial Statements......................... 57
Notes to Consolidated Financial Statements................ 62
Unaudited Supplementary Information....................... 105

Item 9. Changes in and Disagreements With Accountants on
Accounting and Financial Disclosure....................... 112

Item 9A. Controls and Procedures................................... 112

Item 9B. Other Information......................................... 114

PART III

Item 10. Directors and Executive Officers of the Registrant........ 114

Item 11. Executive Compensation.................................... 114

Item 12. Security Ownership of Certain Beneficial Owners
and Management............................................ 114

Item 13. Certain Relationships and Related Transactions............ 114

Item 14. Principal Accountant Fees and Services.................... 114

PART IV

Item 15. Exhibits, Financial Statement Schedules................... 115

Signatures................................................ 121

Exhibit Index............................................. 122

Cautionary Statement Concerning Forward-Looking Statements

Parts I and II of this annual report on Form 10-K (the "Report") contain
forward-looking statements that involve risks and uncertainties. Accordingly, no
assurances can be given that the actual events and results will not be
materially different than the anticipated results described in the forward
looking statements. See "Item 1. Business - Competition, Markets and
Regulations" and "Item 1. Business - Risks Associated with Business Activities"
for a description of various factors that could materially affect the ability of
Pioneer Natural Resources Company to achieve the anticipated results described
in the forward-looking statements.

3

Definitions of Oil and Gas Terms and Conventions Used Herein

Within this Report, the following oil and gas terms and conventions have
specific meanings:

o "Bbl" means a standard barrel containing 42 United States gallons.
o "Bcf" means one billion cubic feet.
o "BOE" means a barrel of oil equivalent and is a standard convention
used to express oil and gas volumes on a comparable oil equivalent
basis. Gas equivalents are determined under the relative energy
content method by using the ratio of 6.0 Mcf of gas to 1.0 Bbl of oil
or NGL.
o "Btu" means British thermal unit and is a measure of the amount of
energy required to raise the temperature of one pound of water one
degree Fahrenheit.
o "GAAP" means accounting principles that are generally accepted in the
United States.
o "LIBOR" means London Interbank Offered Rate, which is a market rate of
interest.
o "MBbl" means one thousand Bbls.
o "MBOE" means one thousand BOEs.
o "MMBOE" means one million BOEs.
o "Mcf" means one thousand cubic feet and is a measure of natural gas
volume.
o "MMBtu" means one million Btus.
o "MMcf" means one million cubic feet.
o "NGL" means natural gas liquid.
o "NYMEX" means The New York Mercantile Exchange.
o "NYSE" means The New York Stock Exchange.
o "Pioneer" or the "Company" means Pioneer Natural Resources Company and
its subsidiaries.
o "Proved reserves" mean the estimated quantities of crude oil, natural
gas, and natural gas liquids which geological and engineering data
demonstrate with reasonable certainty to be recoverable in future
years from known reservoirs under existing economic and operating
conditions, i.e., prices and costs as of the date the estimate is
made. Prices include consideration of changes in existing prices
provided only by contractual arrangements, but not on escalations
based upon future conditions.
(i) Reservoirs are considered proved if economic producibility
is supported by either actual production or conclusive formation
test. The area of a reservoir considered proved includes (A) that
portion delineated by drilling and defined by gas-oil and/or
oil-water contacts, if any; and (B) the immediately adjoining
portions not yet drilled, but which can be reasonably judged as
economically productive on the basis of available geological and
engineering data. In the absence of information on fluid contacts,
the lowest known structural occurrence of hydrocarbons controls the
lower proved limit of the reservoir.
(ii) Reserves which can be produced economically through
application of improved recovery techniques (such as fluid injection)
are included in the "proved" classification when successful testing
by a pilot project, or the operation of an installed program in the
reservoir, provides support for the engineering analysis on which the
project or program was based.
(iii) Estimates of proved reserves do not include the following:
(A) oil that may become available from known reservoirs but is
classified separately as "indicated additional reserves"; (B) crude
oil, natural gas, and natural gas liquids, the recovery of which is
subject to reasonable doubt because of uncertainty as to geology,
reservoir characteristics, or economic factors; (C) crude oil,
natural gas, and natural gas liquids, that may occur in undrilled
prospects; and (D) crude oil, natural gas, and natural gas liquids,
that may be recovered from oil shales, coal, gilsonite and other such
sources.
o "SEC" means the United States Securities and Exchange Commission.
o "Standardized Measure" means the after-tax present value of estimated
future net revenues of proved reserves, determined in accordance with
the rules and regulations of the SEC, using prices and costs in
effect at the specified date and a 10 percent discount rate.
o With respect to information on the working interest in wells,
drilling locations and acreage, "net" wells, drilling locations and
acres are determined by multiplying "gross" wells, drilling locations
and acres by the Company's working interest in such wells, drilling
locations or acres. Unless otherwise specified, wells, drilling
locations and acreage statistics quoted herein represent gross wells,
drilling locations or acres.
o Unless otherwise indicated, all currency amounts are expressed in
U.S. dollars.

4

PART I

ITEM 1. BUSINESS

General

Pioneer is a Delaware corporation whose common stock is listed and traded
on the NYSE. The Company is a large independent oil and gas exploration and
production company with operations in the United States, Argentina, Canada,
Equatorial Guinea, Gabon, South Africa and Tunisia.

The Company's executive offices are located at 5205 N. O'Connor Blvd.,
Suite 900, Irving, Texas 75039. The Company's telephone number is (972)
444-9001. The Company maintains other offices in Anchorage, Alaska; Denver,
Colorado; Midland, Texas; Buenos Aires, Argentina; Calgary, Canada; Libreville,
Gabon; Capetown, South Africa and Tunis, Tunisia. At December 31, 2004, the
Company had 1,550 employees, 889 of whom were employed in field and plant
operations.

Available Information

Pioneer files annual, quarterly and current reports, proxy statements and
other documents with the SEC under the Securities Exchange Act of 1934. The
public may read and copy any materials that Pioneer files with the SEC at the
SEC's Public Reference Room at 450 Fifth Street, N.W., Washington, D.C. 20549.
The public may obtain information on the operation of the Public Reference Room
by calling the SEC at 1-800-SEC-0330. Also, the SEC maintains an Internet
website that contains reports, proxy and information statements, and other
information regarding issuers, including Pioneer, that file electronically with
the SEC. The public can obtain any documents that Pioneer files with the SEC at
http://www.sec.gov.

The Company also makes available free of charge on or through its internet
website (www.pioneernrc.com) its Annual Report on Form 10-K, Quarterly Reports
on Form 10-Q, Current Reports on Form 8-K and, if applicable, amendments to
those reports filed or furnished pursuant to Section 13(a) of the Exchange Act
as soon as reasonably practicable after it electronically files such material
with, or furnishes it to, the SEC.

Evergreen Merger

On September 28, 2004, Pioneer completed its merger with Evergreen
Resources, Inc. ("Evergreen"). Pioneer acquired the common stock of Evergreen
for a total purchase price of approximately $1.8 billion, which was comprised of
cash and Pioneer common stock. At the merger date, Evergreen's proved reserves
were 262.2 MMBOE. Evergreen was a publicly-traded independent oil and gas
company primarily engaged in the production, development, exploration and
acquisition of North American unconventional natural gas. Evergreen was based in
Denver, Colorado and was one of the leading developers of coal bed methane
reserves in the United States. Evergreen's operations were principally focused
on developing and expanding its coal bed methane field located in the Raton
Basin in southern Colorado. Evergreen also had operations in the Piceance Basin
in western Colorado, the Uinta Basin in eastern Utah and the Western Canada
Sedimentary Basin. See Note C of Notes to Consolidated Financial Statements
included in "Item 8. Financial Statements and Supplementary Data" for more
information regarding the Evergreen merger.

Mission and Strategies

The Company's mission is to provide shareholders with superior investment
returns through strategies that maximize Pioneer's long-term profitability and
net asset value. The strategies employed to achieve this mission are predicated
on maintaining financial flexibility and capital allocation discipline.
Historically, these strategies have been anchored by the Company's long-lived
Spraberry oil field and Hugoton and West Panhandle gas fields' reserves and
production. Since the fourth quarter of 2004, the strategy is also enhanced by
the newly acquired Raton gas field. Underlying these fields are approximately 75
percent of the Company's proved oil and gas reserves as of December 31, 2004.
These fields have a remaining productive life in excess of 40 years. The stable
base of oil and gas production from these fields, combined with the deepwater
Gulf of Mexico Canyon Express, Falcon area and Devils Tower projects which began
production in September 2002, March 2003 and May 2004, respectively, and the

5

Sable oil discovery in South Africa which began production in August 2003,
should generate the operating cash flows to fund the Company's $900 million to
$950 million capital budget for 2005 and allow the Company to further enhance
its financial flexibility during 2005.

During 2004, the Company utilized capital from its long-lived Spraberry,
Hugoton and West Panhandle fields and shorter-lived deepwater Gulf of Mexico
projects to partially fund the merger with Evergreen and to selectively reinvest
in assets that the Company believes will offer superior investment returns.
Similarly, during 2005, the Company will continue to: (i) selectively explore
for and develop proved reserve discoveries in areas that it believes will offer
superior reserve growth and profitability potential; (ii) evaluate opportunities
to acquire oil and gas properties under terms that will complement the Company's
exploration and development drilling activities; (iii) invest in the personnel
and technology necessary to maximize the Company's exploration and development
successes; and (iv) enhance liquidity, allowing the Company to take advantage of
future exploration, development and acquisition opportunities. The Company is
committed to continuing to enhance shareholder investment returns through
adherence to these strategies.

Business Activities

The Company is an independent oil and gas exploration and production
company. Pioneer's purpose is to competitively and profitably explore for,
develop and produce oil, NGL and gas reserves. In so doing, the Company sells
homogenous oil, NGL and gas units which, except for geographic and relatively
minor qualitative differentials, cannot be significantly differentiated from
units offered for sale by the Company's competitors. Competitive advantage is
gained in the oil and gas exploration and development industry through superior
capital investment decisions, technological innovation and price and cost
management.

Petroleum industry. The petroleum industry has generally been characterized
by rising oil, NGL and gas commodity prices during 2004 and recent years. During
2004, the Company has also been affected by increasing costs, particularly the
cost of steel and higher drilling and well servicing rig rates. World oil prices
have increased in response to political unrest and supply disruptions in Iraq
and Venezuela while North American gas prices have improved as supply and demand
fundamentals have strengthened. Significant factors that will impact 2005
commodity prices include the final resolution of issues currently impacting Iraq
and the Middle East in general, the extent to which members of the Organization
of Petroleum Exporting Countries ("OPEC") and other oil exporting nations are
able to continue to manage oil supply through export quotas and overall North
American gas supply and demand fundamentals. To mitigate the impact of commodity
price volatility on the Company's net asset value, Pioneer utilizes commodity
hedge contracts. See "Item 7A. Quantitative and Qualitative Disclosures About
Market Risk" and Note K of Notes to Consolidated Financial Statements included
in "Item 8. Financial Statements and Supplementary Data" for information
regarding the impact to oil and gas revenues during the years ended December 31,
2004, 2003 and 2002 from the Company's hedging activities and the Company's open
hedge positions at December 31, 2004.

The Company. The Company's asset base is anchored by the Spraberry oil
field located in West Texas, the Hugoton gas field located in Southwest Kansas,
the Raton gas field located in southern Colorado and the West Panhandle gas
field located in the Texas Panhandle. Complementing these areas, the Company has
exploration and development opportunities and/or oil and gas production
activities in the Gulf of Mexico, the onshore Gulf Coast area and in Alaska, and
internationally in Argentina, Canada, Equatorial Guinea, Gabon, South Africa and
Tunisia. Combined, these assets create a portfolio of resources and
opportunities that are well balanced among oil, NGLs and gas, and that are also
well balanced between long-lived, dependable production and exploration and
development opportunities. Additionally, the Company has a team of dedicated
employees that represent the professional disciplines and sciences that will
allow Pioneer to maximize the long-term profitability and net asset value
inherent in its physical assets.

The Company provides administrative, financial and management support to
United States and foreign subsidiaries that explore for, develop and produce
oil, NGL and gas reserves. Production operations are principally located
domestically in Texas, Kansas, Colorado, Louisiana and the Gulf of Mexico, and
internationally in Argentina, Canada, South Africa and Tunisia.

Production. The Company focuses its efforts towards maximizing its average
daily production of oil, NGLs and gas through development drilling, production
enhancement activities and acquisitions of producing properties while minimizing
the controllable costs associated with the production activities. During the

6

year ended December 31, 2004, the Company's average daily production, on a BOE
basis, increased as a result of (i) gas production beginning in January 2004
from the Company's Harrier gas field in the deepwater Gulf of Mexico, (ii) oil
production beginning in May 2004 from the Company's Devils Tower oil field in
the deepwater Gulf of Mexico, (iii) gas production beginning in June 2004 from
the Company's Raptor and Tomahawk gas fields in the deepwater Gulf of Mexico,
(iv) a full year of gas production from the Company's Falcon field in the
deepwater Gulf of Mexico, (v) a full year of oil production from the Company's
Adam field in Tunisia, (vi) a full year of oil production from the Company's
Sable field offshore South Africa, (vii) increased production from Argentina and
(viii) fourth quarter production from the properties added in the Evergreen
merger. These increases more than offset normal production declines. During the
year ended December 31, 2003, the Company's average daily oil, NGL and gas
production increased as a result of (i) a full year of gas production from the
Company's Canyon Express gas project in the deepwater Gulf of Mexico, (ii) gas
production beginning in March 2003 from the Company's Falcon gas field in the
deepwater Gulf of Mexico, (iii) increased production from Argentina primarily
resulting from the resumption of oil drilling activities in the third quarter of
2002, (iv) oil production beginning in May 2003 from the Company's Adam field in
Tunisia and (v) oil production beginning in August 2003 from the Company's Sable
field offshore South Africa. These increases more than offset normal production
declines. During 2002, the Company's average daily oil, NGL and gas production
decreased primarily due to normal production declines, reduced Argentine demand
for gas, the Company's curtailment of Argentine drilling activities during the
first half of 2002 and the December 2001 sale of the Company's Rycroft/Spirit
River field in Canada. Production, price and cost information with respect to
the Company's properties for each of the years ended December 31, 2004, 2003 and
2002 is set forth under "Item 2. Properties - Selected Oil and Gas Information -
Production, Price and Cost Data".

Drilling activities. The Company seeks to increase its oil and gas
reserves, production and cash flow through exploratory and development drilling
and by conducting other production enhancement activities, such as well
recompletions. During the three years ended December 31, 2004, the Company
drilled 1,035 gross (876.8 net) wells, 87 percent of which were successfully
completed as productive wells, at a total drilling cost (net to the Company's
interest) of $1.6 billion. During 2004, the Company drilled 423 gross (384.8
net) wells. The Company's current 2005 capital expenditure budget is expected to
range from $900 million to $950 million. The Company has allocated the budgeted
2005 capital expenditures as follows: approximately 75 percent to development
drilling and facility activities and the balance of approximately 25 percent to
exploration activities.

The Company believes that its current property base provides a substantial
inventory of prospects for future reserve, production and cash flow growth. The
Company's proved reserves as of December 31, 2004 include proved undeveloped
reserves and proved developed reserves that are behind pipe of 161.1 MMBOE of
oil and NGLs and 1,356.6 Bcf of gas. Development of these proved reserves will
require future capital expenditures. The timing of the development of these
reserves will be dependent upon the commodity price environment, the Company's
expected operating cash flows and the Company's financial condition. The Company
believes that its current portfolio of proved reserves and unproved prospects
provides attractive development and exploration opportunities for at least the
next three to five years.

Exploratory activities. The Company has devoted significant efforts and
resources to hiring and developing a highly skilled exploration staff as well as
acquiring and drilling a portfolio of exploration opportunities. The Company's
commitment to exploration has resulted in significant discoveries, such as the
1998 Sable oil field discovery in South Africa; the 1999 Aconcagua, 2000 Devils
Tower, 2001 Falcon and 2003 Harrier, Tomahawk and Raptor discoveries in the
deepwater Gulf of Mexico; and the 2002 Borj El Khadra permit discovery in the
Ghadames basin onshore Southern Tunisia. The Company currently anticipates that
its 2005 exploration efforts will be approximately 25 percent of total 2005
capital expenditures and will be concentrated domestically in the Gulf of Mexico
and Alaska, and internationally in Africa, Argentina and Canada. Exploratory
drilling involves greater risks of dry holes or failure to find commercial
quantities of hydrocarbons than development drilling or enhanced recovery
activities. See "Item 1. Business - Risks Associated with Business Activities -
Drilling activities" below.

Acquisition activities. The Company regularly seeks to acquire properties
that complement its operations, provide exploration and development
opportunities and potentially provide superior returns on investment. In
addition, the Company pursues strategic acquisitions that will allow the Company
to expand into new geographical areas that feature producing properties and
provide exploration/exploitation opportunities. During the years ended December
31, 2004, 2003 and 2002, the Company expended $2.6 billion (including $2.5
billion associated with the Evergreen merger), $151.0 million and $195.5
million, respectively, of acquisition capital to purchase proved oil and gas

7

properties, including additional interests in its existing assets, and to
acquire new prospects for future exploitation and exploration activities. See
Note C of Notes to Consolidated Financial Statements included in "Item 8.
Financial Statements and Supplementary Data" for a description of the Company's
acquisitions during 2004, 2003 and 2002.

The Company periodically evaluates and pursues acquisition opportunities
(including opportunities to acquire particular oil and gas properties or related
assets; entities owning oil and gas properties or related assets; and
opportunities to engage in mergers, consolidations or other business
combinations with such entities) and at any given time may be in various stages
of evaluating such opportunities. Such stages may take the form of internal
financial analysis, oil and gas reserve analysis, due diligence, the submission
of an indication of interest, preliminary negotiations, negotiation of a letter
of intent or negotiation of a definitive agreement.

Asset divestitures. The Company regularly reviews its asset base for the
purpose of identifying non-strategic assets, the disposition of which would
increase capital resources available for other activities and create
organizational and operational efficiencies. While the Company generally does
not dispose of assets solely for the purpose of reducing debt, such dispositions
can have the result of furthering the Company's objective of increasing
financial flexibility through reduced debt levels.

During the years ended December 31, 2004, 2003 and 2002, the Company's
divestitures consisted of the early termination of derivative hedge contracts
and the sales of oil and gas properties and other assets for net proceeds of
$1.7 million, $35.7 million and $118.9 million, respectively, which resulted in
net divestiture gains of $39 thousand, $1.3 million and $4.4 million,
respectively. The net cash proceeds were primarily used to fund additions to oil
and gas properties or to reduce the Company's outstanding indebtedness. See Note
O of Notes to Consolidated Financial Statements included in "Item 8. Financial
Statements and Supplementary Data" for specific information regarding the
Company's asset divestitures.

The Company anticipates that it will continue to sell non-strategic
properties or other assets from time to time to increase capital resources
available for other activities, to achieve operating and administrative
efficiencies and to improve profitability.

Operations by Geographic Area

The Company operates in one industry segment. During the three years ended
December 31, 2004, the Company had oil and gas producing and development
activities in the United States, Argentina, Canada, South Africa and Tunisia,
and had exploration activities in the United States, Argentina, Canada,
Equatorial Guinea, Gabon, South Africa and Tunisia. See Note S of Notes to
Consolidated Financial Statements included in "Item 8. Financial Statements and
Supplementary Data" for geographic operating segment information, including
results of operations and segment assets.

Marketing of Production

General. Production from the Company's properties is marketed using methods
that are consistent with industry practices. Sales prices for oil, NGL and gas
production are negotiated based on factors normally considered in the industry,
such as the index or spot price for gas or the posted price for oil, price
regulations, distance from the well to the pipeline, well pressure, estimated
reserves, commodity quality and prevailing supply conditions. In Argentina, the
Company receives significantly lower prices for its production as a result of
the Argentine government's imposed price limitations. See "Qualitative
Disclosures" in "Item 7A. Quantitative and Qualitative Disclosures About Market
Risk" for additional discussion of Argentine foreign currency, operations and
price risk.

Significant purchasers. During the year ended December 31, 2004, the
Company's primary purchasers of oil, NGLs and gas were Williams Power Company,
Inc. (12 percent), Occidental Energy Marketing, Inc. (six percent),
ConocoPhillips (six percent), Enterprise Products Operating L.P. (five percent)
and Plains Marketing LP (four percent). The Company is of the opinion that the
loss of any one purchaser would not have an adverse effect on its ability to
sell its oil, NGL and gas production.

Hedging activities. The Company utilizes commodity derivative contracts in
order to (i) reduce the effect of price volatility on the commodities the
Company produces and sells, (ii) support the Company's annual capital budgeting

8

and expenditure plans and (iii) reduce commodity price risk associated with
certain capital projects. See "Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations" for a description of the
Company's hedging activities, "Item 7A. Quantitative and Qualitative Disclosures
About Market Risk" and Note K of Notes to Consolidated Financial Statements
included in "Item 8. Financial Statements and Supplementary Data" for
information concerning the impact on oil and gas revenues during the years ended
December 31, 2004, 2003 and 2002 from the Company's commodity hedging activities
and the Company's open commodity hedge positions at December 31, 2004.

Competition, Markets and Regulations

Competition. The oil and gas industry is highly competitive. A large number
of companies and individuals engage in the exploration for and development of
oil and gas properties, and there is a high degree of competition for oil and
gas properties suitable for development or exploration. Acquisitions of oil and
gas properties have been an important element of the Company's growth. The
Company intends to continue to acquire oil and gas properties that complement
its operations, provide exploration and development opportunities and
potentially provide superior returns on investment. The principal competitive
factors in the acquisition of oil and gas properties include the staff and data
necessary to identify, investigate and purchase such properties and the
financial resources necessary to acquire and develop the properties. Many of the
Company's competitors are substantially larger and have financial and other
resources greater than those of the Company.

Markets. The Company's ability to produce and market oil, NGLs and gas
profitably depends on numerous factors beyond the Company's control. The effect
of these factors cannot be accurately predicted or anticipated. Although the
Company cannot predict the occurrence of events that may affect these commodity
prices or the degree to which these prices will be affected, the prices for any
commodity that the Company produces will generally approximate current market
prices in the geographic region of the production.

Governmental regulations. Enterprises that sell securities in public
markets are subject to regulatory oversight by agencies such as the SEC. This
regulatory oversight imposes on the Company the responsibility for establishing
and maintaining disclosure controls and procedures that will ensure that
material information relating to the Company and its consolidated subsidiaries
is made known to the Company's management and that the financial statements and
other financial information included in this Report do not contain any untrue
statement of a material fact, or omit to state a material fact, necessary to
make the statements made in this Report not misleading.

Oil and gas exploration and production operations are also subject to
various types of regulation by local, state, federal and foreign agencies.
Additionally, the Company's operations are subject to state conservation laws
and regulations, including provisions for the unitization or pooling of oil and
gas properties, the establishment of maximum rates of production from wells and
the regulation of spacing, plugging and abandonment of wells. States and foreign
governments generally impose a production or severance tax with respect to
production and sale of oil and gas within their respective jurisdictions. The
regulatory burden on the oil and gas industry increases the Company's cost of
doing business and, consequently, affects its profitability.

Additional proposals and proceedings that might affect the oil and gas
industry are considered from time to time by Congress, the Federal Energy
Regulatory Commission, state regulatory bodies, the courts and foreign
governments. The Company cannot predict when or if any such proposals might
become effective or their effect, if any, on the Company's operations.

Environmental and health controls. The Company's operations are subject to
numerous federal, state, local and foreign laws and regulations relating to
environmental and health protection. These laws and regulations may require the
acquisition of a permit before drilling commences, restrict the type, quantities
and concentration of various substances that can be released into the
environment in connection with drilling and production activities, limit or
prohibit drilling activities on certain lands lying within wilderness, wetlands
and other protected areas and impose substantial liabilities for pollution
resulting from oil and gas operations. These laws and regulations may also
restrict air emissions or other discharges resulting from the operation of gas
processing plants, pipeline systems and other facilities that the Company owns.
Although the Company believes that compliance with environmental laws and
regulations will not have a material adverse effect on its future results of
operations or financial condition, risks of substantial costs and liabilities

9

are inherent in oil and gas operations, and there can be no assurance that
significant costs and liabilities, including potential criminal penalties, will
not be incurred. Moreover, it is possible that other developments, such as
stricter environmental laws and regulations or claims for damages to property or
persons resulting from the Company's operations, could result in substantial
costs and liabilities.

The Comprehensive Environmental Response, Compensation, and Liability Act
("CERCLA"), also known as the "Superfund" law, imposes liability, without regard
to fault or the legality of the original conduct, on certain classes of persons
with respect to the release of a "hazardous substance" into the environment.
These persons include the owner or operator of the disposal site or sites where
the release occurred and companies that disposed or arranged for the disposal of
hazardous substances released at the site. Persons who are or were responsible
for releases of hazardous substances under CERCLA may be subject to joint and
several liability for the costs of cleaning up the hazardous substances that
have been released into the environment and for damages to natural resources,
and it is not uncommon for neighboring landowners and other third parties to
file claims for personal injury and property damage allegedly caused by the
hazardous substances released into the environment.

The Company generates wastes, including hazardous wastes, that are subject
to the federal Resource Conservation and Recovery Act ("RCRA") and comparable
state statutes. The United States Environmental Protection Agency and various
state agencies have limited the approved methods of disposal for certain
hazardous and non-hazardous wastes. Furthermore, certain wastes generated by the
Company's oil and gas operations that are currently exempt from treatment as
hazardous wastes may in the future be designated as hazardous wastes, and
therefore be subject to more rigorous and costly operating and disposal
requirements.

The Company currently owns or leases, and has in the past owned or leased,
properties that for many years have been used for the exploration and production
of oil and gas reserves. Although the Company has used operating and disposal
practices that were standard in the industry at the time, hydrocarbons or other
wastes may have been disposed of or released on or under the properties owned or
leased by the Company or on or under other locations where such wastes have been
taken for disposal. In addition, some of these properties have been operated by
third parties whose treatment and disposal or release of hydrocarbons or other
wastes was not under the Company's control. These properties and the wastes
disposed thereon may be subject to CERCLA, RCRA and analogous state and foreign
laws. Under such laws, the Company could be required to remove or remediate
previously disposed wastes or property contamination or to perform remedial
plugging operations to prevent future contamination.

Federal regulations require certain owners or operators of facilities that
store or otherwise handle oil, such as the Company, to prepare and implement
spill prevention control plans, countermeasure plans and facility response plans
relating to the possible discharge of oil into surface waters. The Oil Pollution
Act of 1990 ("OPA") amends certain provisions of the federal Water Pollution
Control Act of 1972, commonly referred to as the Clean Water Act ("CWA"), and
other statutes as they pertain to the prevention of and response to oil spills
into navigable waters. The OPA subjects owners of facilities to strict joint and
several liability for all containment and cleanup costs and certain other
damages arising from a spill, including, but not limited to, the costs of
responding to a release of oil to surface waters. The CWA provides penalties for
any discharges of petroleum products in reportable quantities and imposes
substantial liability for the costs of removing a spill. OPA requires
responsible parties to establish and maintain evidence of financial
responsibility to cover removal costs and damages resulting from an oil spill.
OPA calls for a financial responsibility of $35 million to cover pollution
cleanup for offshore facilities. State laws for the control of water pollution
also provide varying civil and criminal penalties and liabilities in the case of
releases of petroleum or its derivatives into surface waters or into the ground.
The Company does not believe that the OPA, CWA or related state laws are any
more burdensome to it than they are to other similarly situated oil and gas
companies.

Many states in which the Company operates regulate naturally occurring
radioactive materials ("NORM") and NORM wastes that are generated in connection
with oil and gas exploration and production activities. NORM wastes typically
consist of very low-level radioactive substances that become concentrated in
pipe scale and in production equipment. Certain state regulations require the
testing of pipes and production equipment for the presence of NORM, the
licensing of NORM-contaminated facilities and the careful handling and disposal
of NORM wastes. The regulation of NORM has minimal effect on the Company's
operations because the Company generates only small quantities of NORM on an
annual basis.

10

The Company does not believe that its environmental risks are materially
different from those of comparable companies in the oil and gas industry.
Nevertheless, no assurance can be given that environmental laws will not result
in a curtailment of production or processing, a material increase in the costs
of production, development, exploration or processing or otherwise adversely
affect the Company's future results of operations and financial condition.

The Company employs an environmental director, regulatory manager and
regulatory and environmental specialists charged with monitoring environmental
and regulatory compliance. The Company performs an environmental review as part
of the due diligence work on potential acquisitions. The Company is not aware of
any material environmental legal proceedings pending against it or any material
environmental liabilities to which it may be subject.

Risks Associated with Business Activities

The nature of the business activities conducted by the Company subjects it
to certain hazards and risks. The following is a summary of some of the material
risks relating to the Company's business activities.

Commodity prices. The Company's revenues, profitability, cash flow and
future rate of growth are highly dependent on oil and gas prices, which are
affected by numerous factors beyond the Company's control. Oil and gas prices
historically have been very volatile. A significant downward trend in commodity
prices would have a material adverse effect on the Company's revenues,
profitability and cash flow and could, under certain circumstances, result in a
reduction in the carrying value of the Company's oil and gas properties and
goodwill and the recognition of deferred tax asset valuation allowances or an
increase to the Company's deferred tax asset valuation allowances, depending on
the Company's tax attributes in each country in which it has activities.

Drilling activities. Drilling involves numerous risks, including the risk
that no commercially productive oil or gas reservoirs will be encountered. The
cost of drilling, completing and operating wells is often uncertain and drilling
operations may be curtailed, delayed or canceled as a result of a variety of
factors, including unexpected drilling conditions, pressure or irregularities in
formations, equipment failures or accidents, adverse weather conditions and
shortages or delays in the delivery of equipment. The Company's future drilling
activities may not be successful and, if unsuccessful, such failure could have
an adverse effect on the Company's future results of operations and financial
condition. While all drilling, whether developmental or exploratory, involves
these risks, exploratory drilling involves greater risks of dry holes or failure
to find commercial quantities of hydrocarbons. Because of the percentage of the
Company's capital budget devoted to higher risk exploratory projects, it is
likely that the Company will continue to experience exploration and abandonment
expense.

Unproved properties. At December 31, 2004 and 2003, the Company carried
unproved property costs of $470.4 million and $179.8 million, respectively.
Generally accepted accounting principles require periodic evaluation of these
costs on a project-by-project basis in comparison to their estimated fair value.
These evaluations will be affected by the results of exploration activities,
commodity price outlooks, planned future sales or expiration of all or a portion
of the leases, contracts and permits appurtenant to such projects. If the
quantity of potential reserves determined by such evaluations is not sufficient
to fully recover the cost invested in each project, the Company will recognize
noncash charges in the earnings of future periods.

Acquisitions. Acquisitions of producing oil and gas properties have been a
key element of the Company's growth. The Company's growth following the full
development of its existing property base could be impeded if it is unable to
acquire additional oil and gas reserves on a profitable basis. The success of
any acquisition will depend on a number of factors, including the ability to
estimate accurately the costs to develop the reserves, the recoverable volumes
of reserves, rates of future production and future net revenues attainable from
the reserves and to assess possible environmental liabilities. All of these
factors affect whether an acquisition will ultimately generate cash flows
sufficient to provide a suitable return on investment. Even though the Company
performs a review of the properties it seeks to acquire that it believes is
consistent with industry practices, such reviews are often limited in scope.

Divestitures. The Company regularly reviews its property base for the
purpose of identifying non-strategic assets, the disposition of which would
increase capital resources available for other activities and create
organizational and operational efficiencies. Various factors could materially

11

affect the ability of the Company to dispose of non-strategic assets, including
the availability of purchasers willing to purchase the non-strategic assets at
prices acceptable to the Company.

Operation of natural gas processing plants. As of December 31, 2004, the
Company owned interests in 11 natural gas processing plants and five treating
facilities. The Company operates seven of the plants and all five treating
facilities. There are significant risks associated with the operation of natural
gas processing plants. Gas and NGLs are volatile and explosive and may include
carcinogens. Damage to or misoperation of a gas processing plant or facility
could result in an explosion or the discharge of toxic gases, which could result
in significant damage claims in addition to interrupting a revenue source.

Operating hazards and uninsured losses. The Company's operations are
subject to all the risks normally incident to the oil and gas exploration and
production business, including blowouts, cratering, explosions, adverse weather
effects and pollution and other environmental damage, any of which could result
in substantial losses to the Company due to injury or loss of life, damage to or
destruction of wells, production facilities or other property, clean-up
responsibilities, regulatory investigations and penalties and suspension of
operations. Although the Company currently maintains insurance coverage that it
considers reasonable and that is similar to that maintained by comparable
companies in the oil and gas industry, it is not fully insured against certain
of these risks, either because such insurance is not available or because of the
high premium costs associated with obtaining such insurance.

Environmental. The oil and gas business is subject to environmental
hazards, such as oil spills, produced water spills, gas leaks and ruptures and
discharges of toxic substances or gases that could expose the Company to
substantial liability due to pollution and other environmental damage. A variety
of federal, state and foreign laws and regulations govern the environmental
aspects of the oil and gas business. Noncompliance with these laws and
regulations may subject the Company to penalties, damages or other liabilities,
and compliance may increase the cost of the Company's operations. Such laws and
regulations may also affect the costs of acquisitions. See "Item 1. Business -
Competition, Markets and Regulations - Environmental and health controls" above
for additional discussion related to environmental risks.

The Company does not believe that its environmental risks are materially
different from those of comparable companies in the oil and gas industry.
Nevertheless, no assurance can be given that future environmental laws will not
result in a curtailment of production or processing, a material increase in the
costs of production, development, exploration or processing or otherwise
adversely affect the Company's future operations and financial condition.
Pollution and similar environmental risks generally are not fully insurable.

Debt restrictions and availability. The Company is a borrower under fixed
term senior notes and variable rate credit facilities. The terms of the
Company's borrowings under the senior notes and the credit facilities specify
scheduled debt repayments and require the Company to comply with certain
associated covenants and restrictions. The Company's ability to comply with the
debt repayment terms, associated covenants and restrictions is dependent on,
among other things, factors outside the Company's direct control, such as
commodity prices, interest rates and competition for available debt financing.
See Note F of Notes to Consolidated Financial Statements included in "Item 8.
Financial Statements and Supplementary Data" for information regarding the
Company's outstanding debt as of December 31, 2004 and the terms associated
therewith.

The Company's ability to obtain additional financing is also impacted by
the Company's debt credit ratings. See "Item 7. Management's Discussion and
Analysis of Financial Condition and Results of Operations" for a discussion of
the Company's debt credit ratings.

Competition. The oil and gas industry is highly competitive. The Company
competes with other companies, producers and operators for acquisitions and in
the exploration, development, production and marketing of oil and gas. Some of
these competitors have substantially greater financial and other resources than
the Company. See "Item 1. Business - Competition, Markets and Regulations" above
for additional discussion regarding competition.

12

Government regulation. The Company's business is regulated by a variety of
federal, state, local and foreign laws and regulations. There can be no
assurance that present or future regulations will not adversely affect the
Company's business and operations. See "Item 1. Business - Competition, Markets
and Regulations" above for additional discussion regarding government
regulation.

International operations. At December 31, 2004, approximately 15 percent of
the Company's proved reserves of oil, NGLs and gas were located outside the
United States (12 percent in Argentina, two percent in Canada and one percent in
Africa). The success and profitability of international operations may be
adversely affected by risks associated with international activities, including
economic and labor conditions, political instability, tax laws (including host-
country import-export, excise and income taxes and United States taxes on
foreign subsidiaries) and changes in the value of the U.S. dollar versus the
local currencies in which oil and gas producing activities may be denominated.
To the extent that the Company is involved in international activities, changes
in exchange rates may adversely affect the Company's future results of
operations and financial condition. See "Critical Accounting Estimates" included
in "Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations", "Qualitative Disclosures" in "Item 7A. Quantitative and
Qualitative Disclosures About Market Risk" and Note B of Notes to Consolidated
Financial Statements included in "Item 8. Financial Statements and Supplementary
Data" for information specific to Argentina's economic and political situation.

Estimates of reserves and future net revenues. Numerous uncertainties exist
in estimating quantities of proved reserves and future net revenues therefrom.
The estimates of proved reserves and related future net revenues set forth in
this Report are based on various assumptions, which may ultimately prove to be
inaccurate.

Petroleum engineering is a subjective process of estimating underground
accumulations of oil and gas that cannot be measured in an exact manner.
Estimates of economically recoverable oil and gas reserves and of future net
cash flows necessarily depend upon a number of variable factors and assumptions,
including the following:

o historical production from the area compared with production from other
producing areas,
o the quality and quantity of available data,
o the interpretation of that data,
o the assumed effects of regulations by governmental agencies,
o assumptions concerning future oil and gas prices and
o assumptions concerning future operating costs, severance, ad valorem
and excise taxes, development costs and workover and remedial costs.

Because all reserve estimates are to some degree subjective, each of the
following items may differ materially from those assumed in estimating reserves:

o the quantities of oil and gas that are ultimately recovered,
o the production and operating costs incurred,
o the amount and timing of future development expenditures and
o future oil and gas sales prices.

Furthermore, different reserve engineers may make different estimates of
reserves and cash flows based on the same available data. The Company's actual
production, revenues and expenditures with respect to reserves will likely be
different from estimates and the difference may be material.

As required by the SEC, the estimated discounted future net cash flows from
proved reserves are generally based on prices and costs as of the date of the
estimate, while actual future prices and costs may be materially higher or
lower. Actual future net cash flows also will be affected by factors such as:

o the amount and timing of actual production,
o supply and demand of oil and gas,
o increases or decreases in consumption and
o changes in governmental regulations or taxation.

13

The Company reports all proved reserves held under production sharing
arrangements and concessions utilizing the "economic interest" method, which
excludes the host country's share of proved reserves. Estimated quantities of
production sharing arrangements reported under the "economic interest" method
are subject to fluctuations in the price of oil and gas and recoverable
operating expenses and capital costs. If costs remain stable, reserve quantities
attributable to recovery of costs will change inversely to changes in commodity
prices.

Standardized Measure is a reporting convention that provides a common basis
for comparing oil and gas companies subject to the rules and regulations of the
SEC. It requires the use of oil and gas spot prices prevailing as of the date of
computation. Consequently, it may not reflect the prices ordinarily received or
that will be received for oil and gas production because of seasonal price
fluctuations or other varying market conditions. Standardized Measures as of any
date are not necessarily indicative of future results of operations.
Accordingly, estimates included herein of future net revenues may be materially
different from the net revenues that are ultimately received. Therefore, the
estimates of discounted future net cash flows or Standardized Measure in this
Report should not be construed as accurate estimates of the current market value
of the Company's proved reserves.

ITEM 2. PROPERTIES

The information included in this Report about the Company's oil, NGL and
gas reserves as of December 31, 2004 and 2003 was based on reserve reports
audited by Netherland, Sewell & Associates, Inc. ("NSA") for the Company's major
properties in the United States, Argentina, Canada and South Africa and reserve
reports prepared by the Company's engineers for all other properties. The
reserve audits conducted by NSA in aggregate represented 88 percent and 87
percent of the Company's estimated proved quantities of reserves as of December
31, 2004 and 2003, respectively. The information included in this Report about
the Company's oil, NGL and gas reserves as of December 31, 2002 was, in part,
based on reserve reports audited by independent petroleum engineers and reserve
reports prepared by the Company's engineers. These reserve audits conducted
represented 71 percent of the Company's estimated proved quantities of reserves
as of December 31, 2002.

The Company did not provide estimates of total proved oil and gas reserves
during the years ended December 31, 2004, 2003 or 2002 to any federal authority
or agency, other than the SEC. The Company's reserve estimates do not include
any probable or possible reserves.

Proved Reserves

The Company's proved reserves totaled 1.0 billion BOE, 789.1 MMBOE and
736.7 MMBOE at December 31, 2004, 2003 and 2002, respectively, representing $6.6
billion, $4.6 billion and $4.1 billion, respectively, of Standardized Measure or
$9.1 billion, $6.0 billion and $5.1 billion, respectively, on a pre-tax basis.
The 30 percent and 45 percent increases in proved reserve volumes and
Standardized Measure, respectively, during 2004 were primarily due to:

o Evergreen merger - 262.2 MMBOE,
o other 2004 acquisitions - 16.0 MMBOE,
o extensions and discoveries in:
- Argentina - 25.8 MMBOE,
- United States - 10.5 MMBOE,
- Canada - 2.3 MMBOE and
- Africa - .5 MMBOE,
o negative revisions of 14.3 MMBOE primarily due to:
- 16.6 MMBOE due to the cancellation of the Gabon project as a result
of increasing costs,
- negative well performance in the Portezuelo Oeste gas field in
Argentina, offset by
- increased commodity prices extending the estimated economic life of
various properties,
o production (including field fuel) during 2004 of 68.7 MMBOE and
o divestitures of 1.1 MMBOE.

The seven percent and 11 percent increases in proved reserve volumes and
Standardized Measure, respectively, during 2003 were primarily due to two core
area acquisitions, discoveries in Gabon, the deepwater Gulf of Mexico and
Tunisia and positive reserve revisions due to increased commodity prices
extending the estimated economic life of various properties, increased
recoverable reserve estimates based on well performance and the addition of

14

reserves resulting from the Company's expanded development drilling program.
Partially offsetting these reserve additions was 2003 production of 56.5 MMBOE,
including field fuel.

On a BOE basis, 65 percent of the Company's total proved reserves at
December 31, 2004 were proved developed reserves. Based on reserve information
as of December 31, 2004, and using the Company's production information for the
year then ended, the reserve-to-production ratio associated with the Company's
proved reserves was 15 years on a BOE basis. The following table provides
information regarding the Company's proved reserves and average daily sales
volumes by geographic area as of and for the year ended December 31, 2004:

PROVED OIL AND GAS RESERVES AND AVERAGE DAILY SALES VOLUMES

2004 Average Daily
Proved Reserves as of December 31, 2004 (a) Sales Volumes (b)
------------------------------------------------- ----------------------------------
Oil Standardardized Oil
& NGLs Gas Measure & NGLs Gas
(MBbls) (MMcf) MBOE (in thousands) (Bbls) (Mcf) BOE
--------- --------- ---------- ----------- -------- --------- ---------

United States..... 363,257 3,000,335 863,313 $ 5,581,303 46,375 521,839 133,349
Argentina......... 33,168 560,374 126,564 647,292 10,080 121,654 30,356
Canada............ 4,095 119,869 24,073 276,467 1,054 41,867 8,031
Africa............ 8,271 - 8,271 138,013 11,676 - 11,676
--------- --------- ---------- ---------- -------- --------- --------
Total............. 408,791 3,680,578 1,022,221 $ 6,643,075 69,185 685,360 183,412
========= ========= ========== ========== ======== ========= ========

- ----------------
(a) The gas reserves contain 271.7 Bcf of gas that will be produced and
utilized as field fuel. Field fuel is gas consumed to operate field
equipment (primarily compressors) prior to the gas being delivered to a
sales point.
(b) The 2004 average daily sales volumes (i) do not include the field fuel
produced, which averaged 4,374 BOE per day and (ii) were calculated using a
366-day year and without making pro forma adjustments for any acquisitions,
divestitures or drilling activity that occurred during the year.

The following table represents the estimated timing and cash flows of
developing the Company's proved undeveloped reserves as of December 31, 2004:

Estimated
Future Future Future Future
Production Cash Production Development Future Net
Years Ended December 31, (MBOE) Inflows Costs Costs Cash Flows
---------- ----------- ----------- ----------- ----------
($ in thousands)

2005............................... 8,534 $ 240,171 $ 28,271 $ 394,289 $ (182,389)
2006............................... 20,625 569,708 70,596 347,878 151,234
2007............................... 21,801 616,401 87,791 214,855 313,755
2008............................... 22,120 613,047 90,579 183,546 338,922
2009............................... 22,716 595,765 95,363 161,118 339,284
Thereafter......................... 257,752 8,085,106 2,133,005 204,888 5,747,213
--------- ---------- --------- --------- ---------
353,548 $10,720,198 $2,505,605 $1,506,574 $6,708,019
========= ========== ========= ========= =========

Description of Properties

As of December 31, 2004, the Company has production, development and/or
exploration operations in the United States, Argentina, Canada, Equatorial
Guinea, Gabon, South Africa and Tunisia.

Domestic. The Company's domestic operations are located in the Permian
Basin, Mid-Continent, Rocky Mountains, Alaska, Gulf of Mexico and onshore Gulf
Coast areas of the United States. Approximately 75 percent of the Company's
domestic proved reserves at December 31, 2004 are located in the Spraberry,
Hugoton, West Panhandle and Raton fields. These mature fields generate
substantial operating cash flow and some have a large portfolio of low risk

15

infill drilling opportunities. The cash flows generated from these fields
provide funding for the Company's other development and exploration activities
both domestically and internationally. During the year ended December 31, 2004,
the Company expended $2.9 billion in domestic acquisition, exploration and
development drilling activities, $2.5 billion of which related to the Evergreen
merger. The Company has budgeted approximately $700 million for domestic
exploration and development drilling expenditures for 2005.

Spraberry field. The Spraberry field was discovered in 1949 and encompasses
eight counties in West Texas. The field is approximately 150 miles long and 75
miles wide at its widest point. The oil produced is West Texas Intermediate
Sweet, and the gas produced is casinghead gas with an average energy content of
1,400 Btu. The oil and gas is produced primarily from three formations, the
upper and lower Spraberry and the Dean, at depths ranging from 6,700 feet to
9,200 feet. Recently, the Company has been adding the Wolfcamp formation at
depths ranging from 9,300 feet to 10,300 feet to selected wells with successful
results. The center of the Spraberry field was unitized in the late 1950s and
early 1960s by the major oil companies; however, until the late 1980s there was
very limited development activity in the field. The Company believes the area
offers excellent opportunities to enhance oil and gas reserves because of the
numerous undeveloped infill drilling locations, many of which are reflected in
the Company's proved undeveloped reserves, and the ability to reduce operating
expenses through economies of scale.

During the year ended December 31, 2004, the Company placed 104 Spraberry
wells on production and had 16 wells in progress as of December 31, 2004. The
Company plans to drill approximately 150 development wells in the Spraberry
field during 2005.

Hugoton field. The Hugoton field in southwest Kansas is one of the largest
producing gas fields in the continental United States. The gas is produced from
the Chase and Council Grove formations at depths ranging from 2,700 feet to
3,000 feet. The Company's gas in the Hugoton field has an average energy content
of 1,025 Btu. The Company's Hugoton properties are located on approximately
257,000 gross acres (237,000 net acres), covering approximately 400 square
miles. The Company has working interests in approximately 1,200 wells in the
Hugoton field, about 1,000 of which it operates, and partial royalty interests
in approximately 500 wells. The Company owns substantially all of the gathering
and processing facilities, primarily the Satanta plant, that service its
production from the Hugoton field. Such ownership allows the Company to control
the production, gathering, processing and sale of its gas and NGL production.

The Company's Hugoton operated wells are capable of producing approximately
90.5 MMcf of wet gas per day (i.e., gas production at the wellhead before
processing or field fuel use and before reduction for royalties), although
actual production in the Hugoton field is limited by allowables set by state
regulators. The Company estimates that it and other major producers in the
Hugoton field produced at or near capacity during the year ended December 31,
2004. During 2004, the Company placed 17 development wells on production and had
one well in progress as of December 31, 2004. The plans for 2005 include
drilling approximately 18 development wells and one potential new horizontal
well.

The Company is continuing to evaluate the feasibility of infill drilling
into the Council Grove Formation and may submit an application to the Kansas
Corporation Commission to allow infill drilling. Such infill drilling may
increase production from the Company's Hugoton properties. However, until an
application has been submitted and approved, the Company will not reflect any of
the infill drilling locations as proved undeveloped reserves. There can be no
assurance that the application will be filed or approved, or as to the timing of
such approval if granted.

West Panhandle field. The West Panhandle properties are located in the
panhandle region of Texas where initial production commenced in 1918. These
stable, long-lived reserves are attributable to the Red Cave, Brown Dolomite,
Granite Wash and fractured Granite formations at depths no greater than 3,500
feet. The Company's gas in the West Panhandle field has an average energy
content of 1,300 Btu and is produced from approximately 600 wells on more than
250,000 gross acres covering over 375 square miles. The Company controls 100
percent of the wells, production equipment, gathering system and gas processing
plant for the field.

During the year ended December 31, 2004, the Company placed 78 development
wells on production and drilled three development wells and two extension wells
which were determined to be unsuccessful. The West Panhandle field had 11
development wells in progress as of December 31, 2004. The Company plans to
drill approximately 90 wells in the West Panhandle field during 2005.

16

Rocky Mountain area. The Company is one of the leading U.S. producers of
coal bed methane ("CBM") with the Raton, Piceance and Uinta Basin assets
acquired from Evergreen which are situated in Colorado and Utah. Exploration for
CBM in the Raton Basin began in the late 1970s and continued through the late
1980s, with several companies drilling and testing more than 100 wells during
this period. The absence of a pipeline to transport gas from the Raton Basin
prevented full scale development until January 1995, when Colorado Interstate
Gas Company completed the construction of the Picketwire lateral. The Company
owns approximately 385,000 gross acres in the center of the Raton Basin with
current production from coal seams of the Vermejo and Raton formations. The
Company also owns approximately 171,000 acres covering highly prospective
regions of the Piceance and Uinta Basins. Currently, production is established
from various tight sandstone, coal and shale formations. The Company has
approximately 1,300 wells in these fields with an average daily gross measured
production of 191 MMcf. In the fourth quarter of 2004, the Company placed 49
development wells on production and drilled two successful extension wells.
Plans for 2005 include the drilling of approximately 300 development wells and
20 extension wells to establish additional prospective areas and reserves.

Gulf of Mexico area. In the Gulf of Mexico, the Company is focused on
reserve and production growth through a portfolio of shelf and deepwater
development projects, high-impact, higher-risk deepwater exploration drilling,
shelf exploration drilling and exploitation opportunities inherent in the
properties the Company currently has producing on the shelf.

In the deepwater Gulf of Mexico, the Company has three major projects, all
of which were producing or capable of producing at December 31, 2004:

o Canyon Express - The Canyon Express project is a joint development
of three deepwater Gulf of Mexico gas discoveries, including the
Company's TotalFinaElf-operated Aconcagua and Marathon-operated
Camden Hills fields, where the Company holds 37.5 percent and 33.3
percent working interests, respectively. The Company participated
in the discovery of the Aconcagua gas field in 1999 during the
early stages of building its exploration program and later added
Camden Hills to its portfolio to enhance its ownership in the
project. The Canyon Express project was approved for development
in June 2000 and reached first production in September 2002. The
Canyon Express gathering system is the first in the area and
provides the Company and its partners with the opportunity to
collect gathering and handling revenues from the use of the system
by any future discoveries in the area. The Company has plans to
drill and complete an additional development well at Aconcagua
during 2005.

o Falcon Corridor - The Falcon Corridor project started with the
Company's Falcon field discovery during 2001, followed by the 2003
Harrier, Raptor and Tomahawk discoveries. The Company owned a 45
percent working interest in the initial Falcon discovery and
surrounding areas. During 2002, the Company purchased an
additional 30 percent working interest in the project and became
the operator. During 2003, the Company acquired the remaining 25
percent working interest in the project and established first
Falcon production during March 2003.

In the first quarter of 2003, the Company drilled its Harrier
discovery, which was completed as a one-well subsea tie-back to
the Falcon field facilities and placed on production in January
2004. In addition, during the third quarter of 2003, the Company
successfully drilled the Tomahawk and Raptor prospects, which were
also developed as single-well subsea tie-backs to the Falcon field
facilities and placed on production in June 2004. To accommodate
the incremental production from Harrier, Tomahawk and Raptor, as
well as potential throughput associated with additional planned
exploration, an additional parallel pipeline connecting the Falcon
field to the Falcon Nest platform on the Gulf of Mexico shelf was
added, doubling its capacity. In early September 2004, the Company
shut in production from the Harrier field as a result of early
water encroachment. The Company initiated a sidetrack well in late
September to access an adjacent fault block in the field which was
successful, encountering over 400 feet of gas-bearing sand. In
order to capture the maximum reserves from the Raptor and Tomahawk
fields, the Company delayed production from the Harrier sidetrack
until the Tomahawk field was fully depleted in December 2004. Once
the Harrier sidetrack was placed on production, the Falcon field
production rate was reduced to continue to allow Raptor to fully
deplete. Raptor is anticipated to be depleted during the first
half of 2005, at which time production from Falcon will be
increased. The Company operates all of the producing fields in the

17

Falcon Corridor. Sidetrack operations are being evaluated for the
Raptor field in 2005 to further increase reserve recovery. In
addition, the Company plans to drill one or two Falcon Corridor
exploration prospects during the first half of 2005.

o Devils Tower Area - The Dominion-operated Devils Tower development
project was sanctioned in 2001 as a spar development project with
the owners leasing a spar from a third party for the life of the
field. The spar has slots for eight dry tree wells and up to four
subsea tie-back risers and is capable of handling 60 MBbls of oil
per day and 60 MMcf of gas per day. Three Devils Tower wells were
completed and placed on production prior to being shut-in during
mid-September due to Hurricane Ivan. The Devils Tower spar
sustained significant damage during Hurricane Ivan, and production
from the three wells did not resume until late October 2004. A
fourth well began producing at the end of November. The damage to
the platform rig sustained during Hurricane Ivan delayed
completion activities related to the four additional wells
previously drilled to develop the field. Rig repairs took 120
days, and completion activities for continued field development
began late in January 2005. Pioneer maintains business
interruption insurance and has filed a claim related to four wells
that were expected to be completed but were delayed due to the
effects of the hurricane. In the fourth quarter of 2004, the
Company recorded approximately $7.5 million of estimated business
interruption recovery related to its estimated 2004 production
loss and should have additional insurance recoveries associated
with 2005 operational impact from Hurricane Ivan. In addition,
three subsea tie-back wells in the Goldfinger and Triton satellite
discoveries in the Devils Tower area are expected to be jointly
tied back to the Devils Tower spar with first production expected
in late 2005. Production is expected to continue to increase as
additional wells are individually completed from the spar over the
next six months. The Company holds a 25 percent working interest
in each of the above projects.

In addition to the development and exploration projects in the deepwater
Gulf of Mexico described above, the Company participated in three subsalt
deepwater prospects during the first half of 2004, of which one well was
successful and two were noncommercial. A sidetrack well in the Dominion-operated
Thunder Hawk discovery at Mississippi Canyon Block 734 encountered in excess of
300 feet of net oil pay in two high-quality reservoir zones. Murphy Exploration
and Production Company is now the operator and has commenced drilling an
additional well to further delineate the field. The Company owns a 12.5 percent
working interest in the discovery. The Company also anticipates drilling an
appraisal well during 2005 on its 2002 Ozona Deep discovery.

During January 2003, the Company announced a joint exploration agreement
with Woodside Energy (USA), Inc. ("Woodside"), a subsidiary of Woodside Energy
Ltd. of Australia, for a two-year drilling program over the shallow-water Texas
shelf region of the Gulf of Mexico. Under the agreement, Woodside acquired a 50
percent working interest in 47 offshore exploration blocks operated by the
Company. The agreement covers eight prospects and 19 leads and included five
exploratory wells originally scheduled to be drilled in 2003 and three in 2004.
Most of the wells to be drilled under the agreement target gas plays below
15,000 feet. The first three wells under this joint agreement were unsuccessful.
The fourth well, Midway, encountered 30 feet of net gas pay and is expected to
be tied back to an existing production platform with first production
anticipated during the second quarter of 2005. Three other intervals with an
additional 60 feet of gas bearing sands were also encountered and will require
additional analysis to determine future commercial potential. The Company has a
37.5 percent working interest in this well. The fifth well that was originally
scheduled to be drilled in 2003 and the three wells originally scheduled to be
drilled in 2004 under the agreement, which has been extended for one additional
year, were mutually agreed to be deferred until more technical work can be
performed on the prospects by both companies. Additionally, the Company and
Woodside are evaluating shallower gas prospects on the Gulf of Mexico shelf for
possible inclusion in the 2005 drilling program.

Onshore Gulf Coast area. The Company has focused its drilling efforts in
this area on the Pawnee field in the Edwards Reef trend in South Texas. The
Company placed 10 development wells and two extension wells on production at
Pawnee during 2004 and had two development wells and one extension well in
progress at year end. The Company plans to drill approximately 12 wells in this
area during 2005.

Alaska area. The Company spent $34.7 million of acquisition and seismic
capital during 2004 to add to its leasehold position and expand its North Slope
seismic data coverage. In June 2004, Pioneer announced that it agreed to a joint
exploration program in the National Petroleum Reserve-Alaska ("NPR-A") located
on the North Slope with ConocoPhillips and Anadarko Petroleum Corporation. At
the federal lease sale held in June 2004, P ioneer was the high co-bidder on 63

18

tracts covering approximately 717,000 acres in the NPR-A Northwest Planning
Area. Pioneer will participate with a 20 percent to 30 percent working interest
in the acreage operated by ConocoPhillips. Pioneer also acquired a 20 percent
interest in 167,000 total acres in the adjacent NPR-A Northeast Planning Area
and in federal offshore blocks, including seismic and geologic data. In December
2004, Pioneer signed an exploration agreement with ConocoPhillips and Anadarko
acquiring a 20 percent interest in approximately 452,000 additional acres and
gaining the rights to extensive seismic and geologic data in the NPR-A Northeast
Planning Area. Pioneer expects to participate in a multi-year exploration
program within NPR-A and anticipates that two exploration wells will be drilled
during the first half of 2005.

During the first quarter of 2005, Pioneer will also participate with a 40
percent working interest in an exploration well to evaluate the Kerr-McGee
Corporation - Tuvaaq prospect. In addition, Pioneer holds a 50 percent working
interest in a 130,000-acre position adjacent to and south of the giant Prudhoe
Bay and Kuparuk Units and has a new 3-D seismic survey underway for completion
during the first quarter of 2005.

During 2002, the Company acquired a 70 percent working interest and
operatorship in ten state leases on Alaska's North Slope. Associated therewith,
the Company drilled three exploratory wells during 2003 to test a possible
extension of the productive sands in the Kuparuk River field into the shallow
waters offshore. Although all three of the wells found the sands filled with
oil, they were too thin to be considered commercial on a stand-alone basis.
However, the wells also encountered thick sections of oil-bearing Jurassic-aged
sands, and the first well flowed at a rate of approximately 1,300 barrels per
day. In January 2004, the Company farmed-into a large acreage block to the
southwest of the Company's discovery. In the fourth quarter of 2004, Pioneer
completed an extensive technical and economic evaluation of the resource
potential within this area. As a result of this evaluation, the Company is
performing front-end engineering and permitting activities to further define the
scope of the project. If the additional work confirms favorable development
economics, Pioneer will seek to obtain regulatory approval to develop the field
in 2006 targeting first oil in 2008.

International. The Company's international operations are located in the
Neuquen and Austral Basins areas of Argentina, the Chinchaga, Martin Creek,
Lookout Butte and Carbon areas of Canada, the Sable oil field offshore South
Africa and in southern Tunisia. Additionally, the Company has other development
and exploration activities in the shallow waters offshore South Africa and oil
development and exploration activities in Tunisia. As of December 31, 2004,
approximately 12 percent, two percent and one percent of the Company's proved
reserves are located in Argentina, Canada and Africa, respectively.

Argentina. The Company's Argentine production during the year ended
December 31, 2004 averaged 30.4 MBOE per day, or approximately 17 percent of the
Company's equivalent production. The Company's operated production in Argentina
is concentrated in the Neuquen Basin which is located about 925 miles southwest
of Buenos Aires and to the east of the Andes Mountains. Oil and gas are produced
primarily from the Al Norte de la Dorsal, the Al Sur de la Dorsal, the Dadin,
the Loma Negra - Ni, the Dos Hermanas, the Anticlinal Campamento and the
Estacion Fernandez Oro blocks, each of which the Company has a 100 percent
working interest. Most of the gas produced from these blocks is processed in the
Company's Loma Negra gas processing plant. The Company also operates and has a
50 percent working interest in the Lago Fuego field which is located in Tierra
del Fuego, an island in the extreme southern portion of Argentina, approximately
1,500 miles south of Buenos Aires.

Most of the Company's non-operated production in Argentina is located in
Tierra del Fuego where oil, gas and NGLs are produced from six separate fields
in which the Company has a 35 percent working interest. The Company also has a
14.4 percent working interest in the Confluencia field which is located in the
Neuquen Basin.

During the year ended December 31, 2004, the Company expended $102.5
million on Argentine development and exploration activities. The Company drilled
44 development wells and 31 extension/exploratory wells, of which 43 development
wells and 21 extension/exploratory wells were successful. During 2004, the
Company shot seismic covering approximately 330,000 acres. The Company plans to
be more active in Argentina in 2005 with $133 million budgeted for oil and gas
development and exploration activities.

Canada. The Company's Canadian producing properties are located primarily
in Alberta and British Columbia, Canada. Production during the year ended
December 31, 2004 averaged 8.0 MBOE per day, or approximately four percent of
the Company's equivalent production. The Company continues to focus its
traditional conventional development, exploration and acquisition activities in

19

the core areas of northeast British Columbia and southern Alberta while
expanding these activities to include a CBM focus in southern Alberta. The
Canadian assets are geographically concentrated, predominately shallow gas and
primarily operated by the Company in the following areas: Chinchaga, Martin
Creek, Lookout Butte and Carbon.

Production from the Chinchaga area of northeast British Columbia is
relatively dry gas from formation depths averaging 3,400 feet. In the Martin
Creek area of British Columbia the production is relatively dry gas from various
reservoirs ranging from 3,700 to 4,300 feet. The Lookout Butte area in southwest
Alberta produces gas and condensate from the Mississippian Turner Valley
formation at approximately 12,000 feet. The Carbon area in south central Alberta
produces gas, CBM, condensate and minor oil from Cretaceous to Devonian
formations at depths ranging from 400 to 6,500 feet.

During the year ended December 31, 2004, the Company expended $120.6
million (approximately $56.4 million associated with the Evergreen merger) on
Canadian exploration, development and acquisition activities. The Company
drilled three development wells and 51 exploratory/extension wells, primarily in
the Chinchaga, Martin Creek and Carbon areas, of which all three developments
wells and 27 exploratory/extension wells were successful. The majority of these
wells were drilled in the Chinchaga and Martin Creek areas during the first
quarter of 2004 as these areas are only accessible for drilling during the
winter months. The remainder of these wells were drilled during the summer and
fall in the Carbon area that is accessible for operations throughout the year.
The Company plans to spend approximately $60 million on oil, gas and CBM
development and exploration opportunities in Canada during 2005.

The Company previously announced its intention to divest of its Martin
Creek and Lookout Butte assets in 2005. The expectation is that sales proceeds
will exceed $100 million based on today's commodity price environment, however,
no assurance can be given that purchasers will bid for these assets at prices
that are acceptable to the Company.

Africa. In Africa, the Company has entered into agreements to explore for
oil and gas in South Africa, Equatorial Guinea, Gabon and Tunisia. The amended
South African agreements cover over five million acres along the southern coast
of South Africa, generally in water depths less than 650 feet. The Gabon
agreement covers 313,937 acres off the coast of Gabon, generally in water depths
less than 100 feet. The Tunisian agreements can be separated into three
categories: (i) three permits covering 2.9 million acres which the Company
operates with an average 55 percent working interest, (ii) the Anadarko-operated
Anaguid and Jenein Nord permits covering over 1.5 million acres in which the
Company has a 45 percent working interest and (iii) the ENI-operated Adam
Concession and Borj El Khadra permit covering 212,420 acres and 969,755 acres,
respectively, in which the Company has a 28 percent and 40 percent working
interest, respectively. All permits are onshore southern Tunisia. During the
year ended December 31, 2004, the Company expended $74.9 million of acquisition,
development and exploration drilling and seismic capital in South Africa, Gabon,
Equatorial Guinea, Tunisia and other prospective areas.

South Africa. The Company spent $9.5 million of capital associated with its
Petro SA-operated Sable oil field. The Sable oil field began producing in August
2003. The Company has a 40 percent working interest in the Sable field. In 2005,
the Company currently plans to spend approximately $1 million in South Africa
for production enhancement opportunities at Sable.

In 2005, the Company expects its South African gas project to be sanctioned
by all parties. If approved, this project will allow the Company to sell its gas
from the Sable field and provide commercialization opportunities for previous
gas discoveries.

Equatorial Guinea. The Company spent $13.0 million of acquisition and
drilling capital during 2004 to acquire a 50 percent working interest in 244,881
acres of Block H offshore Equatorial Guinea. The Bravo 1 well was drilled in
June 2004 and determined to be noncommercial. The Company has several other
prospects on the block that are being evaluated for future drilling, one of
which is expected to be drilled during 2005.

Gabon. The Company spent $20.7 million of capital during 2004 to drill five
exploration wells, one of which was initially evaluated as successful in
extending the planned development area to the south. The remaining four wells
were unsuccessful. Despite the successful extension well, in October 2004, the
Company canceled the development of the Olowi field due to a substantial
increase in projected development costs which resulted in the project not

20

offering competitive returns. The Company's current Gabonese permit expires in
April 2005. The Company has verbally requested an extension to the permit to
allow more time for the Company to determine the best manner to exit Gabon,
however, no assurance can be given that such extension will be granted. In 2004,
the Company recognized an impairment charge of approximately $39.7 million.

Tunisia. The Company spent $17.0 million of acquisition, drilling and
seismic capital during the year ended December 31, 2004 primarily to drill one
successful development well in its Adam oil field, one successful development
well in its Hawa oil field and one successful exploratory well in its Dalia oil
field, all within the ENI-operated Adam Concession. Production from the Adam
Concession began in May 2003. The capital budget for Tunisia in 2005 of
approximately $24 million includes an exploration well in the Adam concession,
one exploration well on the Company-operated El Hamra permit and two appraisal
wells on the Anaguid permit.

Selected Oil and Gas Information

The following tables set forth selected oil and gas information for the
Company as of and for each of the years ended December 31, 2004, 2003 and 2002.
Because of normal production declines, increased or decreased drilling
activities and the effects of past and future acquisitions or divestitures, the
historical information presented below should not be interpreted as being
indicative of future results.

Production, price and cost data. The following table sets forth production,
price and cost data with respect to the Company's properties for the years ended
December 31, 2004, 2003 and 2002:

21

PRODUCTION, PRICE AND COST DATA

Year Ended December 31,
-------------------------------------------------------------------------------------------------------------------
2004 2003 2002
------------------------------------- ------------------------------------------ ----------------------------------
United United United
States Argentina Canada Africa Total States Argentina Canada Africa Total States Argentina Canada Total
------ --------- ------ ------ ------- ------- --------- ------- ------ -------- ------- --------- ------- --------

Production
information:
Annual sales
volumes:
Oil (MBbls)... 9,750 3,123 50 4,274 17,197 8,952 3,171 40 723 12,886 8,555 2,914 45 11,514
NGLs (MBbls).. 7,224 566 336 - 8,126 7,423 481 331 - 8,235 7,487 254 345 8,086
Gas (MMcf)....190,994 44,525 15,323 - 250,842 154,400 34,357 15,209 - 203,966 77,199 28,550 17,653 123,402
Total (MBOE).. 48,806 11,110 2,939 4,274 67,129 42,108 9,378 2,906 723 55,115 28,908 7,926 3,333 40,167
Average daily
sales volumes:
Oil (Bbls).... 26,637 8,534 137 11,676 46,984 24,525 8,687 111 1,981 35,304 23,437 7,984 124 31,545
NGLs (Bbls)... 19,738 1,546 917 - 22,201 20,338 1,318 906 - 22,562 20,512 696 946 22,154
Gas (Mcf).....521,839 121,654 41,867 - 685,360 423,013 94,128 41,669 - 558,810 211,502 78,220 48,365 338,087
Total (BOE)...133,349 30,356 8,031 11,676 183,412 115,364 25,694 7,962 1,981 151,001 79,201 21,716 9,131 110,048
Average prices,
including hedge
results:
Oil (per Bbl).$ 29.41 $ 28.06 $ 44.83 $38.12 $ 31.38 $ 25.25 $ 25.62 $29.10 $29.52 $ 25.59 $23.66 $ 20.63 $22.26 $ 22.89
NGLs (per
Bbl).........$ 25.07 $ 29.91 $ 30.87 $ - $ 25.65 $ 19.04 $ 22.85 $24.80 $ - $ 19.50 $13.77 $ 14.56 $16.77 $ 13.92
Gas (per Mcf).$ 5.15 $ .66 $ 4.64 $ - $ 4.33 $ 4.47 $ .56 $ 4.93 $ - $ 3.84 $ 3.16 $ .48 $ 3.41 $ 2.58
Revenue (per
BOE).........$ 29.75 $ 12.07 $ 28.49 $38.12 $ 27.30 $ 25.10 $ 11.87 $29.05 $29.52 $ 23.11 $19.01 $ 9.79 $20.12 $ 17.29
Average prices,
excluding hedge
results:
Oil (per Bbl).$ 39.59 $ 29.82 $ 44.83 $38.71 $ 37.61 $ 29.58 $ 26.31 $29.10 $30.07 $ 28.80 $23.85 $ 20.33 $22.26 $ 22.95
NGLs (per
Bbl).........$ 25.07 $ 29.91 $ 30.87 $ - $ 25.65 $ 19.04 $ 22.85 $24.80 $ - $ 19.50 $13.77 $ 14.56 $16.77 $ 13.92
Gas (per Mcf).$ 5.72 $ .66 $ 5.75 $ - $ 4.83 $ 4.92 $ .56 $ 5.30 $ - $ 4.25 $ 3.01 $ .48 $ 3.32 $ 2.52
Revenue (per
BOE).......$ 34.01 $ 12.56 $ 31.89 $38.71 $ 30.77 $ 27.69 $ 12.10 $30.98 $30.07 $ 25.24 $18.66 $ 9.68 $19.63 $ 16.97
Average costs
(per BOE):
Production costs:
Lease
operating.$ 3.45 $ 2.75 $ 9.69 $ 7.37 $ 3.86 $ 3.20 $ 2.57 $ 9.49 $ 3.87 $ 3.42 $ 3.42 $ 1.61 $ 7.50 $ 3.40
Taxes:
Ad valorem. .58 - - - .42 .53 - - - .41 .78 - - .56
Production. .83 .23 - - .64 .79 .20 - .12 .64 .74 .13 - .56
Workover..... .25 .01 .95 - .23 .16 .01 .43 - .15 .29 .01 .59 .26
------ ------ ------ ----- ------ ------ ----- ----- ----- ------ ----- ------ ----- ------
Total.....$ 5.11 $ 2.99 $ 10.64 $ 7.37 $ 5.15 $ 4.68 $ 2.78 $ 9.92 $ 3.99 $ 4.62 $ 5.23 $ 1.75 $ 8.09 $ 4.78
====== ====== ====== ===== ====== ====== ====== ===== ===== ====== ===== ====== ===== =======
Depletion
expense.......$ 8.61 $ 5.56 $ 10.93 $11.19 $ 8.37 $ 7.08 $ 4.96 $ 9.98 $10.69 $ 6.92 $ 4.85 $ 5.00 $ 8.36 $ 5.17
====== ====== ====== ===== ====== ====== ====== ===== ===== ====== ===== ====== ===== =======

- ---------------------------------------------------------------------------------
o These amounts represent the Company's historical results from operations
without making pro forma adjustments for any acquisitions, divestitures or
drilling activity that occurred during the respective years.
o During 2004, the Company changed its treatment of field fuel, which is gas
consumed to operate field equipment, to exclude the field fuel gas from
sales volumes, oil and gas revenues and production costs. In prior years,
the field fuel gas was included in sales volumes, oil and gas revenues and
production costs. The prior period amounts have been adjusted to reflect
the Company's current treatment of field fuel. Accordingly, the gas sales
volumes above represent gas available for sale. These amounts will not
agree to the reserve volume tables in the "Unaudited Supplemental Data"
section included in "Item 8. Financial Statements and Supplemenal Data"
because field fuel volumes are included in production volumes in the
reserve volume tables. See Note B of Notes to Consolidated Financial
Statements included in "Item 8. Financial Statements and Supplemental Data"
for additional discussion.
o During 2004, the Company changed its treatment of Canadian gas
transportation costs to include these costs as a component of oil and gas
production costs. In prior years, transportation costs were recorded as a
reduction to oil and gas revenues. The prior period amounts have been
adjusted to reflect the Company's current treatment of Canadian gas
transportation costs. See Note B of Notes to Consolidated Financial
Statements included in "Item 8. Financial Statements and Supplemental Data"
for additional discussion.
o The Company's lower average prices received for its Argentine commodities,
as compared to the prices received in other countries, is due to price
limitations imposed by the Argentine government in an effort to keep fuel
and energy prices for Argentine consumers at pre-devaluation levels. These
limitations have kept the prices received for oil and gas sales in
Argentina well below world market levels. Beginning in 2004, the government
has allowed gas prices to increase gradually over time, but other than
those specific increases already established for gas prices in 2005, no
specific predictions can be made about the future of oil or gas prices in
Argentina. See "Qualitative Disclosures" in "Item 7A. Quantitative and
Qualitative Disclosures About Market Risk" for additional discussion of
Argentine foreign currency, operations and price risk.
- --------------------------------------------------------------------------------

22

Productive wells. The following table sets forth the number of productive
oil and gas wells attributable to the Company's properties as of December 31,
2004, 2003 and 2002:

PRODUCTIVE WELLS (a)

Gross Productive Wells Net Productive Wells
----------------------------- -----------------------------
Oil Gas Total Oil Gas Total
------- ------- ------- ------- ------- --------

As of December 31, 2004:
United States............... 3,999 3,990 7,989 3,288 3,563 6,851
Argentina................... 744 226 970 607 168 775
Canada...................... 38 489 527 25 358 383
Africa...................... 9 - 9 3 - 3
------- ------- ------- ------- ------- -------
Total.................... 4,790 4,705 9,495 3,923 4,089 8,012
======= ======= ======= ======= ======= =======
As of December 31, 2003:
United States............... 3,691 2,012 5,703 2,978 1,907 4,885
Argentina................... 669 194 863 539 141 680
Canada...................... 4 268 272 4 210 214
Africa...................... 7 - 7 2 - 2
------- ------- ------- ------- ------- -------
Total.................... 4,371 2,474 6,845 3,523 2,258 5,781
======= ======= ======= ======= ======= =======
As of December 31, 2002:
United States............... 3,448 1,952 5,400 2,745 1,855 4,600
Argentina................... 694 208 902 534 142 676
Canada...................... 1 246 247 1 197 198
Africa...................... 5 - 5 2 - 2
------- ------- ------- ------- ------- -------
Total.................... 4,148 2,406 6,554 3,282 2,194 5,476
======= ======= ======= ======= ======= =======

- ---------------
(a) Productive wells consist of producing wells and wells capable of
production, including shut-in wells. One or more completions in the same
well bore are counted as one well. If any well in which one of the multiple
completions is an oil completion, then the well is classified as an oil
well. As of December 31, 2004, the Company owned interests in 335 gross
wells containing multiple completions.

Leasehold acreage. The following table sets forth information about the
Company's developed, undeveloped and royalty leasehold acreage as of December
31, 2004:

LEASEHOLD ACREAGE

Developed Acreage Undeveloped Acreage
------------------------- ------------------------- Royalty
Gross Acres Net Acres Gross Acres Net Acres Acreage
----------- ---------- ----------- ---------- ---------

United States:
Onshore................ 1,340,476 1,148,765 458,955 349,065 286,048
Offshore............... 114,573 53,078 2,122,351 1,130,895 10,500
---------- ---------- ---------- ---------- ---------
1,455,049 1,201,843 2,581,306 1,479,960 296,548
Argentina................. 728,000 333,000 1,139,000 1,056,000 -
Canada.................... 280,000 198,000 504,000 371,000 30,000
Africa.................... 222,020 63,318 11,406,804 6,611,566 -
---------- ---------- ---------- ---------- ---------
Total.................. 2,685,069 1,796,161 15,631,110 9,518,526 326,548
========== ========== ========== ========== =========

23

The following table sets forth the expiration dates of the leases on the
Company's gross and net undeveloped acres as of December 31, 2004:

Acres Expiring (a)
----------------------------
Gross Net
----------- ------------

2005 (b)............................ 3,928,789 3,038,128
2006................................ 3,073,584 1,580,639
2007................................ 5,118,053 2,441,124
2008................................ 190,249 172,005
2009................................ 576,433 183,463
Thereafter.......................... 2,744,002 2,103,167
----------- -----------
Total............................ 15,631,110 9,518,526
=========== ===========

- --------------
(a) Acres expiring are based on contractual lease maturities.
(b) Acres subject to expiration during 2005 include 1.8 million gross and net
acres in South Africa block 14, 1.7 million gross acres (.8 million net
acres) in Tunisia, 314 thousand gross and net acres in Gabon and 179
thousand gross acres (131 thousand net acres) in North America. The Company
may extend these leases prior to their expiration based upon 2005 planned
activities or for other business reasons. However, no assurance can be
given that such lease extensions will be granted. In certain of these
leases, the extension is only subject to the Company's election to extend
and the fulfillment of certain capital expenditure commitments. See
"Description of Properties" above for information regarding the Company's
drilling operations.

Drilling activities. The following table sets forth the number of gross and
net productive and dry hole wells in which the Company had an interest that were
drilled during the years ended December 31, 2004, 2003 and 2002. This
information should not be considered indicative of future performance, nor
should it be assumed that there was any correlation between the number of
productive wells drilled and the oil and gas reserves generated thereby or the
costs to the Company of productive wells compared to the costs of dry holes.

DRILLING ACTIVITIES

Gross Wells Net Wells
-------------------------- --------------------------
Year Ended December 31, Year Ended December 31,
-------------------------- --------------------------
2004 2003 2002 2004 2003 2002
------ ------ ------ ----- ------ ------

United States:
Productive wells:
Development................... 268 244 148 243.1 210.5 83.0
Exploratory................... 8 4 6 5.3 4.0 2.0
Dry holes:
Development................... 3 6 4 3.0 6.0 3.7
Exploratory................... 6 6 3 3.0 3.6 2.1
----- ----- ----- ----- ------ ------
285 260 161 254.4 224.1 90.8
----- ----- ----- ----- ------ ------
Argentina:
Productive wells:
Development................... 43 29 13 41.7 29.0 13.0
Exploratory................... 21 21 9 21.0 21.0 9.0
Dry holes:
Development................... 1 2 1 1.0 2.0 1.0
Exploratory................... 10 9 8 9.5 9.0 8.0
----- ----- ----- ----- ------ ------
75 61 31 73.2 61.0 31.0
----- ----- ----- ----- ------ ------
Canada:
Productive wells:
Development................... 3 7 13 3.0 7.0 10.4
Exploratory................... 27 16 9 24.5 14.9 9.0
Dry holes:
Development................... - 7 4 - 6.5 4.0
Exploratory................... 24 26 3 23.3 21.1 3.0
----- ----- ----- ----- ------ ------
54 56 29 50.8 49.5 26.4
----- ----- ----- ----- ------ ------
Africa:
Productive wells:
Development................... 2 1 4 .6 .3 1.6
Exploratory................... 2 1 4 1.4 .4 3.4
Dry holes:
Development................... - - - - - -
Exploratory................... 5 4 - 4.4 3.5 -
----- ----- ----- ----- ------ ------
9 6 8 6.4 4.2 5.0
----- ----- ----- ----- ------ ------
Total.......................... 423 383 229 384.8 338.8 153.2
===== ===== ===== ===== ====== ======
Success ratio (a)................. 88% 84% 90% 89% 85% 86%

- ---------------
(a) Represents the ratio of those wells that were successfully completed as
producing wells or wells capable of producing to total wells drilled and
evaluated.

24

The following table sets forth information about the Company's wells upon
which drilling was in progress as of December 31, 2004:

Gross Wells Net Wells
----------- ---------

United States:
Development................................... 32 28.7
Exploratory................................... 9 4.4
----- ------
41 33.1
----- ------
Argentina:
Development................................... 6 5.4
Exploratory................................... 8 7.4
----- ------
14 12.8
----- ------
Canada:
Development................................... 2 2.0
Exploratory................................... 21 17.0
----- ------
23 19.0
----- ------
Africa:
Development................................... - -
Exploratory................................... 2 .8
----- ------
2 .8
----- ------
Total....................................... 80 65.7
===== ======

ITEM 3. LEGAL PROCEEDINGS

The Company is party to various legal proceedings, which are described
under "Legal actions" in Note J of Notes to Consolidated Financial Statements
included in "Item 8. Financial Statements and Supplementary Data". The Company
is also party to other litigation incidental to its business. Except for the
specific legal actions described in Note J of Notes to Consolidated Financial
Statements included in "Item 8. Financial Statements and Supplemental Data", the
Company believes that the probable damages from such other legal actions will
not be in excess of 10 percent of the Company's current assets.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

The Company did not submit any matters to a vote of security holders during
the fourth quarter of 2004.

PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON STOCK, RELATED STOCKHOLDER
MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

The Company's common stock is listed and traded on the NYSE under the
symbol "PXD". The following table sets forth, for the periods indicated, the
high and low sales prices for the Company's common stock, as reported in the
NYSE composite transactions. The Company's board of directors declared dividends
to the holders of the Company's common stock of $.20 per share during the year
ended December 31, 2004. On February 17, 2005, the Company's board of directors
declared a cash dividend on common stock of $.10 per share, payable on April 15,
2005 to stockholders of record on March 31, 2005. The Company's board of
directors did not declare dividends to the holders of the Company's common stock
during the year ended December 31, 2003.

25

The following table sets forth quarterly high and low prices of the
Company's common stock and dividends declared per share for the years ended
December 31, 2004 and 2003:

Dividends
Declared
High Low Per Share
------- ------- ---------

Year ended December 31, 2004:
Fourth quarter.............................. $ 36.85 $ 30.80 $ -
Third quarter............................... $ 37.50 $ 31.03 $ .10
Second quarter.............................. $ 35.18 $ 29.27 $ -
First quarter............................... $ 34.68 $ 29.60 $ .10

Year ended December 31, 2003:
Fourth quarter.............................. $ 32.90 $ 25.00 $ -
Third quarter............................... $ 26.52 $ 22.76 $ -
Second quarter.............................. $ 28.44 $ 22.85 $ -
First quarter............................... $ 27.44 $ 23.27 $ -

On February 18, 2005, the last reported sales price of the Company's common
stock, as reported in the NYSE composite transactions, was $40.11 per share.

As of February 18, 2005, the Company's common stock was held by
approximately 26,600 registered holders of record.

Securities Authorized for Issuance under Equity Compensation Plans

The following table summarizes information about the Company's equity
compensation plans as of December 31, 2004:

(b)
Number of securities
(a) remaining available
Number of for future issuance
securities to be under equity
issued upon Weighted average compensation plans
exercise of exercise price of (excluding securities
outstanding options outstanding options reflected in first column)
------------------- ------------------- -------------------------

Equity compensation plans approved by
security holders (c):
Pioneer Natural Resources Company:
Long-Term Incentive Plan............. 3,514,559 $ 20.19 8,307,237
Employee Stock Purchase Plan......... - $ - 557,335
Predecessor plans...................... 1,666,025 $ 15.26 -
--------- ----------
5,180,584 8,864,572
========= ==========

- ---------------

(a) There are no outstanding warrants or equity rights awarded under the
Company's equity compensation plans. The securities do not include
restricted stock awarded under the Company's Long-Term Incentive Plan.
(b) The Company's Long-Term Incentive Plan provides for the issuance of a
maximum number of shares of common stock equal to 10 percent of the total
number of shares of common stock equivalents outstanding less the total
number of shares of common stock subject to outstanding awards under any
stock-based plan for the directors, officers or employees of the Company.
The number of remaining securities available for future issuance under the
Company's Employee Stock Purchase Plan is based on the original authorized
issuance of 750,000 shares less 192,665 cumulative shares issued through
December 31, 2004. See Note H of Notes to Consolidated Financial Statements
included in "Item 8. Financial Statements and Supplementary Data" for a
description of each of the Company's equity compensation plans.
(c) There are no equity compensation plans that have not been approved by
security holders.

26

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

The following table summarizes the Company's purchases of treasury stock
during the three months ended December 31, 2004:

Total Number of Shares
(or Units) Purchased
Total Number of Average Price as Part of Publicly
Shares (or Units) Paid per Share Announced Plans
Period Purchased (or Unit) or Programs
------ ----------------- -------------- ----------------------

October 2004................ 300,000 $ 33.173 300,000
November 2004............... 556,500 $ 33.030 556,500
December 2004............... 798,600 $ 34.331 798,600
----------- ----------
Total............... 1,655,100 $ 33.684 1,655,100
=========== ==========

During December 2003, the Company's board of directors approved a $200
million share repurchase program. During January 2005, the Company's board of
directors terminated the $200 million share repurchase program and approved a
new share repurchase program authorizing the purchase of up to $300 million of
the Company's common stock.

27

ITEM 6. SELECTED FINANCIAL DATA

The following selected consolidated financial data as of and for each of
the five years ended December 31, 2004 for the Company should be read in
conjunction with "Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations" and "Item 8. Financial Statements and
Supplementary Data".

Year Ended December 31,
--------------------------------------------------------
2004 2003 2002 2001 2000
-------- -------- -------- -------- --------
(in millions, except per share data)

Statements of Operations Data:
Revenues and other income:
Oil and gas (a)............................ $1,832.7 $1,273.9 $ 694.4 $ 831.7 $ 822.9
Interest and other......................... 14.1 12.3 11.2 21.8 25.8
Gain on disposition of assets, net......... - 1.3 4.4 7.7 34.2
------- ------- ------- ------- -------
1,846.8 1,287.5 710.0 861.2 882.9
------- ------- ------- ------- -------
Costs and expenses:
Oil and gas production (a)................. 345.5 254.8 192.1 194.4 159.5
Depletion, depreciation and amortization... 574.9 390.8 216.4 222.6 214.9
Impairment of oil and gas properties (b)... 39.7 - - - -
Exploration and abandonments............... 181.7 132.8 85.9 127.9 87.5
General and administrative................. 80.5 60.5 48.4 37.0 33.3
Accretion of discount on asset retirement
obligations (c).......................... 8.2 5.0 - - -
Interest................................... 103.4 91.4 95.8 131.9 162.0
Other (d).................................. 33.7 21.4 39.6 43.4 79.5
------- ------- ------- ------- -------
1,367.6 956.7 678.2 757.2 736.7
------- ------- ------- ------- -------
Income before income taxes and cumulative
effect of change in accounting principle... 479.2 330.8 31.8 104.0 146.2
Income tax benefit (provision) (e)........... (166.3) 64.4 (5.1) (4.0) 6.0
------- ------- ------- ------- -------
Income before cumulative effect of change
in accounting principle.................... 312.9 395.2 26.7 100.0 152.2
Cumulative effect of change in accounting
principle, net of tax (c).................. - 15.4 - - -
------- ------- ------- ------- -------
Net income................................... $ 312.9 $ 410.6 $ 26.7 $ 100.0 $ 152.2
======= ======= ======= ======= =======
Income before cumulative effect of change in
accounting principle per share:
Basic.................................... $ 2.50 $ 3.37 $ .24 $ 1.01 $ 1.53
======= ======= ======= ======= =======
Diluted.................................. $ 2.46 $ 3.33 $ .23 $ 1.00 $ 1.53
======= ======= ======= ======= =======
Net income per share:
Basic.................................... $ 2.50 $ 3.50 $ .24 $ 1.01 $ 1.53
======= ======= ======= ======= =======
Diluted.................................. $ 2.46 $ 3.46 $ .23 $ 1.00 $ 1.53
======= ======= ======= ======= =======
Weighted average shares outstanding:
Basic...................................... 125.2 117.2 112.5 98.5 99.4
======= ======= ======= ======= =======
Diluted.................................... 127.5 118.5 114.3 99.7 99.8
======= ======= ======= ======= =======
Dividends declared per share................. $ .20 $ - $ - $ - $ -
======= ======= ======= ======= =======
Balance Sheet Data (as of December 31):
Total assets................................. $6,647.2 $3,951.6 $3,455.1 $3,271.1 $2,954.4
Long-term obligations and minority interests. $3,271.0 $1,762.0 $1,805.6 $1,757.5 $1,833.0
Total stockholders' equity................... $2,831.8 $1,759.8 $1,374.9 $1,285.4 $ 904.9

- ---------------

(a) Certain amounts for periods prior to January 1, 2004 have been reclassified
to conform with the current year presentation. See Note B of Notes to
Consolidated Financial Statements included in "Item 8. Financial Statements
and Supplemental Data" for additional discussion.
(b) During 2004, the Company recorded a $39.7 million impairment charge for its
Gabonese Olowi field as development of the discovery was canceled due to
significant increases in projected field development costs. See Note T of
Notes to Consolidated Financial Statements included in "Item 8. Financial
Statements and Supplementary Data".
(c) Cumulative effect of change in accounting principle for 2003 relates to the
adoption of SFAS No. 143 on January 1, 2003. Associated therewith, the
Company recorded accretion of discount on asset retirement obligations in
accordance with SFAS No. 143 during 2004 and 2003. See Notes B and M of
Notes to Consolidated Financial Statements included in "Item 8. Financial
Statements and Supplementary Data".
(d) Other expense for 2003, 2002, 2001 and 2000 include losses on the early
extinguishment of debt of $1.5 million, $22.3 million, $3.8 million and
$12.3 million, respectively. Other expense for 2001 and 2000 include
noncash mark-to-market charges for changes in the fair values of non-hedge
financial instruments of $11.5 million and $58.5 million, respectively. See
Note P of Notes to Consolidated Financial Statements included in "Item 8.
Financial Statements and Supplementary Data".
(e) Income tax benefit for 2003 includes a $197.7 million adjustment to reduce
United States deferred tax asset valuation allowances. See Note Q of Notes
to Consolidated Financial Statements included in "Item 8. Financial
Statements and Supplementary Data".

28

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS

2004 Highlights and Events

Pioneer's financial and operating performance for the year ended December
31, 2004 included the following highlights and events:

o Average daily sales volumes on a BOE basis increased 21 percent in
2004 as compared to 2003, principally due to a full year of
production from the Falcon and Sable development projects, new
production being initiated from the Harrier, Raptor and Tomahawk
fields in the Falcon area and at Devils Tower and fourth quarter
production added from the Evergreen merger.
o Oil and gas revenues increased 44 percent in 2004 as a result of
the increased production volumes and increases in worldwide oil
and gas prices.
o Income before income taxes and cumulative effect of change in
accounting principle increased by 45 percent to $479.2 million
from $330.8 million in 2003.
o Net cash provided by operating activities increased by 45 percent
to a record $1.1 billion as compared to $763.7 million in 2003.
o The Company's capital investment programs resulted in total proved
reserves of 1.0 billion BOE at December 31, 2004.
o The declaration of $.20 per share of common dividends.
o A $39.7 million impairment charge ($12.8 million net of tax
benefits) as a result of the decision to cancel Gabonese Olowi
field development plans. See Note T of Notes to Consolidated
Financial Statements included in "Item 8. Financial Statements and
Supplementary Data" for more information pertaining to this
matter.
o Partial loss of third and fourth quarter production at Devils
Tower and Canyon Express from Hurricane Ivan which struck on
September 15, 2004 and related damages.
o The 2004 repurchase of 2.8 million shares of the Company's common
stock for $92 million.

During 2004, the Company also announced the following financial and
operating achievements:

o Rating agencies upgrade of the Company to investment grade status
in response to improved financial position and earnings trends,
along with other factors specific to the Company.
o Merger with Evergreen. See Note C of Notes to Consolidated
Financial Statements included in "Item 8. Financial Statements and
Supplementary Data" and "Evergreen Merger" below for information
regarding this business combination.
o The exchange of portions of the Company's higher-yielding senior
notes for 5.875% senior notes due 2016 (the "New Notes") and cash.
See Note F of Notes to Consolidated Financial Statements included
in "Item 8. Financial Statements and Supplementary Data" and
"Capital Commitments, Capital Resources and Liquidity" below for
information regarding this $526.8 million debt exchange that was
completed in July 2004.
o Completion of the first amendment (the "First Amendment") to the
Company's $700 million, five-year revolving credit agreement (the
"Revolving Credit Agreement") which removed Pioneer Natural
Resources USA, Inc., a wholly-owned subsidiary of the Company
("Pioneer USA"), as a guarantor of the Revolving Credit Agreement
and had the effect of removing Pioneer USA as a guarantor of the
Company's senior notes. See Note F of Notes to Consolidated
Financial Statements included in "Item 8. Financial Statements and
Supplementary Data" for information regarding the First Amendment.
o Completion of a successful appraisal well in the Hawa area in the
Adam production concession onshore southern Tunisia.
o First production from the Company's deepwater Gulf of Mexico
Harrier field during January 2004, the Devils Tower field during
May 2004 and the Raptor and Tomahawk fields during June 2004.
o The acquisition of a 50 percent interest in Block H offshore
Equatorial Guinea, West Africa.
o The announced agreement to participate in a joint exploration
program with ConocoPhillips and Anadarko Petroleum Corporation in
the National Petroleum Reserve on the North Slope of Alaska.

29

2004 Financial and Operating Performance

During the years ended December 31, 2004, 2003 and 2002, the Company
recorded net income of $312.9 million, $410.6 million and $26.7 million ($2.46,
$3.46 and $.23 per diluted share), respectively. Compared to 2003, the Company's
2004 total revenues and other income increased by $559.4 million, or 43 percent,
including a $558.8 million increase in oil and gas revenues. The increase in oil
and gas revenues was due to increases in production volumes and increases of 23
percent, 32 percent and 13 percent in average oil, NGL and gas prices,
respectively, including the effects of commodity price hedges.

Compared to 2003, the Company's total costs and expenses increased by
$410.9 million, or 43 percent, during the year ended December 31, 2004. The
increase in total costs and expenses was primarily reflective of a $184.0
million increase in depletion, depreciation and amortization ("DD&A") expense,
primarily driven by increases in depletion associated with increased production
volumes from higher-cost-basis deepwater Gulf of Mexico and South Africa
properties, a $90.8 million increase in oil and gas production costs, which
primarily resulted from increases in production volumes, the strengthening of
both the Argentine peso and Canadian dollar and commodity prices that impacted
variable lease operating expenses and production taxes, a $48.9 million increase
in exploration and abandonments expense primarily due to increased
exploration/extension drilling in the Gulf of Mexico, Argentina, Canada and
Gabon and a $39.7 million impairment charge on the Company's Gabonese
properties.

During the year ended December 31, 2004, the Company's net cash provided by
operating activities increased to $1.1 billion, as compared to $763.7 million
during 2003 and $332.2 million during 2002. The 45 percent increase in net cash
provided by operating activities during 2004 was primarily due to increases in
production volumes and commodity prices, as discussed above.

During the year ended December 31, 2004, successful capital investment
activities increased the Company's proved reserves to 1.0 billion BOE,
reflecting the effects of the Evergreen merger, strategic acquisitions of
property interests in the Company's core operating areas and the Company's 2004
drilling program. Costs incurred for the year ended December 31, 2004 totaled
$3.2 billion, including $2.6 billion of proved and unproved property
acquisitions, $557.2 million of exploration and development drilling and seismic
expenditures and $15.1 million of asset retirement obligations. Costs incurred
for the year ended December 31, 2004 include $2.5 billion of costs to acquire
Evergreen's oil and gas properties.

See "Results of Operations" and "Capital Commitments, Capital Resources and
Liquidity", below, for more in- depth discussions of the Company's oil and gas
producing activities, including discussions pertaining to oil and gas production
volumes, prices, hedging activities, costs and expenses, capital commitments,
capital resources and liquidity.

Evergreen Merger

On September 28, 2004, Pioneer completed its merger with Evergreen. Pioneer
acquired the common stock of Evergreen for a total purchase price of
approximately $1.8 billion, which was comprised of cash and Pioneer common
stock. At the merger date, Evergreen's proved reserves were approximately 262.2
MMBOE. Evergreen was a publicly- traded independent oil and gas company
primarily engaged in the production, development, exploration and acquisition of
North American unconventional gas. Evergreen was based in Denver, Colorado and
was one of the leading developers of CBM reserves in the United States.
Evergreen's operations were principally focused on developing and expanding its
CBM gas field located in the Raton Basin in southern Colorado. Evergreen also
had operations in the Piceance Basin in western Colorado, the Uinta Basin in
eastern Utah and the Western Canada Sedimentary Basin. See Note C of Notes to
Consolidated Financial Statements included in "Item 8. Financial Statements and
Supplementary Data" for more information regarding the Evergreen merger.

2005 Outlook and Activities

Volumetric production payments. During January 2005, the Company sold two
percent of its total proved reserves, or 20.5 million BOE of proved reserves, by
means of two volumetric production payments ("VPPs") for total proceeds of $593
million and the assumption of the Company's obligations under certain derivative
hedge agreements. Proceeds from the VPPs were initially used to pay down
indebtedness.

30

The VPPs represent limited term overriding royalty interests in oil and gas
reserves which: (i) entitle the purchaser to receive production volumes over a
period of time from specific lease interests; (ii) are free and clear of all
associated future production costs and capital expenditures; (iii) are
nonrecourse to the Company (i.e., the purchaser's only recourse is to the assets
acquired); (iv) transfers title to the purchaser and (v) allows the Company to
retain the assets after the VPP's volumetric obligations have been satisfied.

The first VPP sells 58 Bcf of Hugoton field gas volumes over an expected
five-year term beginning in February 2005 for $275 million of proceeds. The
second VPP sells 10.8 MMBOE of Spraberry field oil volumes over an expected
seven-year term beginning in January 2006 for $318 million of proceeds.

A VPP is considered a sale of proved reserves and the related future
production of those proved reserves. As a result the Company will (i) remove the
proved reserves associated with the VPPs; (ii) recognize the VPP proceeds as
deferred revenue which will be amortized on a unit-of-production basis to future
oil and gas revenues over the terms of the VPPs; (iii) retain responsibility for
100 percent of the production costs and capital costs related to VPP interests
and (iv) no longer recognize production associated with the VPP volumes,
resulting in higher future revenue per BOE, production costs per BOE and DD&A
per BOE ratios.

The Company will amortize to oil and gas revenues $62.9 million of net
deferred gas revenue during 2005 associated with the Hugoton field VPP. During
2006, the Company will amortize $57.6 million of net deferred gas revenue
associated with the Hugoton field VPP and $53.7 million of net deferred oil
revenue associated with the Spraberry field VPP.

Commodity prices. World oil prices increased during the year ended December
31, 2004 in response to political unrest and supply disruptions in Iraq and
Venezuela as well as other supply and demand factors. North American gas prices
also increased during 2004 in response to continued strong supply and demand
fundamentals. The Company's outlook for 2005 commodity prices continues to be
cautiously optimistic. Significant factors that will impact 2005 commodity
prices include developments in Iraq and other Middle East countries, the extent
to which members of the OPEC and other oil exporting nations are able to manage
oil supply through export quotas and variations in key North American gas supply
and demand indicators. Pioneer will continue to strategically hedge oil and gas
price risk to mitigate the impact of price volatility on its oil, NGL and gas
revenues.

See Note K of Notes to Consolidated Financial Statements included in "Item
8. Financial Statements and Supplementary Data" for additional information
regarding the Company's commodity hedge positions at December 31, 2004. Also see
"Item 7A. Quantitative and Qualitative Disclosures About Market Risk" for
disclosures about the Company's commodity related derivative financial
instruments.

Capital expenditures. During 2005, the Company's budget for oil and gas
capital activities is expected to range from $900 million to $950 million, of
which approximately 75 percent has been budgeted for lower-risk development and
extension drilling and facility costs and 25 percent for exploration
expenditures. The Company's 2005 capital budget is allocated approximately 75
percent to the United States, 15 percent to Argentina and five percent to each
of Africa and Canada. Pioneer expects to drill approximately 800 exploration and
development wells during 2005. During 2005 and 2006, the Company expects to
expend approximately $394 million and $348 million, respectively, of capital for
development drilling and facility costs related to its proved undeveloped
reserves.

Production growth. The Company expects that its annual 2005 worldwide
production will range from 70 MMBOE to 74 MMBOE, or approximately 192 MBOE to
203 MBOE per day. The forecasted range includes a full year of production from
the assets acquired in the Evergreen merger and has been reduced by the VPP
volumes sold during January 2005. The Company expects, based on quoted futures
prices, to generate cash flow significantly in excess of its capital program
which will further enhance the Company's financial flexibility to fund the
development of future exploration successes, core area acquisitions and
additional development drilling.

With several discoveries in various stages of commercialization, a pipeline
of exploration opportunities, the potential for continued core area
acquisitions, continuing strong commodity prices and significant excess cash
flow, Pioneer has targeted five-year average compounded annual production growth
of eight percent to nine percent or ten percent per share, giving consideration
to contemplated share repurchases.

31

Costs and expenses. The Company expects that its costs and expenses that
are highly correlated with production volumes, such as production costs and
depletion expense, will increase in absolute amounts during 2005 and that
production costs, depreciation, depletion and amortization expense and other
costs and expenses will increase on a per BOE basis as a result of the sale of
proved reserves through the VPPs. Additionally, the Company expects that
depletion expense will increase on a per BOE basis during 2005 as compared to
2004 due to increased production from the Devils Tower oil field in the
deepwater Gulf of Mexico and the assets acquired in the Evergreen merger. The
per BOE cost basis of these fields is higher than that of Pioneer's average
producing property in 2004. Ad valorem taxes are highly correlated with prior
year commodity prices. As a consequence of increases in oil, NGL and gas prices
during 2004, ad valorem taxes are expected to be higher in 2005, as compared to
2004. The Company also anticipates an increase in general and administrative
expenses during 2005 due to additional staffing associated with the Evergreen
merger and anticipated Company growth, as well as the amortization of deferred
compensation associated with unvested restricted stock and stock options.

Capital allocation. During 2004, the Company improved its financial
position and achieved investment grade standards. The Company is now targeting
mid-investment grade ratings. Towards that end, the Company established a
targeted range for debt to book capitalization of less than 35 percent by the
end of 2005, as further discussed later. During 2004, the Company paid dividends
of $.20 per common share in two semiannual installments of $.10 per common
share, and the Company currently expects to, as a minimum, maintain this level
of dividends in 2005.

During 2005 through 2007, the Company anticipates, based upon year-end
futures prices, that it will have significant excess cash flow after funding its
typical annual capital budgets, planned dividends and achieving its leverage
targets. The Company considers it a high priority to utilize a portion of the
excess cash flow to fund the development of new exploration successes and to
selectively acquire additional assets in its core areas. The Company will also
use a portion of the excess cash flow for share repurchases, pursuant to the
recently approved $300 million stock repurchase program.

First quarter 2005. Based on current estimates, the Company expects that
first quarter 2005 production will average 175,000 to 190,000 BOE per day. This
range is lower than the fourth quarter average reflecting the VPP volumes sold,
more days of downtime and a gradual ramp up of production for the Canyon Express
system which has been undergoing repairs, the timing of oil cargo shipments in
Tunisia and South Africa which were high during the fourth quarter, and the
typical seasonal decline in gas demand during Argentina's summer season.

First quarter production costs (including production and ad valorem taxes)
are expected to average $6.00 to $6.50 per BOE based on current NYMEX strip
prices for oil and gas. The increase over the prior quarter is a result of the
retention of operating costs related to the VPP volumes sold, an increase in
production and ad valorem taxes and additional workovers planned during the
Canadian winter access season. Production costs are expected to decline in the
second quarter of 2005 as lower-cost volumes resume from the deepwater Gulf of
Mexico and workovers return to more normal levels. Depreciation, depletion and
amortization expense is expected to average $8.75 to $9.25 per BOE.

Total exploration and abandonment expense is expected to be $80 million to
$110 million. Several higher-risk exploration wells and significant seismic
investments are planned during the first quarter, serving to front-end load the
Company's 2005 exploration program. Specifically, first quarter exploration
activity is expected to include an appraisal well to the 2004 Thunder Hawk
discovery and an exploration well on a Falcon Corridor satellite prospect in the
deepwater Gulf of Mexico. In Alaska, as many as three wells are expected to test
new exploration targets and Pioneer plans to shoot seismic over newly acquired
acreage. One well is planned in West Africa and lower-risk exploration and
geologic and geophysical work will also continue in Argentina, Canada and
Tunisia. General and administrative expense is expected to be $24 million to $26
million. Interest expense is expected to be $33 million to $36 million, and
accretion of discount on asset retirement obligations is expected to be
approximately $2 million to $3 million.

The Company's effective income tax rate is expected to range from 36
percent to 39 percent based on current capital spending plans, including cash
income taxes of $5 million to $10 million that are principally related to
Argentine and Tunisian income taxes and nominal alternative minimum tax in the
U.S. Other than in Argentina and Tunisia, the Company continues to benefit from
the carryforward of net operating losses and other positive tax attributes.

32

Debt reduction target. Although the Evergreen merger has resulted in an
increase in the Company's ratio of debt to book capitalization, the Company has
targeted a ratio of debt to book capitalization of less than 35 percent by the
end of 2005. To achieve this target, the Company plans to apply a portion of the
proceeds from the 2005 VPPs and the divestiture of certain Canadian assets for
expected proceeds of over $100 million to reduce debt. In addition, the Company
expects cash flows to be significantly in excess of the 2005 capital program
based on current commodity prices which can be used to further reduce debt.

Field Fuel Reporting

During the fourth quarter of 2004, the Company completed a voluntary
internal review of the various accounting treatments related to field fuel costs
used by major oil companies and other independents in order to determine common
industry practice. The review, in part, was undertaken in response to the large
volume of field fuel usage related to the assets acquired from Evergreen. Field
fuel is gas consumed to operate field equipment (primarily compressors) prior to
the gas being delivered to a sales point.

Pioneer has historically recorded the value of field fuel as an operating
expense with an equal amount recorded as oil and gas revenues, with no net
income effect. Pioneer also reflected the volumes associated with field fuel in
gas production. This practice has been routinely discussed by the Company,
especially in relation to the rising value of the fuel used in the field and its
contribution to rising field operating expenses.

Although the Company believes that its past treatment of field fuel was
acceptable, the Company changed its reporting of field fuel, no longer recording
it as revenue or expense and not including it as production. Pioneer believes
this presentation is more common in the industry and will provide a better basis
for comparing Pioneer to other oil and gas companies. Within this Report, the
Company has adjusted its prior period revenues, production costs and sales
volumes to reflect the new method of reporting field fuel. The change in
reporting field fuel did not change reported net income of the periods presented
since revenues and production costs were changed in equal amounts.

Critical Accounting Estimates

The Company prepares its consolidated financial statements for inclusion in
this Report in accordance with GAAP. See Note B of Notes to Consolidated
Financial Statements included in "Item 8. Financial Statements and Supplementary
Data" for a comprehensive discussion of the Company's significant accounting
policies. GAAP represents a comprehensive set of accounting and disclosure rules
and requirements, the application of which requires management judgments and
estimates including, in certain circumstances, choices between acceptable GAAP
alternatives. Following is a discussion of the Company's most critical
accounting estimates, judgments and uncertainties that are inherent in the
Company's application of GAAP.

Accounting for oil and gas producing activities. The accounting for and
disclosure of oil and gas producing activities requires the Company's management
to choose between GAAP alternatives and to make judgments about estimates of
future uncertainties.

Successful efforts method of accounting. The Company utilizes the
successful efforts method of accounting for oil and gas producing activities as
opposed to the alternate acceptable full cost method. In general, the Company
believes that, during periods of active exploration, net assets and net income
are more conservatively measured under the successful efforts method of
accounting for oil and gas producing activities than under the full cost method.
The critical difference between the successful efforts method of accounting and
the full cost method is as follows: under the successful efforts method,
exploratory dry holes and geological and geophysical exploration costs are
charged against earnings during the periods in which they occur; whereas, under
the full cost method of accounting, such costs and expenses are capitalized as
assets, pooled with the costs of successful wells and charged against the
earnings of future periods as a component of depletion expense. During the years
ended December 31, 2004, 2003 and 2002, the Company recognized exploration,
abandonment, geological and geophysical expense of $181.7 million, $132.8
million and $85.9 million, respectively, under the successful efforts method.

Proved reserve estimates. Estimates of the Company's proved reserves
included in this Report are prepared in accordance with GAAP and SEC guidelines.
The accuracy of a reserve estimate is a function of:

33

o the quality and quantity of available data,
o the interpretation of that data,
o the accuracy of various mandated economic assumptions and
o the judgment of the persons preparing the estimate.

The Company's proved reserve information included in this Report as of
December 31, 2004, 2003 and 2002 was audited by independent petroleum engineers
with respect to the Company's major properties and prepared by the Company's
engineers with respect to all other properties. Estimates prepared by third
parties may be higher or lower than those included herein.

Because these estimates depend on many assumptions, all of which may
substantially differ from future actual results, reserve estimates will be
different from the quantities of oil and gas that are ultimately recovered. In
addition, results of drilling, testing and production after the date of an
estimate may justify, positively or negatively, material revisions to the
estimate of proved reserves.

It should not be assumed that the present value of future net cash flows
included in this Report as of December 31, 2004 is the current market value of
the Company's estimated proved reserves. In accordance with SEC requirements,
the Company based the estimated present value of future net cash flows from
proved reserves on prices and costs on the date of the estimate. Actual future
prices and costs may be materially higher or lower than the prices and costs as
of the date of the estimate.

The Company's estimates of proved reserves materially impact depletion
expense. If the estimates of proved reserves decline, the rate at which the
Company records depletion expense will increase, reducing future net income.
Such a decline may result from lower market prices, which may make it
uneconomical to drill for and produce higher cost fields. In addition, a decline
in proved reserve estimates may impact the outcome of the Company's assessment
of its oil and gas producing properties and goodwill for impairment.

Impairment of proved oil and gas properties. The Company reviews its
long-lived proved properties to be held and used whenever management determines
that events or circumstances indicate that the recorded carrying value of the
properties may not be recoverable. Management assesses whether or not an
impairment provision is necessary based upon its outlook of future commodity
prices and net cash flows that may be generated by the properties and if a
significant downward revision has occurred to the estimated proved reserves.
Proved oil and gas properties are reviewed for impairment at the level at which
depletion of proved properties is calculated.

Impairment of unproved oil and gas properties. Management periodically
assesses unproved oil and gas properties for impairment, on a project-by-project
basis. Management's assessment of the results of exploration activities,
commodity price outlooks, planned future sales or expiration of all or a portion
of such projects impact the amount and timing of impairment provisions, if any.

Suspended wells. The Company suspends the costs of exploratory wells that
discover hydrocarbons pending a final determination of the commercial potential
of the oil and gas discovery. The ultimate disposition of these well costs is
dependent on the results of future drilling activity and development decisions.
If the Company decides not to pursue additional appraisal activities or
development of these fields, the costs of these wells will be charged to
exploration and abandonment expense.

The Company generally does not carry the costs of drilling an exploratory
well as an asset in its Consolidated Balance Sheets for more than one year
following the completion of drilling unless the exploratory well finds oil and
gas reserves in an area requiring a major capital expenditure and both of the
following conditions are met:

(i) The well has found a sufficient quantity of reserves to justify
its completion as a producing well if the required capital
expenditure is made.
(ii) Drilling of the additional exploratory wells is under way or
firmly planned for the near future.

Due to the capital intensive nature and the geographical location of certain
Alaskan, deepwater Gulf of Mexico and foreign projects, it may take the Company
longer than one year to evaluate the future potential of the exploration well

34

and economics associated with making a determination on its commercial
viability. In these instances, the projects feasibility is not contingent upon
price improvements or advances in technology, but rather the Company's ongoing
efforts and expenditures related to accurately predicting the hydrocarbon
recoverability based on well information, gaining access to other companies
production, transportation or processing facilities and/or getting partner
approval to drill additional appraisal wells. These activities are ongoing and
being pursued constantly. Consequently, the Company's assessment of suspended
exploratory well costs is continuous until a decision can be made that the well
has found proved reserves or is noncommercial and is impaired. See Note D of
Notes to Consolidated Financial Statements included in "Item 8. Financial
Statements and Supplementary Data" for additional information regarding the
Company's suspended exploratory well costs.

Assessments of functional currencies. Management determines the functional
currencies of the Company's subsidiaries based on an assessment of the currency
of the economic environment in which a subsidiary primarily realizes and expends
its operating revenues, costs and expenses. The U.S. dollar is the functional
currency of all of the Company's international operations except Canada. The
assessment of functional currencies can have a significant impact on periodic
results of operations and financial position.

Argentine economic and currency measures. The accounting for and
remeasurement of the Company's Argentine balance sheets as of December 31, 2004
and 2003 reflect management's assumptions regarding some uncertainties unique to
Argentina's current economic situation. The Argentine economic and political
situation continues to evolve and the Argentine government may enact future
regulations or policies that, when finalized and adopted, may materially impact,
among other items, (i) the realized prices the Company receives for the
commodities it produces and sells; (ii) the timing of repatriations of excess
cash flow to the Company's corporate headquarters in the United States; (iii)
the Company's asset valuations; and (iv) peso-denominated monetary assets and
liabilities. See "Item 7A. Quantitative and Qualitative Disclosures About Market
Risk" and Note B of Notes to Consolidated Financial Statements included in "Item
8. Financial Statements and Supplementary Data" for a description of the
assumptions utilized in the preparation of these financial statements.

Deferred tax asset valuation allowances. The Company continually assesses
both positive and negative evidence to determine whether it is more likely than
not that its deferred tax assets will be realized prior to their expiration.
Pioneer monitors Company-specific, oil and gas industry and worldwide economic
factors and reassesses the likelihood that the Company's net operating loss
carryforwards and other deferred tax attributes in each jurisdiction will be
utilized prior to their expiration. There can be no assurances that facts and
circumstances will not materially change and require the Company to establish a
United States deferred tax asset valuation allowance in a future period. As of
December 31, 2004, the Company does not believe there is sufficient positive
evidence to reverse its valuation allowances related to foreign tax
jurisdictions.

Goodwill impairment. The Company will review its goodwill for impairment at
least annually. This requires the Company to estimate the fair value of the
assets and liabilities of the reporting units that have goodwill. There is
considerable judgment involved in estimating fair values, particularly proved
reserve estimates as described above.

Litigation and environmental contingencies. The Company makes judgments and
estimates in recording liabilities for ongoing litigation and environmental
remediation. Actual costs can vary from such estimates for a variety of reasons.
The costs to settle litigation can vary from estimates based on differing
interpretations of laws and opinions and assessments on the amount of damages.
Similarly, environmental remediation liabilities are subject to change because
of changes in laws, regulations, additional information obtained relating to the
extent and nature of site contamination and improvements in technology. Under
GAAP, a liability is recorded for these types of contingencies if the Company
determines the loss to be both probable and reasonably estimated. See Note J of
Notes to Consolidated Financial Statements included in "Item 8. Financial
Statements and Supplementary Data" for additional information regarding the
Company's commitments and contingencies.

Results of Operations

Oil and gas revenues. Revenues from oil and gas operations totaled $1.8
billion during 2004, as compared to $1.3 billion during 2003 and $694.4 million
during 2002, representing a 44 percent increase from 2003 to 2004. The revenue
increase from 2003 to 2004 was due to a 21 percent increase in total BOE
production, a 23 percent increase in oil prices, a 32 percent increase in NGL

35

prices and a 13 percent increase in gas prices, including the effects of
commodity price hedges. The revenue increase from 2002 to 2003 was due to a 37
percent increase in BOE production, a 12 percent increase in oil prices, a 40
percent increase in NGL prices and a 49 percent increase in gas prices,
including the effects of commodity price hedges.

The following table provides average daily sales volumes, by geographic
area and in total, for the years ended December 31, 2004, 2003 and 2002:

Year ended December 31,
----------------------------------------
2004 2003 2002
--------- --------- ----------

Average daily sales volumes:
Oil (Bbls)
United States................................. 26,637 24,525 23,437
Argentina..................................... 8,534 8,687 7,984
Canada........................................ 137 111 124
Africa........................................ 11,676 1,981 -
--------- --------- ---------
Worldwide..................................... 46,984 35,304 31,545
========= ========= =========
NGLs (Bbls)
United States................................. 19,738 20,338 20,512
Argentina..................................... 1,546 1,318 696
Canada........................................ 917 906 946
--------- --------- ---------
Worldwide..................................... 22,201 22,562 22,154
========= ========= =========
Gas (Mcf)
United States................................. 521,839 423,013 211,502
Argentina..................................... 121,654 94,128 78,220
Canada........................................ 41,867 41,669 48,365
--------- --------- ---------
Worldwide..................................... 685,360 558,810 338,087
========= ========= =========
Total (BOE)
United States................................. 133,349 115,364 79,201
Argentina..................................... 30,356 25,694 21,716
Canada........................................ 8,031 7,962 9,131
Africa........................................ 11,676 1,981 -
--------- --------- ---------
Worldwide..................................... 183,412 151,001 110,048
========= ========= =========

Per BOE average daily production for 2004 as compared to 2003 increased by
16 percent in the United States, by 18 percent in Argentina, by one percent in
Canada and the Company realized first production from South Africa and Tunisia
during 2003. The increased production was principally attributable to a full
year of production from the Falcon area, new production being initiated from the
Harrier, Raptor and Tomahawk fields in the Falcon area and at Devils Tower,
fourth quarter production added from the Evergreen merger and to oil sales
having first been realized from the Company's Tunisian and South African oil
projects during August and October of 2003, respectively. Argentine oil and gas
sales volumes increased during 2004 primarily due to production volumes being
added from the Company's capital expenditures and higher oil and gas demand
during their summer season.

Per BOE average daily production for 2003 as compared to 2002 increased by
46 percent in the United States, by 18 percent in Argentina and the Company
realized first production from South Africa and Tunisia during 2003, while
average daily production for 2003 as compared to 2002 decreased by 13 percent in
Canada due to normal production decline rates. The increased production was
principally attributable to incremental gas production from the deepwater Gulf
of Mexico Canyon Express and Falcon area projects, initial oil production in
South Africa and Tunisia and increased oil and gas production in Argentina,
offset by normal production declines.

36

The following table provides average reported prices, including the results
of hedging activities, and average realized prices, excluding the results of
hedging activities, by geographic area and in total, for the years ended
December 31, 2004, 2003 and 2002:

Year ended December 31,
--------------------------------------
2004 2003 2002
-------- -------- ---------
>
Average reported prices:
Oil (per Bbl)
United States............................. $ 29.41 $ 25.25 $ 23.66
Argentina................................. $ 28.06 $ 25.62 $ 20.63
Canada.................................... $ 44.83 $ 29.10 $ 22.26
Africa.................................... $ 38.12 $ 29.52 $ -
Worldwide................................. $ 31.38 $ 25.59 $ 22.89
NGL (per Bbl)
United States............................. $ 25.07 $ 19.04 $ 13.77
Argentina................................. $ 29.91 $ 22.85 $ 14.56
Canada.................................... $ 30.87 $ 24.80 $ 16.77
Worldwide................................. $ 25.65 $ 19.50 $ 13.92
Gas (per Mcf)
United States............................. $ 5.15 $ 4.47 $ 3.16
Argentina................................. $ .66 $ .56 $ .48
Canada.................................... $ 4.64 $ 4.93 $ 3.41
Worldwide................................. $ 4.33 $ 3.84 $ 2.58
Average realized prices:
Oil (per Bbl)
United States............................. $ 39.59 $ 29.58 $ 23.85
Argentina................................. $ 29.82 $ 26.31 $ 20.33
Canada.................................... $ 44.83 $ 29.10 $ 22.26
Africa.................................... $ 38.71 $ 30.07 $ -
Worldwide................................. $ 37.61 $ 28.80 $ 22.95
NGL (per Bbl)
United States............................. $ 25.07 $ 19.04 $ 13.77
Argentina................................. $ 29.91 $ 22.85 $ 14.56
Canada.................................... $ 30.87 $ 24.80 $ 16.77
Worldwide................................. $ 25.65 $ 19.50 $ 13.92
Gas (per Mcf)
United States............................. $ 5.72 $ 4.92 $ 3.01
Argentina................................. $ .66 $ .56 $ .48
Canada.................................... $ 5.75 $ 5.30 $ 3.32
Worldwide................................. $ 4.83 $ 4.25 $ 2.52

Field fuel. As previously discussed, the Company changed its method of
reporting field fuel usage during the fourth quarter of 2004. Accordingly, the
gas revenues, production volumes and related per unit measures of all periods
presented have been adjusted in accordance with the new method of reporting
field fuel.

Hedging activities. The oil and gas prices that the Company reports are
based on the market price received for the commodities adjusted by the results
of the Company's cash flow hedging activities. The Company utilizes commodity
swap and collar contracts in order to (i) reduce the effect of price volatility
on the commodities the Company produces and sells, (ii) support the Company's
annual capital budgeting and expenditure plans and (iii) reduce commodity price
risk associated with certain capital projects. The effective portions of changes
in the fair values of the Company's commodity price hedges are deferred as
increases or decreases to stockholders' equity until the underlying hedged
transaction occurs. Consequently, changes in the effective portions of commodity
price hedges add volatility to the Company's reported stockholders' equity until
the hedge derivative matures or is terminated. See Note K of Notes to
Consolidated Financial Statements included in "Item 8. Financial Statements and
Supplementary Data" for information concerning the impact to oil and gas
revenues during the years ended December 31, 2004, 2003 and 2002 from the
Company's hedging activities, the Company's open hedge positions at December 31,
2004 and descriptions of the Company's hedge commodity derivatives. Also see
"Item 7A. Quantitative and Qualitative Disclosures About Market Risk" for
additional disclosures about the Company's commodity related derivative
financial instruments.

37

Argentine commodity prices. During 2002, the Argentine government
implemented a 20 percent tax on oil exports. During 2002 and 2003, the Company
exported approximately 29 percent and five percent, respectively, of its
Argentine oil production. Associated therewith, the Company incurred oil export
taxes of $2.2 million and $1.2 million for 2002 and 2003, respectively. During
2004, the Company did not export any of its Argentine oil production. The export
tax has also had the effect of decreasing internal Argentine oil revenues (not
only export revenues) by the taxes levied. The U.S. dollar equivalent value for
domestic Argentine oil sales (now paid in pesos) has generally moved toward
parity with the U.S. dollar-denominated export values, net of the export tax.
The adverse impact of this tax has been partially offset by the net cost savings
resulting from the devaluation of the peso on peso-denominated costs.

In January 2003, at the Argentine government's request, oil producers and
refiners agreed to cap amounts payable for certain domestic sales at $28.50 per
Bbl which remained in effect through April 2004. The producers and refiners
further agreed that the difference between the actual price and the capped price
would be payable once actual prices fall below the $28.50 cap. Subsequently the
terms were modified such that while the $28.50 per Bbl payable cap was in place,
the refiners would have no obligation to pay producers for sales values that
exceeded $36.00 per Bbl. Initially, the refiners and producers also agreed to
discount U.S. dollar-denominated oil prices at 90 percent prior to converting to
pesos at the current exchange rate for the purpose of invoicing and settling oil
sales to Argentine refiners. In May 2004, refiners and producers changed the
discount percentage from 90 percent for all price levels to 86 percent if West
Texas Intermediate ("WTI") was equal to or less than $36 per Bbl and 80 percent
if WTI exceeded $36 per Bbl. All the oil prices are adjusted for normal quality
differentials prior to applying the discount.

In 2004, it appeared probable that the price of world oil would remain
above the $28.50 cap for the foreseeable future. Given the uncertainty
surrounding the timing of when Argentine producers could expect to collect
balances outstanding from refiners, the Company ceased recognizing revenue and
began recording any excess between the actual sales price pursuant to its oil
sales contracts with Argentine refiners that were subject to the price
stabilization agreement and the $28.50 price cap as deferred revenue in the
balance sheet. At December 31, 2004, the Company had $5.0 million of deferred
revenue reflected in its balance sheet associated with the sales in excess of
the price cap. The decision by Argentine oil producers and refiners to not renew
the price stability agreement beyond April 30, 2004 does not terminate the
obligation of refiners to reimburse producers for balances that accumulated from
January 2003 through April 2004, if and when the price of WTI falls below
$28.50.

In May 2004, the Argentine government increased the export tax from 20
percent to 25 percent. This tax is applied on the sales value after the tax,
thus, the net effect of the 20 percent and 25 percent rates is 16.7 percent and
20 percent, respectively. In August 2004, the Argentine government further
increased the export tax rates for oil exports. The export tax now escalates
from the current 25 percent (20 percent effective rate) to a maximum rate of 45
percent (31 percent effective rate) of the realized value for exported barrels
as WTI prices per barrel increase from less than $32.00 to $45.00 and above. The
export tax is not deducted in the calculation of royalty payments and expires in
February 2007. Given the number of governmental changes during 2004 affecting
the realized price the Company receives for its oil sales, no specific
predictions can be made about the future of oil prices in Argentina, however, in
the short term, the Company expects Argentine oil realizations to be less than
oil realizations in the United States.

As a result of economic emergency law enacted by the Argentine government
in January 2002, the Company's gas prices, expressed in U.S. dollars, have also
fallen in proportion to the devaluation of the Argentine peso since the end of
2001 due to the pesofication of contracts and freezing of gas prices at the
wellhead required by that law. As a baseline, the Company's 2001 realized
Argentine gas price was $1.31 per Mcf as compared to $.48, $.56 and $.66 in
2002, 2003 and 2004, respectively.

The unfavorable gas price has acted to discourage gas development
activities and increased gas demand. Without development of gas reserves in
Argentina, supplies of gas in the country have declined, while demand for gas
has been increasing due to the resurgence of the Argentine economy and the
higher cost of alternative fuels. Recently, gas exports to Chile were curtailed
at the direction of the Argentine government and Argentina entered into an
agreement to import gas from Bolivia at prices starting at approximately $2.00
per Mcf (at the border), including transportation costs. In May 2004, pursuant
to a decree, the Argentine government approved measures to permit producers to
renegotiate gas sales contracts, excluding those that could affect small
residential customers, in accordance with scheduled price increases specified in
the decree. The wellhead prices in the decree rise from a current range of $.61
to $.78 per Mcf to a range of $.87 to $1.04 per Mcf after July 1, 2005,
depending on the region where the gas is produced. No further gas price

38

increases beyond July 2005 have been allowed for in the current decree. Other
than an expectation that gas prices will be permitted to increase gradually over
time, as has already been demonstrated by the governing authorities, no specific
predictions can be made about the future of gas prices in Argentina, however,
the Company expects Argentine gas realizations to be less than gas realizations
in the United States.

See "Item 7A. Quantitative and Qualitative Disclosures About Market Risk"
for further discussion of commodity prices in Argentina.

Interest and other income. The Company recorded interest and other income
totaling $14.1 million, $12.3 million and $11.2 during the years ended December
31, 2004, 2003 and 2002, respectively. The Company's interest and other income
was comprised of revenue that was not directly attributable to oil and gas
producing activities or oil and gas property divestitures. See Note N of Notes
to Consolidated Financial Statements included in "Item 8. Financial Statements
and Supplementary Data" for additional information regarding interest and other
income.

Gain on disposition of assets. During the years ended December 31, 2004,
2003 and 2002, the Company completed asset divestitures for net proceeds of $1.7
million, $35.7 million and $118.9 million, respectively. Associated therewith,
the Company recorded gains on disposition of assets of $39 thousand, $1.3
million and $4.4 million during the years ended December 31, 2004, 2003 and
2002, respectively.

The net cash proceeds from asset divestitures during the years ended
December 31, 2004, 2003 and 2002 were used, together with net cash flows
provided by operating activities, to fund additions to oil and gas properties
and to reduce outstanding indebtedness. See Note O of Notes to Consolidated
Financial Statements included in "Item 8. Financial Statements and Supplementary
Data" for additional information regarding asset divestitures.

Oil and gas production costs. The Company recorded production costs of
$345.5 million, $254.8 million and $192.1 million during the years ended
December 31, 2004, 2003 and 2002, respectively. In general, lease operating
expenses and workover expenses represent the components of oil and gas
production costs over which the Company has management control, while production
taxes and ad valorem taxes are directly related to commodity price changes.
Total production costs per BOE increased during the year ended December 31, 2004
by 11 percent as compared to 2003. The increase in total production costs per
BOE during 2004 as compared to 2003 is primarily attributable to increases in
production volumes and a greater proportion of those volumes coming from the
Sable oil field in South Africa, the Devils Tower oil and gas field in the
deepwater Gulf of Mexico and, to a lesser extent, the new production added with
the Evergreen merger which are higher operating cost properties.

Total production costs per BOE decreased during 2003 by three percent as
compared to 2002, primarily due to decreases in per BOE ad valorem taxes and
workover expenses, partially offset by increases in per BOE lease operating
expenses and production taxes. The increase in per BOE lease operating expenses
was due to the strengthening of both the Argentine peso and the Canadian dollar,
Argentine inflation and higher average lifting costs incurred on South African
Sable oil field production, while the increase in per BOE production taxes
primarily resulted from increases in North American gas prices and world oil
prices. The decrease in per BOE ad valorem taxes is primarily due to the
incremental production from the deepwater Gulf of Mexico, Argentina, South
Africa and Tunisia fields which are not subject to ad valorem taxes.

39

The following tables provide the components of the Company's total
production costs per BOE and total production costs per BOE by geographic area
for the years ended December 31, 2004, 2003 and 2002:

Year Ended December 31,
----------------------------------
2004 2003 2002
------- ------- -------

Lease operating expenses..................... $ 3.86 $ 3.42 $ 3.40
Taxes:
Ad valorem ................................ .42 .41 .56
Production................................. .64 .64 .56
Workover expenses............................ .23 .15 .26
------ ------ ------
Total production costs................. $ 5.15 $ 4.62 $ 4.78
====== ====== ======

Year Ended December 31,
----------------------------------
2004 2003 2002
------- ------- -------

Total production costs:
United States.............................. $ 5.11 $ 4.68 $ 5.23
Argentina.................................. $ 2.99 $ 2.78 $ 1.75
Canada..................................... $ 10.64 $ 9.92 $ 8.09
Africa..................................... $ 7.37 $ 3.99 $ -
Worldwide.................................. $ 5.15 $ 4.62 $ 4.78

As previously discussed, the Company changed its method of reporting field
fuel usage during the fourth quarter of 2004. Accordingly, the production costs
and related per unit measures of all presented periods have been adjusted in
accordance with the new method of reporting field fuel.

Depletion, depreciation and amortization expense. The Company's total DD&A
expense was $8.56, $7.09 and $5.39 per BOE for the years ended December 31,
2004, 2003 and 2002, respectively. Depletion expense, the largest component of
DD&A, was $8.37, $6.92 and $5.17 per BOE during the years ended December 31,
2004, 2003 and 2002, respectively, and depreciation and amortization of other
property and equipment was $.19, $.17 and $.22 per BOE during each of the
respective years. During 2004 and 2003, the increase in per BOE depletion
expense was due to a greater proportion of the Company's production being
derived from higher cost-basis deepwater Gulf of Mexico and South African
developments and downward revisions to proved reserves in Canada in 2003.

The following table provides depletion expense per BOE by geographic area
for the years ended December 31, 2004, 2003 and 2002:

Year Ended December 31,
----------------------------------
2004 2003 2002
------- ------- -------
>
Depletion expense:
United States.............................. $ 8.61 $ 7.08 $ 4.85
Argentina.................................. $ 5.56 $ 4.96 $ 5.00
Canada..................................... $ 10.93 $ 9.98 $ 8.36
Africa..................................... $ 11.19 $ 10.69 $ -
Worldwide.................................. $ 8.37 $ 6.92 $ 5.17

Impairment of oil and gas properties. The Company reviews its long-lived
assets to be held and used, including oil and gas properties, whenever events or
circumstances indicate that the carrying value of those assets may not be
recoverable. During the year ended December 31, 2004, the Company recognized a
noncash impairment charge of $39.7 million to reduce the carrying value of its
Gabonese Olowi field assets as development of the discovery was canceled. See
"Critical Accounting Estimates" above and Notes B and T of Notes to Consolidated
Financial Statements included in "Item 8. Financial Statements and Supplementary
Data" for additional information pertaining to the Company's accounting policies
regarding assessments of impairment and the Gabonese Olowi field impairment,
respectively.

40

Exploration, abandonments, geological and geophysical costs. Exploration,
abandonments, geological and geophysical costs totaled $181.7 million, $132.8
million and $85.9 million during the years ended December 31, 2004, 2003 and
2002, respectively. The following table provides the Company's geological and
geophysical costs, exploratory dry hole expense, lease abandonments and other
exploration expense by geographic area for the years ended December 31, 2004,
2003 and 2002:

Africa
United and
States Argentina Canada Other Total
-------- --------- -------- -------- ----------
(in thousands)

Year ended December 31, 2004:
Geological and geophysical costs.......... $ 51,731 $ 11,718 $ 4,047 $ 14,833 $ 82,329
Exploratory dry holes..................... 39,328 7,213 11,811 24,460 82,812
Leasehold abandonments and other.......... 7,925 4,475 4,142 6 16,548
------- ------- ------- ------- --------
$ 98,984 $ 23,406 $ 20,000 $ 39,299 $ 181,689
======= ======= ======= ======= ========
Year ended December 31, 2003:
Geological and geophysical costs.......... $ 40,783 $ 7,689 $ 4,426 $ 3,903 $ 56,801
Exploratory dry holes..................... 27,015 2,672 10,963 20,250 60,900
Leasehold abandonments and other.......... 4,934 7,715 2,302 108 15,059
------- ------- ------- ------- --------
$ 72,732 $ 18,076 $ 17,691 $ 24,261 $ 132,760
======= ======= ======= ======= ========
Year ended December 31, 2002:
Geological and geophysical costs.......... $ 22,761 $ 4,138 $ 3,544 $ 7,223 $ 37,666
Exploratory dry holes..................... 32,557 3,294 1,220 (539) 36,532
Leasehold abandonments and other.......... 7,637 2,874 1,077 108 11,696
------- ------- ------- ------- --------
$ 62,955 $ 10,306 $ 5,841 $ 6,792 $ 85,894
======= ======= ======= ======= ========

The increase in 2004 exploration, abandonments, geological and geophysical
expense, as compared to 2003, was primarily due to a $25.5 million increase in
geological and geophysical expenditures and a $21.9 million increase in dry hole
expense. The increase in geological and geophysical expenditures during 2004 as
compared to 2003 was primarily due to expenditures supportive of exploration
activities in the deepwater Gulf of Mexico, Alaska, Argentina and Africa.
Significant components of the Company's dry hole expense during 2004 included
$27.7 million and $10.5 million on the Company's deepwater Gulf of Mexico Juno
and Myrtle Beach prospects, respectively, $19.0 million on the Company's
Gabonese Olowi prospect and $5.8 million on the Company's Bravo prospect
offshore Equatorial Guinea. During 2004, the Company drilled and evaluated 103
exploration/extension wells, 58 of which were successfully completed as
discoveries. During 2003, the Company drilled and evaluated 87
exploration/extension wells, 42 of which were successfully completed as
discoveries.

The increase in 2003 exploration, abandonments, geological and geophysical
expense, as compared to 2002, was primarily due to increased geological and
geophysical expenditures supportive of exploration activities in the Gulf of
Mexico and Alaska and a $24.4 million increase in exploratory dry hole expense.
The increase in exploratory dry hole expense during 2003 as compared to 2002 was
primarily due to an increase in Canadian exploratory drilling activities and
three unsuccessful wells drilled in South Africa and one unsuccessful well
drilled in Tunisia.

General and administrative expenses. The Company's general and
administrative expenses totaled $80.5 million ($1.20 per BOE), $60.5 million
($1.10 per BOE) and $48.4 million ($1.21 per BOE) during the years ended
December 31, 2004, 2003 and 2002, respectively. The increase in general and
administrative expense during 2004, as compared to 2003, was primarily due to
increases in administrative staff, including staff increases associated with the
Evergreen merger, and performance-related compensation costs, including the
amortization of restricted stock awarded to officers, directors and employees
during the three years ended December 31, 2004.

The increase in general and administrative expense during 2003, as compared
to 2002, was primarily due to increases in administrative staff and
performance-related compensation costs, including the amortization of restricted
stock awarded to officers, directors and key employees during 2003 and 2002.

Accretion of discount on asset retirement obligations. During the years
ended December 31, 2004 and 2003, the Company recorded accretion of discount on
asset retirement obligations of $8.2 million and $5.0 million, respectively. The
provisions of Statement of Financial Accounting Standards No. 143, "Accounting

41

for Asset Retirement Obligations" ("SFAS 143") require that the accretion of
discount on asset retirement obligations be classified in the consolidated
statement of operations separate from interest expense. Prior to 2003 and the
adoption of SFAS 143, the Company classified accretion of discount on asset
retirement obligations as a component of interest expense. The Company's
interest expense during the year ended December 31, 2002 included $2.6 million
of accretion of discount on asset retirement obligations that was calculated
prior to the adoption of SFAS 143 based on asset retirement obligations recorded
in purchased business combinations. See Notes B and M of Notes to Consolidated
Financial Statements included in "Item 8. Financial Statements and Supplementary
Data" for additional information regarding the Company's adoption of SFAS 143.

The increase in accretion of discount on asset retirement obligations for
2004 as compared to 2003 was primarily due to the increase in future plugging
and abandonment obligations related to new wells in the deepwater Gulf of
Mexico, Tunisia and South Africa and fourth quarter accretion of discount on
asset retirement obligations associated with the Evergreen merger.

Interest expense. Interest expense was $103.4 million, $91.4 million and
$95.8 million during the years ended December 31, 2004, 2003 and 2002,
respectively, while the weighted average interest rate on the Company's
indebtedness for the year ended December 31, 2004 was 5.4 percent as compared to
5.3 percent and 5.7 percent for the years ended December 31, 2003 and 2002,
respectively, taking into account the effect of interest rate derivatives. The
increase in interest expense for 2004 as compared to 2003 was primarily due to
an $8.0 million decrease in interest rate hedge gains, a $3.4 million decrease
in capitalized interest as the Company completed its major development projects
in the Gulf of Mexico and South Africa, increased borrowings under the Company's
lines of credit, primarily as a result of the Evergreen merger, and the
assumption of $300 million of notes in connection with the Evergreen merger.

The decrease in interest expense for 2003 as compared to 2002 was primarily
due to (i) $4.8 million of interest savings associated with the July 2002
repayment of a $45.2 million West Panhandle gas field capital obligation which
bore interest at an annual rate of 20 percent; (ii) $4.1 million of incremental
savings from the Company's interest rate hedging program; a $2.6 million
decrease in accretion expense (see "Accretion of discount on asset retirement
obligations", above); and (iii) lower underlying market interest rates and
outstanding debt. Partially offsetting the decreases in interest expense was a
$6.8 million decrease in interest capitalized during 2003 as compared to 2002
due to the completion of the Canyon Express and Falcon area development
projects.

During July 2004, the Company exchanged $526.8 million of three existing
series of senior notes for a like principal amount of New Notes and cash. In
accordance with GAAP, the Company accounted for the debt exchange during the
third quarter of 2004 as a replacement of the exchanged debt and began
amortizing a $109.0 million payment made in conjunction with the debt exchange
which represented the market value of the exchanged senior notes in excess of
their stated value, along with the unamortized carrying values attributable to
the issuance costs, discounts and deferred hedge gains and losses of the
exchanged debt, as adjustments of interest expense over the term of the New
Notes.

See Note F of Notes to Consolidated Financial Statements included in "Item
8. Financial Statements and Supplementary Data" for additional information about
the Company's long-term debt, the July 2004 note exchange and interest expense.

Other expenses. Other expenses were $33.7 million during the year ended
December 31, 2004, as compared to $21.3 million during 2003 and $39.6 million
during 2002. See Note P of Notes to Consolidated Financial Statements included
in "Item 8. Financial Statements and Supplementary Data" for a detailed
description of the components included in other expenses. The increase in other
expense for 2004 as compared to 2003 was primarily due to incremental
contingency adjustments of $11.8 million. The decrease in other expense for 2003
as compared to 2002 was primarily due to a decrease of $20.9 million in losses
on early extinguishment of debt.

Income tax provisions (benefits). The Company recognized consolidated
income tax provisions of $166.4 million during the year ended December 31, 2004,
consolidated income tax benefits of $64.4 million during 2003 and consolidated
income tax provisions of $5.1 million during 2002. The Company's consolidated
income tax provisions in 2004 were comprised of a $3.1 million current United
States federal, state and local tax provisions, a $22.2 million current foreign
income tax provision, $143.8 million of deferred United States federal, state
and local tax provisions and $2.7 million of deferred foreign tax benefits.

42

The Company's consolidated tax benefits in 2003 were comprised of a $.1
million current United States federal tax provision, an $11.1 million current
foreign income tax provision, $76.3 million of deferred United States federal,
state and local tax benefits and $.7 million of deferred foreign tax provisions.
The 2003 deferred United States federal, state and local tax benefits include a
$197.7 million benefit from the reversal of the Company's valuation allowances
against United States deferred tax assets. The Company's consolidated tax
provision for 2002 was comprised of current United States state and local taxes
of $.2 million, current foreign taxes of $2.1 million and deferred foreign tax
provisions of $2.8 million.

The Company's 34.7 percent effective tax rate for the year ended December
31, 2004 is lower than the combined United States federal and state statutory
rate of approximately 36.5 percent primarily due to the deferred tax benefit
recognized associated with the Company's cancellation of the development of its
Olowi field in Gabon. See Notes Q and T of Notes to Consolidated Financial
Statements included in "Item 8. Financial Statements and Supplementary Data" for
a discussion regarding the Company's reversal of its United States deferred tax
valuation allowances during 2003 and the Company's decision to cancel its
development of the Olowi field in Gabon.

See "Critical Accounting Estimates" above and Note Q of Notes to
Consolidated Financial Statements included in "Item 8. Financial Statements and
Supplementary Data" for additional information regarding the Company's tax
position.

Cumulative effect of change in accounting principle. The Company adopted
the provisions of SFAS 143 on January 1, 2003 and recognized a $15.4 million
benefit from the cumulative effect of change in accounting principle, net of
$1.3 million of deferred income taxes.

Capital Commitments, Capital Resources and Liquidity

Capital commitments. The Company's primary needs for cash are for
exploration, development and acquisitions of oil and gas properties, repayment
of contractual obligations and working capital obligations. Funding for
exploration, development and acquisitions of oil and gas properties and
repayment of contractual obligations may be provided by any combination of
internally-generated cash flow, proceeds from the disposition of non-strategic
assets or alternative financing sources as discussed in "Capital resources"
below. Generally, funding for the Company's working capital obligations is
provided by internally-generated cash flows.

Payments for acquisitions, net of cash acquired. The Company paid $880.4
million of cash, net of $12.1 million of cash acquired, to complete the
Evergreen merger during 2004. As noted above, the Company also assumed $300
million principal amount of Evergreen notes and other current and noncurrent
obligations associated with the Evergreen merger. As is further discussed in
"Financing activities", below, and in Notes C and F of Notes to Consolidated
Financial Statements included in "Item 8. Financial Statements and Supplementary
Data", the Company financed the cash costs of the merger with a new $900 million
364-Day Credit Agreement (the "364-Day Credit Agreement").

Oil and gas properties. The Company's cash expenditures for additions to
oil and gas properties during the years ended December 31, 2004, 2003 and 2002
totaled $615.9 million, $688.1 million and $614.7 million, respectively. The
Company's 2004 and 2003 expenditures for additions to oil and gas properties
were internally funded by $1.1 billion and $763.7 million, respectively, of net
cash provided by operating activities. The Company's 2002 expenditures for
additions to oil and gas properties were funded by $332.2 million of net cash
provided by operating activities, $118.9 million of proceeds from the
disposition of assets and a portion of the proceeds from the issuance of 11.5
million shares of the Company's common stock during April 2002.

The Company strives to maintain its indebtedness at reasonable levels in
order to provide sufficient financial flexibility to take advantage of future
opportunities. The Company's capital budget for 2005 is expected to range from
$900 million to $950 million. The Company believes that net cash provided by
operating activities during 2005 will be sufficient to fund the 2005 capital
expenditures budget as well as reduce long-term debt to achieve a targeted debt
to book capitalization of less than 35 percent and fund the Company's 2005
dividends. For additional information regarding the Company's plans for 2005,
see "2005 Outlook and Activities" above.

43

Contractual obligations, including off-balance sheet obligations. The
Company's contractual obligations include long-term debt, operating leases,
drilling commitments, derivative obligations, other liabilities and, during
2005, the VPP obligations. From time to time, the Company enters into
off-balance sheet arrangements and transactions that can give rise to material
off-balance sheet obligations of the Company. As of December 31, 2004, the
material off-balance sheet arrangements and transactions that the Company has
entered into include (i) $57.1 million of undrawn letters of credit, (ii)
operating lease agreements, (iii) drilling commitments and (iv) contractual
obligations for which the ultimate settlement amounts are not fixed and
determinable such as derivative contracts that are sensitive to future changes
in commodity prices and gas transportation commitments.

The following table summarizes by period the payments due by the Company
for contractual obligations estimated as of December 31, 2004:

Payments Due by Year
----------------------------------------------------
2006 and 2008 and
2005 2007 2009 Thereafter
--------- ---------- --------- ------------
(in thousands)

Long-term debt (a)................. $ 130,950 $ 832,075 $ 378,000 $1,151,579
Operating leases (b)............... 56,365 83,115 32,647 13,214
Drilling commitments (c)........... 10,468 7,957 - -
Derivative obligations (d)......... 224,403 131,940 50,352 511
Other liabilities (e).............. 44,541 65,099 40,401 61,833
Transportation commitments (f)..... 58,622 119,697 118,929 287,021
-------- --------- -------- ---------
$ 525,349 $1,239,883 $ 620,329 $1,514,158
======== ========= ======== =========

- ------------
(a) See Note F of Notes to Consolidated Financial Statements included in "Item
8. Financial Statements and Supplementary Data". The amounts included in
the table above represent principal maturities only.
(b) See Note J of Notes to Consolidated Financial Statements included in "Item
8. Financial Statements and Supplementary Data".
(c) Drilling commitments represent future minimum expenditure commitments under
contracts that the Company was a party to on December 31, 2004 for drilling
rig services and well commitments.
(d) Derivative obligations represent net liabilities for oil and gas commodity
derivatives that were valued as of December 31, 2004. These liabilities
include $.2 million of current assets and $.9 million of long-term
liabilities that are fixed in amount and are not subject to continuing
market risk. The ultimate settlement amounts of the remaining portions of
the Company's derivative obligations are unknown because they are subject
to continuing market risk. See "Item 7A. Quantitative and Qualitative
Disclosures About Market Risk" and Note K of Notes to Consolidated
Financial Statements included in "Item 8. Financial Statements and
Supplementary Data" for additional information regarding the Company's
derivative obligations.
(e) The Company's other liabilities represent current and noncurrent other
liabilities that are comprised of benefit obligations, litigation and
environmental contingencies, asset retirement obligations and other
obligations for which neither the ultimate settlement amounts nor their
timings can be precisely determined in advance. See Notes H, J and M of
Notes to Consolidated Financial Statements included in "Item 8. Financial
Statements and Supplementary Data" for additional information regarding the
Company's post retirement benefit obligations, litigation contingencies and
asset retirement obligations, respectively.
(f) Transportation commitments represent estimated transportation fees on gas
throughput commitments. See Note J of Notes to Consolidated Financial
Statements included in "Item 8. Financial Statements and Supplementary
Data" for additional information regarding the Company's transportation
commitments.

Capital resources. The Company's primary capital resources are net cash
provided by operating activities, proceeds from financing activities and
proceeds from sales of non-strategic assets. The Company expects that these
resources will be sufficient to fund its capital commitments in 2005.

Operating activities. Net cash provided by operating activities during the
years ended December 31, 2004, 2003 and 2002 were $1.1 billion, $763.7 million
and $332.2 million, respectively. Net cash provided by operating activities in
2004 increased by $340.9 million, or 45 percent, as compared to that of 2003.
The increase in 2004 was primarily due to increased production volumes and
higher commodity prices as compared to 2003. Net cash provided by operating
activities in 2003 increased by $431.4 million, or 130 percent, as compared to
that of 2002. The increase in 2003 was primarily due to increased production
volumes and higher commodity prices as compared to 2002.

44

Investing activities. Net cash used in investing activities during the
years ended December 31, 2004, 2003 and 2002 were $1.5 billion, $662.3 million
and $508.1 million, respectively. The $869.2 million increase in cash used in
investing activities during 2004 as compared to 2003 was primarily due to $880.4
million paid, net of cash acquired, in conjunction with the Evergreen merger.
The $154.2 million increase in cash used in investing activities during 2003 as
compared to 2002 was primarily due to a $73.4 million increase in additions to
oil and gas properties and an $83.2 million decrease in proceeds from
disposition of assets. The cash proceeds from asset divestitures during 2003
were used to reduce outstanding indebtedness. See "Results of Operations",
above, and Note O of Notes to Consolidated Financial Statements included in
"Item 8. Financial Statements and Supplementary Data" for additional information
regarding asset divestitures.

Financing activities. Net cash provided by financing activities totaled
$414.3 million and $170.9 million during the years ended December 31, 2004 and
2002, respectively. During the year ended December 31, 2003, financing
activities used $91.7 million of net cash. The increase in net cash provided by
financing activities in 2004 as compared to 2003 was primarily due to borrowings
on the Company's lines of credit to finance the cash consideration paid in
conjunction with the Evergreen merger offset by excess operating cash flows
being used to repay borrowings on the Company's lines of credit and the $109.0
million paid in conjunction with the exchange of the Company's senior notes
discussed below. During 2004, financing activities were comprised of $553.4
million of net principal borrowings on long-term debt, $54.3 million of payments
of other noncurrent liabilities, $26.6 million of dividends paid and $92.3
million of treasury stock purchases, partially offset by $35.1 million of
proceeds from the exercise of long-term incentive plan stock options and
employee stock purchases. During 2003, financing activities were comprised of
$105.5 million of net principal payments on long-term debt, $14.1 million of
payments of other noncurrent liabilities, $2.8 million of payments for deferred
loan fees and $2.3 million of treasury stock purchases, partially offset by
$33.0 million of proceeds from the exercise of long-term incentive plan stock
options and employee stock purchases. During 2002, the Company's financing
activities were comprised of $236.0 million of proceeds, net of issuance costs,
from the sale of 11.5 million shares of the Company's common stock; $48.0
million of net borrowings of long-term debt; and $14.4 million of proceeds from
the exercise of long-term incentive plan stock options and employee stock
purchases, partially offset by $124.2 million of payments of other noncurrent
liabilities and $3.3 million of payments for debt issuance costs.

Over the three-year period ended December 31, 2004, the Company has entered
into financing transactions with the intent of reducing its cost of capital and
increasing liquidity through the extension of debt maturities. During 2004, the
Company accepted tenders to exchange $117.9 million, $275.1 million and $133.8
million in principal amount of its 8 1/4% senior notes due 2007, 9-5/8% senior
notes due 2010 and 7.50% senior notes due 2012 (collectively, the "Old Notes"),
respectively, for a like principal amount of New Notes and cash. The exchange of
the Old Notes for the New Notes reduces the Company's future cash interest
expense incurred and extended the associated debt maturities.

During September 2004, the Company entered into the 364-Day Credit
Agreement that was used to finance the cash consideration associated with the
Evergreen merger. Borrowings under the 364-Day Credit Agreement may, at the
option of the Company, be designated to bear interest based on (a) a rate per
annum equal to the higher of the prime rate announced from time to time by
JPMorgan Chase Bank or the weighted average of the rates on overnight Federal
funds transactions with members of the Federal Reserve System during the last
preceding business day plus 50 basis point or (b) a base Eurodollar rate,
substantially equal to LIBOR, plus a margin that is based on a grid of the
Company's debt rating (75 basis points per annum at December 31, 2004).
Effective February 4, 2005, the Company requested that commitments under the
364-Day Credit Agreement be reduced by $250 million to $650 million. Also in
connection with the Evergreen merger, the Company assumed $100 million of 4.75%
Senior Convertible Notes due 2021 (the "Convertible Notes") and $200 million of
5.875% Senior Subordinated Notes due 2012 (the "EVG 5.875% Notes"). During
October 2004, the Company issued a Notice of Change of Control, Offer to
Purchase, and the Consent Solicitation Statement (the "Notice") (i) notifying
holders of the EVG 5.875% Notes of their right to require the Company to
repurchase their EVG 5.875% Notes pursuant to the terms set forth in the Notice
and (ii) soliciting consents to proposed amendments to the indenture governing
the EVG 5.875% Notes (the "Consent Solicitation"). A majority of the holders of
the EVG 5.875% Notes approved the Consent Solicitation which had the effect of
(i) eliminating the subordination of the right of payment on the EVG 5.875%
Notes, (ii) amending certain restrictive covenants applicable to the EVG 5.875%
Notes so that they are the same as the restrictive covenants governing the
Company's other senior notes and (iii) amending provisions that suspend other
restrictive covenants when the EVG 5.875% Notes receive certain investment grade
ratings. Associated with the Offer to Purchase, the Company accepted tenders for
and redeemed $5.5 million of the EVG 5.875% Notes. As a result of the Evergreen
merger, the Convertible Notes are redeemable at any time at the option of the

45

holders. If the holders of the Convertible Notes do not redeem the Convertible
Notes prior to December 20, 2006, the Company intends to exercise its rights
under the indenture and redeem the Convertible Notes on such date for cash,
common stock or a combination thereof. See Notes F and K of Notes to
Consolidated Financial Statements included in "Item 8. Financial Statements and
Supplemental Data" and "Item 7A. Quantitative and Qualitative Disclosures About
Market Risk" for more information about the Company's debt instruments and
interest rate hedging activities.

The Company's future debt level is dependent primarily on net cash provided
by operating activities, proceeds from financing activities and proceeds
generated from asset dispositions. The Company believes it has substantial
borrowing capacity, which has been further enhanced during 2005 by the use of
the VPP net proceeds to reduce outstanding indebtedness, to meet any
unanticipated cash requirements, and during low commodity price periods, the
Company has the flexibility to increase borrowings and/or modify its capital
spending to meet its contractual obligations and maintain its debt ratings.
During 2005, $131.0 million of the Company's 8-7/8% senior notes due 2005 (the
"8-7/8% Notes") will mature and the 364-Day Credit Agreement will have its first
anniversary. The Company intends to initially utilize unused borrowing capacity
under its 364-Day Credit Agreement to repay the 8-7/8% Notes and to transfer
outstanding borrowings, if any, under the 364-Day Credit Agreement to the
Company's Revolving Credit Agreement on its first anniversary. The Company also
intends to refinance, under its Revolving Credit Agreement, the cash component
of a redemption price associated with any redemption of the Convertible Notes
prior to December 2006, should redemptions occur. Accordingly, the Company's
Consolidated Balance Sheet does not reflect any current portion of long-term
debt as of December 31, 2004.

As the Company pursues its strategy, it may utilize various financing
sources, including fixed and floating rate debt, convertible securities,
preferred stock or common stock. The Company may also issue securities in
exchange for oil and gas properties, stock or other interests in other oil and
gas companies or related assets. Additional securities may be of a class
preferred to common stock with respect to such matters as dividends and
liquidation rights and may also have other rights and preferences as determined
by the Company's board of directors.

Liquidity. The Company's principal source of short-term liquidity is its
revolving lines of credit. Outstanding borrowings under the lines of credit
totaled $828 million as of December 31, 2004. Including $49.3 million of undrawn
and outstanding letters of credit under the lines of credit, the Company had
$722.7 million of unused borrowing capacity as of December 31, 2004.

Book capitalization and current ratio. The Company's book capitalization at
December 31, 2004 was $5.2 billion, consisting of debt of $2.4 billion and
stockholders' equity of $2.8 billion. Consequently, the Company's debt to book
capitalization decreased to 45.7 percent at December 31, 2004 from 46.9 percent
at December 31, 2003. As more fully discussed in "2005 Outlook and Activities"
above, the Company has targeted a range for debt to book capitalization of less
than 35 percent by the end of 2005. The Company's ratio of current assets to
current liabilities was .57 at December 31, 2004 as compared to .48 at December
31, 2003. The improvement in the Company's ratio of current assets to current
liabilities was primarily due to increases in oil and gas receivables due to
higher commodity prices.

Debt ratings. The Company receives debt credit ratings from Standard &
Poor's Ratings Group, Inc. ("S&P") and Moody's Investor Services, Inc.
("Moody's") and are subject to regular reviews. The Company's debt is currently
rated BBB- with a negative outlook by S&P and Baa3 with a negative outlook by
Moody's, both of which are investment- grade ratings. S&P and Moody's consider
many factors in determining the Company's ratings including: production growth
opportunities, liquidity, debt levels and asset and reserve mix. There are no
"ratings triggers" in any of the Company's contractual obligations that would
accelerate the related scheduled maturities should the Company's ratings fall
below certain levels. If the Company were to be downgraded by either S&P or
Moody's, it could negatively impact the interest rate and fees on existing
indebtedness and the Company's ability to obtain additional financing or the
interest rate and fees associated with additional financing.

New Accounting Pronouncement

On December 16, 2004, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standards No. 123 (revised 2004), "Share-Based
Payment" ("SFAS 123(R)"), which is a revision of Statement of Financial
Accounting Standards No. 123, "Accounting for Stock-Based Compensation" ("SFAS

46

123"). SFAS 123(R) supersedes Accounting Principles Bulletin Opinion No. 25,
"Accounting for Stock Issued to Employees" ("APB 25") and amends Statement of
Financial Accounting Standards No. 95, "Statement of Cash Flows". Generally, the
approach in SFAS 123(R) is similar to the approach described in SFAS 123.
However, SFAS 123(R) will require all share-based payments to employees,
including grants of employee stock options, to be recognized in the Company's
Consolidated Statements of Operations based on their fair values. Pro forma
disclosure is no longer an alternative.

SFAS 123(R) must be adopted no later than July 1, 2005 and permits public
companies to adopt its requirements using one of two methods:

o A "modified prospective" method in which compensation cost is recognized
beginning with the effective date based on the requirements of SFAS 123(R)
for all share-based payments granted after the effective date and based on
the requirements of SFAS 123 for all awards granted to employees prior to
the adoption date of SFAS 123(R) that remain unvested on the adoption date.
o A "modified retrospective" method which includes the requirements of the
modified prospective method described above, but also permits entities to
restate either all prior periods presented or prior interim periods of the
year of adoption based on the amounts previously recognized under SFAS 123
for purposes of pro forma disclosures.

The Company has elected to adopt the provisions of SFAS 123(R) on July 1, 2005
using the modified prospective method.

As permitted by SFAS 123, the Company currently accounts for share-based
payments to employees using the intrinsic value method prescribed by APB 25 and
related interpretations. As such, the Company generally does not recognize
compensation expenses associated with employee stock options. Accordingly, the
adoption of SFAS 123(R)'s fair value method could have a significant impact on
the Company's future result of operations, although it will have no impact on
the Company's overall financial position. Had the Company adopted SFAS 123(R) in
prior periods, the impact would have approximated the impact of SFAS 123 as
described in the pro forma net income and earnings per share disclosures in Note
B of Notes to Consolidated Financial Statements included in "Item 8. Financial
Statements and Supplementary Data". The adoption of SFAS 123(R) will have no
effect on the Company's outstanding restricted stock awards. The Company
estimates that the adoption of SFAS 123(R), based on the outstanding unvested
stock options at December 31, 2004, will result in future compensation charges
to general and administrative expenses of approximately $1.8 million during the
period from July 1, 2005 through December 31, 2005, and approximately $1.1
million during 2006.

The Company has an Employee Stock Purchase Plan (the "ESPP") that allows
eligible employees to annually purchase the Company's common stock at a
discount. The provisions of SFAS 123(R) will cause the ESPP to be a compensatory
plan. However, the change in accounting for the ESPP is not expected to have a
material impact on the Company's financial position, future results of
operations or liquidity. Historically, the ESPP compensatory amounts have been
nominal. See Note H of Notes to Consolidated Financial Statements included in
"Item 8. Financial Statements and Supplementary Data" for additional information
regarding the ESPP.

SFAS 123(R) also requires the tax benefits in excess of recognized
compensation expenses to be reported as a financing cash flow, rather than as an
operating cash flow as required under current literature. This requirement may
serve to reduce the Company's future cash provided by operating activities and
increase future cash provided by financing activities, to the extent of
associated tax benefits that may be realized in the future. While the Company
cannot estimate what those amounts will be in the future (because they depend
on, among other things, when employees exercise stock options), the amount of
operating cash flows recognized in prior periods for such excess tax deductions
were $6.6 million and $14.7 million during the years ended December 31, 2004 and
2003, respectively. The Company did not recognize any such tax benefits during
2002.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The following quantitative and qualitative information is provided about
financial instruments to which the Company was a party as of December 31, 2004
and 2003, and from which the Company may incur future gains or losses from
changes in market interest rates, foreign exchange rates or commodity prices.

47

Although certain derivative contracts that the Company was a party to did not
qualify as hedges, the Company does not enter into derivative or other financial
instruments for trading purposes.

The fair value of the Company's derivative contracts are determined based
on counterparties' estimates and valuation models. The Company did not change
its valuation method during the year ended December 31, 2004. During 2004, the
Company was a party to commodity and interest rate swap contracts and commodity
collar contracts. See Note K of Notes to Consolidated Financial Statements
included in "Item 8. Financial Statements and Supplementary Data" for additional
information regarding the Company's derivative contracts, including deferred
gains and losses on terminated derivative contracts. The following table
reconciles the changes that occurred in the fair values of the Company's open
derivative contracts during 2004:

Derivative Contract Assets (Liabilities)
---------------------------------------
Interest
Commodity Rate Total
----------- -------- ----------
(in thousands)
>
Fair value of contracts outstanding
as of December 31, 2003................... $ (201,422) $ - $ (201,422)
Fair value of Evergreen contracts assumed... (52,115) - (52,115)
Changes in contract fair values (a)......... (444,125) (10,638) (454,763)
Contract maturities......................... 292,475 (2,167) 290,308
Contract terminations....................... (1,359) 12,805 11,446
--------- ------- ---------
Fair value of contracts outstanding
as of December 31, 2004................... $ (406,546) $ - $ (406,546)
========= ======= =========

- ---------------
(a) At inception, new derivative contracts entered into by the Company have no
intrinsic value.

Quantitative Disclosures

Interest rate sensitivity. The following tables provide information about
other financial instruments that the Company was a party to as of December 31,
2004 and 2003 and that are or were sensitive to changes in interest rates. For
debt obligations, the tables present maturities by expected maturity dates, the
weighted average interest rates expected to be paid on the debt given current
contractual terms and market conditions and the debt's estimated fair value. For
fixed rate debt, the weighted average interest rate represents the contractual
fixed rates that the Company was obligated to periodically pay on the debt as of
December 31, 2004 and 2003. For variable rate debt, the average interest rate
represents the average rates being paid on the debt projected forward
proportionate to the forward yield curve for LIBOR on January 31, 2005.

Interest Rate Sensitivity
Debt Obligations as of December 31, 2004

Liability
Year Ending December 31, Fair Value at
----------------------------------------------------------------- December 31,
2005 2006 2007 2008 2009 Thereafter Total 2004
-------- -------- -------- -------- -------- ---------- ---------- -----------
(in thousands, except interest rates)

Total Debt:
Fixed rate principal
maturities (a)............ $130,950 $ - $ 32,075 $350,000 $ - $1,151,579 $1,664,604 $(1,846,110)
Weighted average
interest rate (%)....... 6.46 6.40 6.39 7.04 7.04 7.04
Variable rate maturities.... $ - $800,000 $ - $ 28,000 $ - $ - $ 828,000 $ (828,000)
Average interest rate (%). 3.89 4.77 5.13 5.49 - -

- -------------
(a) Represents maturities of principal amounts excluding (i) debt issuance
discounts and premiums and (ii) deferred fair value hedge gains and losses.

48

Interest Rate Sensitivity
Debt Obligations as of December 31, 2003

Liability
Year Ending December 31, Fair Value at
----------------------------------------------------------------- December 31,
2004 2005 2006 2007 2008 Thereafter Total 2003
-------- -------- -------- -------- -------- ---------- ---------- -----------
(in thousands, except interest rates)

Total Debt:
Fixed rate principal
maturities (a)........... $ - $130,950 $ - $150,000 $350,000 $739,169 $1,370,119 $(1,549,026)
Weighted average
interest rate (%)....... 7.93 7.86 7.83 7.81 8.34 8.37
Variable rate maturities.... $ - $ - $ - $ - $160,000 $ - $ 160,000 $ (160,000)
Average interest rate (%). 2.87 4.28 5.27 5.91 6.28 -

- -------------
(a) Represents maturities of principal amounts excluding (i) debt issuance
discounts and premiums and (ii) deferred fair value hedge gains and losses.

Foreign exchange rate sensitivity. There were no outstanding foreign
exchange rate hedge derivatives at December 31, 2004 and 2003.

Commodity price sensitivity. The following tables provide information about
the Company's oil and gas derivative financial instruments that were sensitive
to changes in oil and gas prices as of December 31, 2004 and 2003. As of
December 31, 2004 and 2003, all of the Company's oil and gas derivative
financial instruments qualified as hedges.

Commodity hedge instruments. The Company hedges commodity price risk with
derivative contracts, such as swap and collar contracts. Swap contracts provide
a fixed price for a notional amount of sales volumes. Collar contracts provide
minimum ("floor") and maximum ("ceiling") prices for the Company on a notional
amount of sales volumes, thereby allowing some price participation if the
relevant index price closes above the floor price.

See Notes B, E and K of Notes to Consolidated Financial Statements included
in "Item 8. Financial Statements and Supplementary Data" for a description of
the accounting procedures followed by the Company relative to hedge derivative
financial instruments and for specific information regarding the terms of the
Company's derivative financial instruments that are sensitive to changes in oil
and gas prices.

49

Oil Price Sensitivity
Derivative Financial Instruments as of December 31, 2004

Liability
Year Ending December 31, Fair Value at
------------------------------------------------------------------------- December 31,
2005 2006 2007 2008 2009 2010 2011 2012 2004
------- ------- ------- ------- ------ ------ ------ ------ ------------
(in thousands)

Oil Hedge Derivatives (a):
Average daily notional Bbl
volumes:
Swap contracts (b)....... 27,000 14,500 17,000 21,000 3,500 1,000 2,000 2,000 $ (261,111)
Weighted average fixed
price per Bbl.......... $ 27.97 $ 34.12 $ 32.59 $ 30.72 $36.48 $36.10 $35.93 $35.86
Collar contracts......... - 3,500 - - - - - - $ (2,278)
Weighted average ceiling
price per Bbl.......... $ - $ 41.95 $ - $ - $ - $ - $ - $ -
Weighted average floor
price per Bbl.......... $ - $ 35.00 $ - $ - $ - $ - $ - $ -
Average forward NYMEX
oil prices (c)........... $ 48.58 $ 45.26 $ 43.08 $ 41.01 $40.36 $39.91 $39.71 $39.51

- ---------------
(a) See Note K of Notes to Consolidated Financial Statements included in "Item
8. Financial Statements and Supplementary Data" for hedge volumes and
weighted average prices by calendar quarter.
(b) Subsequent to December 31, 2004, the Company conveyed to the purchaser of
the Spraberry VPP the following oil swap contracts which were included in
the schedule above: (i) 4,500 Bbls per day of 2006 oil sales at a weighted
average fixed price per Bbl of $39.53, (ii) 4,000 Bbls per day of 2007 oil
sales at a weighted average fixed price per Bbl of $38.14, (iii) 4,000 Bbls
per day of 2008 oil sales at a weighted average fixed price per Bbl of
$37.15, (iv) 3,500 Bbls per day of 2009 oil sales at a weighted average
fixed price per Bbl of $36.48, (v) 1,000 Bbls per day of 2010 oil sales at
a weighted average fixed price per Bbl of $36.10, (vi) 2,000 Bbls per day
of 2011 oil sales at a weighted average fixed price per Bbl of $35.93 and
(vii) 2,000 Bbls per day of 2012 oil sales at a weighted average fixed
price per Bbl of $35.86.
(c) The average forward NYMEX oil prices are based on February 18, 2005 market
quotes.

Oil Price Sensitivity
Derivative Financial Instruments as of December 31, 2003

Liability
Year Ending December 31, Fair Value at
---------------------------------------------------- December 31,
2004 2005 2006 2007 2008 2003
-------- -------- -------- -------- -------- -------------
(in thousands)

Oil Hedge Derivatives:
Average daily notional Bbl volumes:
Swap contracts........................ 18,973 17,000 5,000 1,000 5,000 $(50,240)
Weighted average fixed price per Bbl.. $ 25.84 $ 24.93 $ 26.19 $ 26.00 $ 26.09
Average forward NYMEX oil prices (a).. $ 30.12 $ 28.03 $ 27.09 $ 26.55 $ 26.60

- ---------------
(a) The average forward NYMEX oil prices are based on January 30, 2004 market
quotes.

50

Gas Price Sensitivity
Derivative Financial Instruments as of December 31, 2004

Liability
Year Ending December 31, Fair Value at
---------------------------------------------------- December 31,
2005 2006 2007 2008 2009 2004
-------- -------- -------- -------- -------- -------------
(in thousands)

Gas Hedge Derivatives (a):
Average daily notional MMBtu
volumes (b):
Swap contracts (c)................... 284,055 103,534 55,000 30,000 25,000 $ (142,858)
Weighted average fixed price per
MMBtu........................... $ 5.22 $ 4.68 $ 4.69 $ 5.06 $ 4.72
Collar contracts..................... - 5,000 - - - $ (299)
Weighted average ceiling price per
MMBtu........................... $ - $ 7.15 $ - $ - $ -
Weighted average floor price per
MMBtu........................... $ - $ 5.25 $ - $ - $ -
Average forward NYMEX gas
prices (d)......................... $ 6.29 $ 6.47 $ 6.14 $ 5.81 $ 5.50

- --------------
(a) To minimize basis risk, the Company enters into basis swaps for a portion
of its gas hedges to convert the index price of the hedging instrument from
a NYMEX index to an index which reflects the geographic area of production.
The Company considers these basis swaps as part of the associated swap and
collar contracts and, accordingly, the effects of the basis swaps have been
presented together with the associated contracts.
(b) See Note K of Notes to Consolidated Financial Statements included in "Item
8. Financial Statements and Supplementary Data" for hedge volumes and
weighted average prices by calendar quarter.
(c) Subsequent to December 31, 2004, the Company conveyed to the purchaser of
the Hugoton VPP the following gas swap contracts which were included in the
table above: (i) 9,151 MMBtu per day 2005 gas sales at a weighted average
fixed price per MMBtu of $6.17, (ii) 33,534 MMBtu per day 2006 gas sales at
a weighted average fixed price per MMBtu of $5.78, (iii) 30,000 MMBtu per
day 2007 gas sales at a weighted average fixed price per MMBtu of $5.32,
(iv) 25,000 MMBtu per day 2008 gas sales at a weighted average fixed price
per MMBtu of $5.00 and (v) 25,000 MMBtu per day of 2009 gas sales at a
weighted average fixed price per MMBtu of $4.72.
(d) The average forward NYMEX gas prices are based on February 18, 2005 market
quotes.

Gas Price Sensitivity
Derivative Financial Instruments as of December 31, 2003

Liability
Year Ending December 31, Fair Value at
-------------------------------------- December 31,
2004 2005 2006 2007 2003
-------- ------- ------- ------- -------------
(in thousands)

Gas Hedge Derivatives (a):
Average daily notional MMBtu volumes:
Swap contracts................................... 283,962 60,000 70,000 20,000 $ (151,182)
Weighted average fixed price per MMBtu........ $ 4.16 $ 4.24 $ 4.16 $ 3.51
Average forward NYMEX gas prices (b)............. $ 4.66 $ 5.04 $ 4.74 $ 4.60

- --------------
(a) To minimize basis risk, the Company enters into basis swaps for a portion
of its gas hedges to convert the index price of the hedging instrument from
a NYMEX index to an index which reflects the geographic area of production.
The Company considers these basis swaps as part of the associated swap and
collar contracts and, accordingly, the effects of the basis swaps have been
presented together with the associated contracts.
(b) The average forward NYMEX gas prices are based on January 30, 2004 market
quotes.

51

Qualitative Disclosures

Non-derivative financial instruments. The Company is a borrower under fixed
rate and variable rate debt instruments that give rise to interest rate risk.
The Company's objective in borrowing under fixed or variable rate debt is to
satisfy capital requirements while minimizing the Company's costs of capital.
See Note F of Notes to Consolidated Financial Statements included in "Item 8.
Financial Statements and Supplementary Data" for a discussion of the Company's
debt instruments.

Derivative financial instruments. The Company utilizes interest rate,
foreign exchange rate and commodity price derivative contracts to hedge interest
rate, foreign exchange rate and commodity price risks in accordance with
policies and guidelines approved by the Company's board of directors. In
accordance with those policies and guidelines, the Company's executive
management determines the appropriate timing and extent of hedge transactions.

Foreign currency, operations and price risk. International investments
represent, and are expected to continue to represent, a significant portion of
the Company's total assets. Pioneer currently has international operations in
Africa, Argentina and Canada, which represent nine, seven and five percent of
the Company's 2004 revenues, respectively. Pioneer continues to identify and
evaluate other international opportunities. As a result of such foreign
operations, Pioneer's financial results could be affected by factors such as
changes in foreign currency exchange rates, weak economic conditions or changes
in political climates in these foreign countries.

The Company's international operations may be adversely affected by
political and economic instability, changes in the legal and regulatory
environment and other factors. For example:

o local political and economic developments could restrict or increase
the cost of Pioneer's foreign operations,
o exchange controls and currency fluctuations could result in financial
losses,
o royalty and tax increases and retroactive tax claims could increase
costs of Pioneer's foreign operations,
o expropriation of the Company's property could result in loss of
revenue, property and equipment,
o civil uprising, riots, terrorist attacks and wars could make it
impractical to continue operations, resulting in financial losses,
o import and export regulations and other foreign laws or policies could
result in loss of revenues,
o repatriation levels for export revenues could restrict the
availability of cash to fund operations outside a particular foreign
country and
o laws and policies of the U.S. affecting foreign trade, taxation and
investment could restrict Pioneer's ability to fund foreign operations
or may make foreign operations more costly.

Pioneer does not currently maintain political risk insurance. Pioneer
evaluates on a country-by-country basis whether obtaining political risk
coverage is necessary and may add such insurance in the future if the Company
believes it is prudent.

Africa. Pioneer's operations in Africa are in South Africa, Tunisia, Gabon
and Equatorial Guinea. The Company views the operating environment in these
African nations as stable and the economic stability as good. While the values
of the various African nations' currencies do fluctuate in relation to the U.S.
dollar, the Company believes that any currency risk associated with Pioneer's
African operations would not have a material impact on the Company's results of
operations given that such operations are closely tied to oil prices which are
denominated in U.S. dollars.

Argentina. During the decade of the 1990s, Argentina's government pursued
free market policies, including the privatization of state-owned companies,
deregulation of the oil and gas industry, tax reforms to equalize tax rates for
domestic and foreign investors, liberalization of import and export laws and the
lifting of exchange controls. The cornerstone of these reforms was the 1991
convertibility law that established an exchange rate of one Argentine peso to
one U.S. dollar. These policies were successful as evidenced by the elimination
of inflation and substantial economic growth during the early to mid-1990s.
However, throughout the decade, the Argentine government failed to balance its
fiscal budget, incurring repeated significant fiscal deficits that by the end of
2001 resulted in the accumulation of $130 billion of debt.

52

During 2001, Argentina found itself in a critical economic situation with
the combination of high levels of external indebtedness, a financial and banking
system in crisis, a country risk rating that had reached levels beyond the
historical norm, a high level of unemployment and an economic contraction that
had lasted four years.

Late in 2001, the country was unable to obtain additional funding from the
International Monetary Fund. Economic instability increased, resulting in
substantial withdrawals of cash from the Argentine banking system over a short
period of time. The government was forced to implement monetary restrictions and
placed limitations on the transfer of funds out of the country without the
authorization of the Central Bank of the Republic of Argentina. President De la
Rua and his entire administration were forced to resign in the face of public
dissatisfaction. After his resignation in December 2001, there was, for a few
weeks, a revolving door of presidents that were appointed to office by
Argentina's Congress, but quickly resigned in reaction to public outcry. Eduardo
Duhalde was appointed President of Argentina in January 2002 to hold office
until the 2003 Presidential election.

In January 2002, the government defaulted on a significant portion of
Argentina's $130 billion of debt and the national Congress passed Emergency Law
25,561, which, among other things, overturned the long standing, but
unsustainable, convertibility plan. The government adopted a floating rate of
exchange in February 2002. Two specific provisions of the Emergency Law directly
impact the Company. First, a tax on the value of hydrocarbon exports was
established effective March 1, 2002. The second provision was the requirement
that domestic commercial transactions, or contracts, for sales in Argentina that
were previously denominated in U.S. dollars be converted to pesos (i.e.,
pesofication) at an exchange rate to be negotiated between sellers and buyers.
Furthermore, the government placed a price freeze on gas prices at the wellhead.
With the price of gas pesofied and frozen, the U.S. dollar-equivalent price of
gas in Argentina fell in direct proportion to the level of devaluation.

The abandonment of the convertibility plan and the decision to allow the
peso to float in international exchange markets resulted in significant
devaluation of the peso. By September 30, 2002, the peso-to-U.S. dollar exchange
rate had increased from 1:1 to 3.74:1. However, since the end of the third
quarter of 2002, Argentina's economy has shown signs of stabilization. At
December 31, 2004, the peso-to-U.S. dollar exchange rate was 2.98:1.

In Argentina, unlike Pioneer's other operating areas, there have been
significant factors that have kept the commodity prices, in general, below those
of the world markets and may continue to do so. The following is a discussion of
the matters affecting Argentine commodity prices:

o Oil Prices - In January 2002, the Argentine government devalued the
peso and enacted an emergency law that, in part, required certain
contracts that were previously payable in U.S. dollars to be payable
in pesos. Subsequently, in February 2002, the Argentine government
announced a 20 percent tax on oil exports, effective March 1, 2002.
The tax is limited by law to a term of no more than five years. The
export tax is not deducted in the calculation of royalty payments.
Domestic Argentine oil sales, while valued in U.S. dollars, are now
being paid in pesos. Export oil sales continue to be valued and paid
in U.S. dollars.

In January 2003, at the Argentine government's request, oil producers
and refiners agreed to cap amounts payable for certain domestic sales
at $28.50 per Bbl which remained in effect through April 2004. The
producers and refiners further agreed that the difference between the
actual price and the capped price would be payable once actual prices
fall below the $28.50 cap. Subsequently the terms were modified such
that while the $28.50 per Bbl payable cap was in place, the refiners
would have no obligation to pay producers for sales values that
exceeded $36.00 per Bbl. Initially, the refiners and producers also
agreed to discount U.S. dollar-denominated oil prices at 90 percent
prior to converting to pesos at the current exchange rate for the
purpose of invoicing and settling oil sales to Argentine refiners. In
May 2004, refiners and producers changed the discount percentage from
90 percent for all price levels to 86 percent if WTI was equal to or
less than $36 per Bbl and 80 percent if WTI exceeded $36 per Bbl. All
the oil prices are adjusted for normal quality differentials prior to
applying the discount.

In May 2004, the Argentine government increased the export tax from
20 percent to 25 percent. This tax is applied on the sales value
after the tax, thus, the net effect of the 20 percent and 25 percent
rates is 16.7 percent and 20 percent, respectively. In August 2004,
the Argentine government further increased the export tax rates for
oil exports. The export tax now escalates from the current 25 percent

53

(20 percent effective rate) to a maximum rate of 45 percent (31
percent effective rate) of the realized value for exported barrels as
WTI prices per barrel increase from less than $32.00 to $45.00 and
above.

During 2002 and 2003, the Company exported approximately 29 percent
and five percent, respectively, of its Argentine oil production.
Associated therewith, the Company incurred oil export taxes of $2.2
million and $1.2 million for 2002 and 2003, respectively. During
2004, the Company did not export any of its Argentine oil production.
As noted above, the export tax has also had the effect of decreasing
internal Argentine oil revenues (not only export revenues) by the
taxes levied. The U.S. dollar equivalent value for domestic Argentine
oil sales has generally moved toward parity with the U.S.
dollar-denominated export values, net of the export tax. The adverse
impact of this tax has been partially offset by the net cost savings
resulting from the devaluation of the peso on peso-denominated costs
such as labor. Given the number of governmental changes during 2004
affecting the realized price the Company receives for its oil sales,
no specific predictions can be made about the future of oil prices in
Argentina, however, in the short term, the Company expects Argentine
oil realizations to be less than oil realizations in the United
States.

o Gas Prices - The Company sells its gas to Argentine customers
pursuant to (a) peso-denominated contracts, (b) long-term
dollar-denominated contracts and (c) spot market sales. As a result
of economic emergency law enacted by the Argentine government in
January 2002, the Company's gas prices, expressed in U.S. dollars,
have fallen in proportion to the devaluation of the Argentine peso
since the end of 2001 due to the pesofication of contracts and the
freezing of gas prices at the wellhead required by that law. As a
baseline, the Company's 2001 realized gas price was $1.31 per Mcf as
compared to $.48, $.56 and $.66 in 2002, 2003 and 2004, respectively.

The unfavorable gas price has acted to discourage gas development
activities and increased gas demand. Without development of gas
reserves in Argentina, supplies of gas in the country have declined,
while demand for gas has been increasing due to the resurgence of the
Argentine economy and the higher cost of alternative fuels. Recently,
gas exports to Chile were curtailed at the direction of the Argentine
government and Argentina entered into an agreement to import gas from
Bolivia at prices starting at approximately $2.00 per Mcf (at the
border), including transportation costs. In May 2004, pursuant to a
decree, the Argentine government approved measures to permit
producers to renegotiate gas sales contracts, excluding those that
could affect small residential customers, in accordance with
scheduled price increases specified in the decree. The wellhead
prices in the decree rise from a current range of $.61 to $.78 per
Mcf to a range of $.87 to $1.04 per Mcf after July 2005, depending on
the region where the gas is produced. No further gas price increases
beyond July 2005 have been allowed for in the current decree. Other
than an expectation that gas prices will be permitted to increase
gradually over time, as has already been demonstrated by the
governing authorities, no specific predictions can be made about the
future of gas prices in Argentina, however, the Company expects
Argentine gas realizations to be less than gas realizations in the
United States.

Canada. The Company views the operating environment in Canada as stable and
the economic stability as good. A portion of the Company's Canadian revenues and
substantially all of its costs are denominated in Canadian dollars. While the
value of the Canadian dollar does fluctuate in relation to the U.S. dollar, the
Company believes that any currency risk associated with its Canadian operations
would not have a material impact on the Company's results of operations.

As of December 31, 2004, the Company's primary risk exposures associated
with financial instruments to which it is a party include oil and gas price
volatility, volatility in the exchange rates of the Canadian dollar and
Argentine peso vis a vis the U.S. dollar and interest rate volatility. The
Company's primary risk exposures associated with financial instruments have not
changed significantly since December 31, 2004.

54

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Index to Consolidated Financial Statements

Page

Consolidated Financial Statements of Pioneer Natural Resources Company:
Report of Independent Registered Public Accounting Firm........... 56
Consolidated Balance Sheets as of December 31, 2004 and 2003...... 57
Consolidated Statements of Operations for the Years Ended
December 31, 2004, 2003 and 2002............................... 58
Consolidated Statements of Stockholders' Equity for the Years
Ended December 31, 2004, 2003 and 2002......................... 59
Consolidated Statements of Cash Flows for the Years Ended
December 31, 2004, 2003 and 2002............................... 60
Consolidated Statements of Comprehensive Income (Loss) for the
Years Ended December 31, 2004, 2003 and 2002................... 61
Notes to Consolidated Financial Statements........................ 62
Unaudited Supplementary Information............................... 105

55

REPORT OF INDEPENDENT REGISTERED PUBLIC
ACCOUNTING FIRM

The Board of Directors and Stockholders of
Pioneer Natural Resources Company:

We have audited the accompanying consolidated balance sheets of Pioneer
Natural Resources Company and subsidiaries (the "Company") as of December 31,
2004 and 2003, and the related consolidated statements of operations,
stockholders' equity, cash flows and comprehensive income (loss) for each of the
three years in the period ended December 31, 2004. These financial statements
are the responsibility of the Company's management. Our responsibility is to
express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public
Company Accounting Oversight Board (United States). Those standards require that
we plan and perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the consolidated financial position of
the Company and subsidiaries at December 31, 2004 and 2003, and the consolidated
results of their operations and their cash flows for each of the three years in
the period ended December 31, 2004, in conformity with U.S. generally accepted
accounting principles.

We also have audited, in accordance with the standards of the Public
Company Accounting Oversight Board (United States), the effectiveness of the
Company's internal control over financial reporting as of December 31, 2004,
based on criteria established in Internal Control--Integrated Framework issued
by the Committee of Sponsoring Organizations of the Treadway Commission and our
report dated February 17, 2005 expressed an unqualified opinion thereon.

As discussed in Note B to the consolidated financial statements, in 2003
the Company adopted Statement of Financial Accounting Standards No. 143,
"Accounting for Asset Retirement Obligations."

Ernst & Young LLP

Dallas, Texas
February 17, 2005

56

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED BALANCE SHEETS
(in thousands, except share data)

December 31,
------------------------
2004 2003
---------- ----------
ASSETS

Current assets:
Cash and cash equivalents.............................................. $ 7,257 $ 19,299
Accounts receivable:
Trade, net of allowance for doubtful accounts of $7,348 and
$4,727 as of December 31, 2004 and 2003, respectively.............. 207,696 111,033
Due from affiliates.................................................. 2,583 447
Inventories............................................................ 40,332 17,509
Prepaid expenses....................................................... 10,822 11,083
Deferred income taxes.................................................. 33,980 40,514
Other current assets:
Derivatives.......................................................... 209 423
Other, net of allowance for doubtful accounts of $4,486
as of December 31, 2004 and 2003................................... 9,320 4,807
--------- ---------
Total current assets............................................. 312,199 205,115
--------- ---------
Property, plant and equipment, at cost:
Oil and gas properties, using the successful efforts method
of accounting:
Proved properties.................................................... 7,654,181 4,983,558
Unproved properties.................................................. 470,435 179,825
Accumulated depletion, depreciation and amortization................... (2,243,549) (1,676,136)
--------- ---------
Total property, plant and equipment.............................. 5,881,067 3,487,247
--------- ---------
Deferred income taxes.................................................... 2,963 192,344
Goodwill................................................................. 315,880 -
Other property and equipment, net........................................ 78,696 28,080
Other assets:
Derivatives............................................................ - 209
Other, net of allowance for doubtful accounts of $92
as of December 31, 2004 and 2003..................................... 56,436 38,577
--------- ---------
$6,647,241 $3,951,572
========= =========

LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable:
Trade................................................................ $ 205,153 $ 177,614
Due to affiliates.................................................... 10,898 8,804
Interest payable....................................................... 45,735 37,034
Income taxes payable................................................... 13,520 5,928
Other current liabilities:
Derivatives.......................................................... 224,612 161,574
Other................................................................ 44,541 38,798
--------- ---------
Total current liabilities.......................................... 544,459 429,752
--------- ---------
Long-term debt........................................................... 2,385,950 1,555,461
Derivatives.............................................................. 182,803 48,825
Deferred income taxes.................................................... 526,189 12,121
Other liabilities and minority interests................................. 176,060 145,641
Stockholders' equity:
Common stock, $.01 par value; 500,000,000 shares authorized;
145,644,828 and 119,665,784 shares issued at December 31, 2004
and 2003, respectively............................................... 1,456 1,197
Additional paid-in capital............................................. 3,705,286 2,734,403
Treasury stock, at cost; 813,166 and 378,012 shares at December 31,
2004 and 2003, respectively.......................................... (27,793) (5,385)
Deferred compensation.................................................. (22,558) (9,933)
Accumulated deficit.................................................... (634,146) (887,848)
Accumulated other comprehensive income (loss):
Net deferred hedge losses, net of tax................................ (241,350) (104,130)
Cumulative translation adjustment.................................... 50,885 31,468
--------- ---------
Total stockholders' equity......................................... 2,831,780 1,759,772
Commitments and contingencies
--------- ---------
$6,647,241 $3,951,572
========= =========

The accompanying notes are an integral part of
these consolidated financial statements.

57

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share data)

Year Ended December 31,
-------------------------------------
2004 2003 2002
---------- ---------- ---------

Revenues and other income:
Oil and gas............................................... $1,832,663 $1,273,871 $ 694,355
Interest and other........................................ 14,074 12,292 11,222
Gain on disposition of assets, net........................ 39 1,256 4,432
--------- --------- --------
1,846,776 1,287,419 710,009
--------- --------- --------
Costs and expenses:
Oil and gas production.................................... 345,504 254,750 192,145
Depletion, depreciation and amortization.................. 574,874 390,840 216,375
Impairment of oil and gas properties...................... 39,684 - -
Exploration and abandonments.............................. 181,689 132,760 85,894
General and administrative................................ 80,528 60,545 48,402
Accretion of discount on asset retirement obligations..... 8,210 5,040 -
Interest.................................................. 103,387 91,388 95,815
Other..................................................... 33,687 21,320 39,602
--------- --------- --------
1,367,563 956,643 678,233
--------- --------- --------
Income before income taxes and cumulative effect of change
in accounting principle................................... 479,213 330,776 31,776
Income tax benefit (provision).............................. (166,359) 64,403 (5,063)
--------- --------- --------
Income before cumulative effect of change in accounting
principle................................................. 312,854 395,179 26,713
Cumulative effect of change in accounting principle,
net of tax................................................ - 15,413 -
--------- --------- --------
Net income.................................................. $ 312,854 $ 410,592 $ 26,713
========= ========= ========
Basic earnings per share:
Income before cumulative effect of change in accounting
principle.............................................. $ 2.50 $ 3.37 $ .24
Cumulative effect of change in accounting principle,
net of tax............................................. - .13 -
--------- --------- --------
Net income................................................ $ 2.50 $ 3.50 $ .24
========= ========= ========
Diluted earnings per share:
Income before cumulative effect of change in accounting
principle.............................................. $ 2.46 $ 3.33 $ .23
Cumulative effect of change in accounting principle,
net of tax............................................. - .13 -
--------- --------- --------
Net income................................................ $ 2.46 $ 3.46 $ .23
========= ========= ========
Weighted average shares outstanding:
Basic.................................................. 125,156 117,185 112,542
========= ========= ========
Diluted................................................ 127,488 118,513 114,288
========= ========= ========

The accompanying notes are an integral part of
these consolidated financial statements.

58

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(in thousands, except dividends per share)

Accumulated Other
Comprehensive
Income (Loss)
---------------------
Net
Deferred
Hedge
Gains Cumulative Total
Additional Deferred (Losses) Trans- Stock-
Common Paid-in Treasury Compen- Accumulated Net lation holders'
Stock Capital Stock sation Deficit of tax Adjustment Equity
------- ---------- -------- --------- ----------- --------- ---------- ----------

Balance as of January 1, 2002....... $ 1,074 $2,462,272 $(48,002) $ - $(1,323,343) $ 201,046 $ (7,658) $1,285,389

Issuance of common stock............ 115 235,885 - - - - - 236,000
Adjustment to common stock
issued for 2001 partnership
acquisitions...................... - (175) - - - - - (175)
Exercise of long-term incentive
plan stock options and
employee stock purchases.......... - 416 15,783 - (1,810) - - 14,389
Deferred compensation:
Compensation deferred............. 7 16,169 - (16,176) - - - -
Deferred compensation included
in net income................... - - - 1,884 - - - 1,884
Net income.......................... - - - - 26,713 - - 26,713
Other comprehensive income (loss):
Net deferred hedge gains
(losses), net of tax:
Net deferred hedge losses...... - - - - - (181,628) - (181,628)
Net hedge gains included in
net income................... - - - - - (12,424) - (12,424)
Tax benefits related to net
hedge losses................. - - - - - 2,561 - 2,561
Translation adjustment............ - - - - - - 2,188 2,188
------ --------- ------- -------- ---------- -------- ------- ---------
Balance as of December 31, 2002..... 1,196 2,714,567 (32,219) (14,292) (1,298,440) 9,555 (5,470) 1,374,897
------ --------- ------- -------- ---------- -------- ------- ---------
Exercise of long-term incentive
plan stock options and employee
stock purchases................... 1 4,100 29,183 - - - - 33,284
Purchase of treasury stock.......... - - (2,349) - - - - (2,349)
Tax benefits related to
stock-based compensation.......... - 14,666 - - - - - 14,666
Deferred compensation:
Compensation deferred............. - 1,070 - (1,070) - - - -
Deferred compensation included in
net income...................... - - - 5,429 - - - 5,429
Net income.......................... - - - - 410,592 - - 410,592
Other comprehensive income (loss):
Net deferred hedge losses,
net of tax:
Net deferred hedge losses...... - - - - - (282,165) - (282,165)
Net hedge losses included in
net income................... - - - - - 117,416 - 117,416
Tax benefits related to net
hedge losses................. - - - - - 51,064 - 51,064
Translation adjustment............ - - - - - - 36,938 36,938
------ --------- ------- -------- ---------- -------- ------- ---------
Balance as of December 31, 2003..... 1,197 2,734,403 (5,385) (9,933) (887,848) (104,130) 31,468 1,759,772
------ --------- ------- -------- ---------- -------- ------- ---------
Acquisition of Evergreen
Resources, Inc.................... 254 947,334 - (6,001) - - - 941,587
Dividends declared ($.20 per
common share)..................... - - - - (26,557) - - (26,557)
Exercise of long-term incentive
plan stock options and employee
stock purchases................... - (2,185) 69,848 - (32,595) - - 35,068
Purchase of treasury stock.......... - - (92,256) - - - - (92,256)
Tax benefits related to
stock-based compensation.......... - 6,612 - - - - - 6,612
Deferred compensation:
Compensation deferred............. 5 19,122 - (19,127) - - - -
Deferred compensation included in
net income...................... - - - 12,503 - - - 12,503
Net income.......................... - - - - 312,854 - - 312,854
Other comprehensive income (loss):
Net deferred hedge losses,
net of tax:
Net deferred hedge losses...... - - - - - (443,318) - (443,318)
Net hedge losses included in
net income................... - - - - - 232,758 - 232,758
Tax benefits related to net
hedge losses................. - - - - - 73,340 - 73,340
Translation adjustment............ - - - - - - 19,417 19,417
------ --------- ------- -------- ---------- -------- ------- ---------
Balance as of December 31, 2004..... $ 1,456 $3,705,286 $(27,793) $ (22,558) $ (634,146) $(241,350) $ 50,885 $2,831,780
======= ========= ======= ======== ========== ======== ======= =========

The accompanying notes are an integral part of
these consolidated financial statements.

59

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)

Year Ended December 31,
--------------------------------------
2004 2003 2002
----------- ---------- ---------

Cash flows from operating activities:
Net income................................................... $ 312,854 $ 410,592 $ 26,713
Adjustments to reconcile net income to net cash
provided by operating activities:
Depletion, depreciation and amortization................ 574,874 390,840 216,375
Impairment of oil and gas properties.................... 39,684 - -
Exploration expenses, including dry holes............... 146,833 97,690 64,617
Deferred income taxes................................... 141,072 (75,588) 2,788
Gain on disposition of assets, net...................... (39) (1,256) (4,432)
Accretion of discount on asset retirement obligations... 8,210 5,040 -
Noncash interest expense................................ (12,208) (20,610) (5,809)
Commodity hedge related amortization.................... (45,102) (71,816) 26,490
Cumulative effect of change in accounting principle,
net of tax........................................... - (15,413) -
Amortization of stock-based compensation................ 12,503 5,429 1,884
Other noncash items..................................... 16,913 4,966 29,763
Change in operating assets and liabilities, net of
effects from acquisitions:
Accounts receivable, net................................ (73,376) (10,983) (23,922)
Inventories............................................. (14,025) (7,734) 3,023
Prepaid expenses........................................ 974 (5,598) 2,330
Other current assets, net............................... 262 (602) (4,166)
Accounts payable........................................ 250 58,603 (342)
Interest payable........................................ 5,533 (424) 48
Income taxes payable.................................... 3,372 5,928 (530)
Other current liabilities............................... (14,037) (5,385) (2,585)
---------- --------- --------
Net cash provided by operating activities............ 1,104,547 763,679 332,245
---------- --------- --------
Cash flows from investing activities:
Payments for acquisition, net of cash acquired............... (880,365) - -
Proceeds from disposition of assets.......................... 1,709 35,698 118,850
Additions to oil and gas properties.......................... (615,895) (688,133) (614,698)
Other property additions, net................................ (36,970) (9,865) (12,283)
---------- --------- --------
Net cash used in investing activities................ (1,531,521) (662,300) (508,131)
---------- --------- --------
Cash flows from financing activities:
Borrowings under long-term debt.............................. 1,157,903 264,725 529,805
Principal payments on long-term debt......................... (604,475) (370,262) (481,783)
Common stock issuance proceeds, net of issuance costs........ - - 236,000
Payment of other liabilities................................. (54,252) (14,055) (124,245)
Exercise of long-term incentive plan stock options and
employee stock purchases.................................. 35,068 33,020 14,389
Purchase of treasury stock................................... (92,256) (2,349) -
Payment of financing fees.................................... (1,173) (2,799) (3,293)
Dividends paid............................................... (26,557) - -
---------- --------- --------
Net cash provided by (used in) financing activities.. 414,258 (91,720) 170,873
---------- --------- --------
Net increase (decrease) in cash and cash equivalents .......... (12,716) 9,659 (5,013)
Effect of exchange rate changes on cash and cash equivalents... 674 1,150 (831)
Cash and cash equivalents, beginning of year................... 19,299 8,490 14,334
---------- --------- --------
Cash and cash equivalents, end of year......................... $ 7,257 $ 19,299 $ 8,490
========== ========= ========

The accompanying notes are an integral part of
these consolidated financial statements.

60

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(in thousands)

Year ended December 31,
-------------------------------------
2004 2003 2002
--------- ---------- ----------

Net income................................................ $ 312,854 $ 410,592 $ 26,713

Other comprehensive loss:
Net deferred hedge losses, net of tax:
Net deferred hedge losses............................ (443,318) (282,165) (181,628)
Net hedge losses (gains) included in net income...... 232,758 117,416 (12,424)
Tax benefits related to net hedge losses............. 73,340 51,064 2,561
Translation adjustment.................................. 19,417 36,938 2,188
--------- --------- ---------

Other comprehensive loss.......................... (117,803) (76,747) (189,303)
--------- --------- ---------

Comprehensive income (loss)............................... $ 195,051 $ 333,845 $ (162,590)
========= ========= =========

The accompanying notes are an integral part of
these consolidated financial statements.

61

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2004, 2003 and 2002

NOTE A. Organization and Nature of Operations

Pioneer Natural Resources Company ("Pioneer" or the "Company") is a
Delaware corporation whose common stock is listed and traded on the New York
Stock Exchange. The Company is a large independent oil and gas exploration and
production company with operations in the United States, Argentina, Canada,
Equatorial Guinea, Gabon, South Africa and Tunisia.

On September 28, 2004, the Company completed a merger with Evergreen
Resources, Inc. ("Evergreen"), as set forth in the Agreement and Plan of Merger
dated May 3, 2004 (the "Merger Agreement"), that added to the Company's United
States and Canadian asset base and expanded its portfolio of development and
exploration opportunities in North America. Evergreen's operations were
primarily focused on developing and expanding its coal bed methane production
from the Raton Basin in southern Colorado.

In accordance with the provisions of Statement of Financial Accounting
Standards No. 141, "Business Combinations" ("SFAS 141"), the merger has been
accounted for as a purchase of Evergreen by Pioneer. As a result, the historical
financial statements for the Company are those of Pioneer, and the Company's
Consolidated Balance Sheets present the addition of Evergreen's assets and
liabilities as of September 28, 2004. The accompanying Consolidated Statements
of Operations and Consolidated Statements of Cash Flows include the financial
results of Evergreen since October 1, 2004. See Note C for additional
information regarding the Evergreen merger.

NOTE B. Summary of Significant Accounting Policies

Principles of consolidation. The consolidated financial statements include
the accounts of the Company and its wholly-owned and majority-owned subsidiaries
since their acquisition or formation, and the Company's interest in the
affiliated oil and gas partnerships for which it serves as general partner
through certain of its wholly-owned subsidiaries. The Company proportionately
consolidates less than 100 percent-owned affiliate partnerships involved in oil
and gas producing activities in accordance with industry practice. The Company
owns less than a 20 percent interest in the oil and gas partnerships that it
proportionately consolidates. All material intercompany balances and
transactions have been eliminated.

Minority interests. As of December 31, 2004, other liabilities and minority
interests in the Company's Consolidated Balance Sheet includes $8.7 million of
minority interests attributable to outside ownership interests in certain
entities acquired in the Evergreen merger. The minority interest in these
subsidiaries' net income for the three months ended December 31, 2004 was $.9
million and is included in other expense in the Company's Consolidated Statement
of Operations.

Investments. Investments in unaffiliated equity securities that have a
readily determinable fair value are classified as "trading securities" if
management's current intent is to hold them for only a short period of time;
otherwise, they are accounted for as "available-for-sale" securities. The
Company reevaluates the classification of investments in unaffiliated equity
securities at each balance sheet date. The carrying value of trading securities
and available-for-sale securities are adjusted to fair value as of each balance
sheet date.

Unrealized holding gains are recognized for trading securities in interest
and other revenue, and unrealized holding losses are recognized in other expense
during the periods in which changes in fair value occur.

Unrealized holding gains and losses are recognized for available-for-sale
securities as credits or charges to stockholders' equity and other comprehensive
income (loss) during the periods in which changes in fair value occur.

62

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2004, 2003 and 2002

Realized gains and losses on the divestiture of available-for-sale securities
are determined using the average cost method. The Company had no investments in
available-for-sale securities as of December 31, 2004 or 2003.

Investments in unaffiliated equity securities that do not have a readily
determinable fair value are measured at the lower of their original cost or the
net realizable value of the investment. The Company had no significant equity
security investments that did not have a readily determinable fair value as of
December 31, 2004 or 2003.

Use of estimates in the preparation of financial statements. Preparation of
the accompanying consolidated financial statements in conformity with generally
accepted accounting principles in the United States ("GAAP") requires management
to make estimates and assumptions that affect the reported amounts of assets and
liabilities, the disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenues and expenses
during the reporting periods. Depletion of oil and gas properties is determined
using estimates of proved oil and gas reserves. There are numerous uncertainties
inherent in the estimation of quantities of proved reserves and in the
projection of future rates of production and the timing of development
expenditures. Similarly, evaluations for impairment of proved and unproved oil
and gas properties are subject to numerous uncertainties including, among
others, estimates of future recoverable reserves; commodity price outlooks;
foreign laws, restrictions and currency exchange rates; and export and excise
taxes. Actual results could differ from the estimates and assumptions utilized.

Argentina devaluation. Early in January 2002, the Argentine government
severed the direct one-to-one U.S. dollar to Argentine peso relationship that
had existed for many years. As of December 31, 2004 and 2003, the Company used
exchange rates of 2.98 pesos to $1 and 2.93 pesos to $1, respectively, to
remeasure the peso-denominated monetary assets and liabilities of the Company's
Argentine subsidiaries. The remeasurement of the peso-denominated monetary net
assets of the Company's Argentine subsidiaries as of December 31, 2004, 2003 and
2002 resulted in a gain of $.2 million and charges of $.3 million and $6.9
million, respectively.

As a result of certain Argentine stability laws and regulations enacted
since the devaluation of the Argentine peso which impact the price the Company
receives for the oil and gas it produces, the Company continually reviews its
Argentine proved and unproved properties for impairment. Based on estimates of
future commodity prices and operating costs, the Company believes that the
future cash flows from its oil and gas assets will be sufficient to fully
recover its proved property basis. The Company also plans to continue its
exploration efforts on all of its remaining unproved acreage. Based upon the
Company's improved economic outlook for Argentina, the Company has significantly
increased its capital budget for exploration and development activities in 2005
as compared to the capital budgets in 2004 and 2003.

While the Argentine economic and political situation continues to improve,
the Argentine government may enact future regulations or policies that, when
finalized and adopted, may materially impact, among other items, (i) the
realized prices the Company receives for the commodities it produces and sells;
(ii) the timing of repatriations of excess cash flow to the Company's corporate
headquarters in the United States; (iii) the Company's asset valuations; (iv)
the Company's level of future investments in Argentina; and (v) peso-denominated
monetary assets and liabilities. While conditions are improving, numerous
uncertainties exist surrounding the ultimate resolution of Argentina's economic
and political stability.

Adoption of SFAS 143. On January 1, 2003, the Company adopted the
provisions of Statement of Financial Accounting Standards No. 143, "Accounting
for Asset Retirement Obligations" ("SFAS 143"). SFAS 143 amended Statement of
Financial Accounting Standards No. 19, "Financial Accounting and Reporting by
Oil and Gas Producing Companies" ("SFAS 19") to require that the fair value of a
liability for an asset retirement obligation be recognized in the period in
which it is incurred if a reasonable estimate of fair value can be made. Under
the provisions of SFAS 143, asset retirement obligations are capitalized as part
of the carrying value of the long-lived asset.

63

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2004, 2003 and 2002

The adoption of SFAS 143 resulted in a January 1, 2003 cumulative effect
adjustment to record a gain of $15.4 million, net of $1.3 million of deferred
tax, as a cumulative effect adjustment of a change in accounting principle in
the Company's Consolidated Statements of Operations. See Note M for additional
information regarding the Company's asset retirement obligations.

The following table illustrates the pro forma effect on net income and
earnings per share for the years ended December 31, 2003 and 2002 as if the
Company had adopted the provisions of SFAS 143 on January 1, 2002.

Year ended December 31,
----------------------------
2003 2002
--------- ---------
(in thousands, except per share amounts)

Net income, as reported........................ $ 410,592 $ 26,713
Pro forma adjustments to reflect retroactive
adoption of SFAS 143........................ (15,413) 4,743
-------- --------
Pro forma net income........................... $ 395,179 $ 31,456
======== ========
Net income per share:
Basic - as reported......................... $ 3.50 $ .24
======== ========
Basic - pro forma........................... $ 3.37 $ .28
======== ========
Diluted - as reported....................... $ 3.46 $ .23
======== ========
Diluted - pro forma......................... $ 3.33 $ .28
======== ========

Cash equivalents. Cash and cash equivalents include cash on hand and
depository accounts held by banks.

Inventories - equipment. Lease and well equipment inventory to be used in
future joint operations activities are carried at the lower of cost or market,
on a first-in, first-out basis. Total lease and well equipment inventory was
$37.9 million and $15.3 million as of December 31, 2004 and 2003, respectively,
and is net of valuation reserve allowances of $.4 million and $.6 million as of
December 31, 2004 and 2003, respectively.

Inventories - commodities. Commodities are carried at the lower of average
cost or market. When sold from inventory, commodities are removed on a first-in,
first-out basis. Total commodity inventory was $2.4 million and $2.2 million as
of December 31, 2004 and 2003, respectively.

Oil and gas properties. The Company utilizes the successful efforts method
of accounting for its oil and gas properties. Under this method, all costs
associated with productive wells and nonproductive development wells are
capitalized while nonproductive exploration costs and geological and geophysical
expenditures are expensed. The Company capitalizes interest on expenditures for
significant development projects until such projects are ready for their
intended use.

The Company generally does not carry the costs of drilling an exploratory
well as an asset in its Consolidated Balance Sheets for more than one year
following the completion of drilling unless the exploratory well finds oil and
gas reserves in an area requiring a major capital expenditure and both of the
following conditions are met:

(i) The well has found a sufficient quantity of reserves to justify
its completion as a producing well if the required capital
expenditure is made.
(ii) Drilling of the additional exploratory wells is under way or
firmly planned for the near future.

64

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2004, 2003 and 2002

Due to the capital intensive nature and the geographical location of certain
Alaskan, deepwater Gulf of Mexico and foreign projects, it may take the Company
longer than one year to evaluate the future potential of the exploration well
and economics associated with making a determination on its commercial
viability. In these instances, the projects feasibility is not contingent upon
price improvements or advances in technology, but rather the Company's ongoing
efforts and expenditures related to accurately predicting the hydrocarbon
recoverability based on well information, gaining access to other companies
production, transportation or processing facilities and/or getting partner
approval to drill additional appraisal wells. These activities are ongoing and
being pursued constantly. Consequently, the Company's assessment of suspended
exploratory well costs is continuous until a decision can be made that the well
has found proved reserves or is noncommercial and is impaired. See Note D for
additional information regarding the Company's suspended exploratory well costs.

The Company owns interests in 11 natural gas processing plants and five
treating facilities. The Company operates seven of the plants and all five
treating facilities. The Company's ownership in the natural gas processing
plants and treating facilities is primarily to accommodate handling the
Company's gas production and thus are considered a component of the capital and
operating costs of the respective fields that they service. To the extent that
there is excess capacity at a plant or treating facility, the Company attempts
to process third party gas volumes for a fee to keep the plant or treating
facility at capacity. All revenues and expenses derived from third party gas
volumes processed through the plants and treating facilities are reported as
components of oil and gas production costs. The third party revenues generated
from the plant and treating facilities for the three years ended December 31,
2004, 2003 and 2002 were $45.9 million, $39.5 million and $28.4 million,
respectively. The third party expenses attributable to the plants and treating
facilities for the same respective periods were $11.9 million, $11.3 million and
$9.3 million. The capitalized costs of the plants and treating facilities are
included in proved oil and gas properties and are depleted using the unit-of-
production method along with the other capitalized costs of the field that they
service.

Capitalized costs relating to proved properties are depleted using the
unit-of-production method based on proved reserves. Costs of significant
nonproducing properties, wells in the process of being drilled and development
projects are excluded from depletion until such time as the related project is
completed and proved reserves are established or, if unsuccessful, impairment is
determined.

Proceeds from the sales of individual properties and the capitalized costs
of individual properties sold or abandoned are credited and charged,
respectively, to accumulated depletion, depreciation and amortization.
Generally, no gain or loss is recognized until the entire amortization base is
sold. However, gain or loss is recognized from the sale of less than an entire
amortization base if the disposition is significant enough to materially impact
the depletion rate of the remaining properties in the amortization base.

In accordance with Statement of Financial Accounting Standards No. 144,
"Accounting for the Impairment or Disposal of Long-Lived Assets" ("SFAS 144"),
the Company reviews its long-lived assets to be held and used, including proved
oil and gas properties accounted for under the successful efforts method of
accounting, whenever events or circumstances indicate that the carrying value of
those assets may not be recoverable. An impairment loss is indicated if the sum
of the expected future cash flows is less than the carrying amount of the
assets. In this circumstance, the Company recognizes an impairment loss for the
amount by which the carrying amount of the asset exceeds the estimated fair
value of the asset.

Unproved oil and gas properties are periodically assessed for impairment on
a project-by-project basis. The impairment assessment is affected by the results
of exploration activities, commodity price outlooks, planned future sales or
expiration of all or a portion of such projects. If the quantity of potential
reserves determined by such evaluations is not sufficient to fully recover the
cost invested in each project, the Company will recognize an impairment loss at
that time by recording an allowance.

65

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2004, 2003 and 2002

Goodwill. As is described in Note C, the Company recorded $324.8 million of
goodwill associated with the Evergreen merger. The goodwill was recorded to the
Company's United States reporting unit and will be subject to change during the
twelve-month period following the merger if the settlement values of monetary
assets acquired and liabilities assumed in the merger differ from their
estimated values as of September 28, 2004. In accordance with Emerging Issues
Task Force ("EITF") Abstract Issue No. 00-23, "Issues Related to the Accounting
for Stock Compensation under APB Opinion No. 25 and FASB Interpretation No. 44",
the Company reduced goodwill by $9.0 million during the fourth quarter of 2004
for tax benefits associated with the exercise of fully-vested stock options
assumed in conjunction with the Evergreen merger to the extent that the
stock-based compensation expense reported for tax purposes did not exceed the
fair value of the awards recognized as part of the total purchase price. In
accordance with Statement of Financial Accounting Standards No. 142, "Goodwill
and Other Intangible Assets", goodwill is not amortized to earnings but is
assessed for impairment whenever events or circumstances indicate that
impairment of the carrying value of goodwill is likely, but no less often than
annually. If the carrying value of goodwill is determined to be impaired, it is
reduced for the impaired value with a corresponding charge to pretax earnings in
the period in which it is determined to be impaired.

Treasury stock. Treasury stock purchases are recorded at cost. Upon
reissuance, the cost of treasury shares held is reduced by the average purchase
price per share of the aggregate treasury shares held.

Environmental. The Company's environmental expenditures are expensed or
capitalized depending on their future economic benefit. Expenditures that relate
to an existing condition caused by past operations and that have no future
economic benefits are expensed. Expenditures that extend the life of the related
property or mitigate or prevent future environmental contamination are
capitalized. Liabilities are recorded when environmental assessment and/or
remediation is probable and the costs can be reasonably estimated. Such
liabilities are undiscounted unless the timing of cash payments for the
liability are fixed or reliably determinable.

Revenue recognition. The Company does not recognize revenues until they are
realized or realizable and earned. Revenues are considered realized or
realizable and earned when: (i) persuasive evidence of an arrangement exists;
(ii) delivery has occurred or services have been rendered; (iii) the seller's
price to the buyer is fixed or determinable and (iv) collectibility is
reasonably assured.

The Company uses the entitlements method of accounting for oil, NGL and gas
revenues. Sales proceeds in excess of the Company's entitlement are included in
other liabilities and the Company's share of sales taken by others is included
in other assets in the accompanying Consolidated Balance Sheets.

The Company had no oil or natural gas liquid ("NGL") entitlement assets or
liabilities as of December 31, 2004 or 2003. The following table presents the
Company's gas entitlement assets and liabilities and their associated volumes as
of December 31, 2004 and 2003:

December 31,
-------------------------------------
2004 2003
---------------- -----------------
Amount MMcf Amount MMcf
------ ------ ------ ------
($ in millions)

Entitlement assets.................. $ 10.4 3,842 $ 10.5 3,929
Entitlement liabilities............. $ 14.7 11,859 $ 15.8 14,793

Derivatives and hedging. The Company follows the provisions of Statement of
Financial Accounting Standards No. 133, "Accounting for Derivative Instruments
and Hedging Activities" ("SFAS 133"). SFAS 133 requires the accounting
recognition of all derivative instruments as either assets or liabilities at

66

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2004, 2003 and 2002

fair value. Derivative instruments that are not hedges must be adjusted to fair
value through net income. Under the provisions of SFAS 133, the Company may
designate a derivative instrument as hedging the exposure to changes in the fair
value of an asset or a liability or an identified portion thereof that is
attributable to a particular risk (a "fair value hedge") or as hedging the
exposure to variability in expected future cash flows that are attributable to a
particular risk (a "cash flow hedge"). Both at the inception of a hedge and on
an ongoing basis, a fair value hedge must be expected to be highly effective in
achieving offsetting changes in fair value attributable to the hedged risk
during the periods that a hedge is designated. Similarly, a cash flow hedge must
be expected to be highly effective in achieving offsetting cash flows
attributable to the hedged risk during the term of the hedge. The expectation of
hedge effectiveness must be supported by matching the essential terms of the
hedged asset, liability or forecasted transaction to the derivative hedge
contract or by effectiveness assessments using statistical measurements. The
Company's policy is to assess hedge effectiveness at the end of each calendar
quarter.

Under the provisions of SFAS 133, changes in the fair value of derivative
instruments that are fair value hedges are offset against changes in the fair
value of the hedged assets, liabilities, or firm commitments through net income.
Effective changes in the fair value of derivative instruments that are cash flow
hedges are recognized in accumulated other comprehensive income (loss) - net
deferred hedge losses, net of tax in the stockholders' equity section of the
Company's Consolidated Balance Sheets until such time as the hedged items are
recognized in net income. Ineffective portions of a derivative instrument's
change in fair value are immediately recognized in net income.

See Note K for a description of the specific types of derivative
transactions in which the Company participates.

Stock-based compensation. The Company has a long-term incentive plan (the
"Long-Term Incentive Plan") under which the Company grants stock-based
compensation. The Long-Term Incentive Plan is described more fully in Note H.
The Company accounts for stock-based compensation granted under the Long-Term
Incentive Plan using the intrinsic value method prescribed by Accounting
Principles Bulletin Opinion No. 25, "Accounting for Stock Issued to Employees"
("APB 25") and related interpretations. Stock-based compensation expense
associated with option grants was not recognized in the determination of the
Company's net income during the years ended December 31, 2004, 2003 and 2002, as
all options granted under the Long-Term Incentive Plan had exercise prices equal
to the market value of the underlying common stock on the dates of grant or were
issued in exchange for fully-vested Evergreen options as purchase consideration
in the Evergreen merger. Stock-based compensation expense associated with
restricted stock awards is deferred and amortized to earnings ratably over the
vesting periods of the awards. See "New accounting pronouncement" below for
information regarding the Company's adoption of Statement of Financial
Accounting Standards No. 123 (revised 2004), "Share-Based Payment" ("SFAS
123(R)") on July 1, 2005.

67

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2004, 2003 and 2002

The following table illustrates the pro forma effect on net income and
earnings per share as if the Company had applied the fair value recognition
provisions of Statement of Financial Accounting Standards No. 123, "Accounting
for Stock-Based Compensation" ("SFAS 123"), to stock-based compensation during
the years ended December 31, 2004, 2003 and 2002:

Year ended December 31,
------------------------------------
2004 2003 2002
--------- --------- ----------
(in thousands, except per share amounts)

Net income, as reported.............................. $ 312,854 $ 410,592 $ 26,713
Plus: Stock-based compensation expense included
in net income for all awards, net of tax (a)....... 7,939 3,447 1,884
Deduct: Stock-based compensation expense
determined under fair value based method
for all awards, net of tax (a)..................... (13,985) (11,429) (11,691)
-------- -------- --------
Pro forma net income................................. $ 306,808 $ 402,610 $ 16,906
======== ======== ========
Net income per share:
Basic - as reported................................ $ 2.50 $ 3.50 $ .24
======== ======== ========
Basic - pro forma.................................. $ 2.45 $ 3.44 $ .15
======== ======== ========
Diluted - as reported.............................. $ 2.46 $ 3.46 $ .23
======== ======== ========
Diluted - pro forma................................ $ 2.41 $ 3.40 $ .15
======== ======== ========

- -----------
(a) For the years ended December 31, 2004 and 2003, stock-based compensation
expense included in net income is net of tax benefits of $4.6 million and
$2.0 million, respectively. Similarly, stock-based compensation expense
determined under the fair value based method for the years ended December
31, 2004 and 2003 is net of tax benefits of $8.0 million and $6.6 million,
respectively. No tax benefits were recognized for the stock-based
compensation expense amounts during the year ended December 31, 2002. See
Note Q for additional information regarding the Company's income taxes.

Foreign currency translation. The U.S. dollar is the functional currency
for all of the Company's international operations except Canada. Accordingly,
monetary assets and liabilities denominated in a foreign currency are remeasured
to U.S. dollars at the exchange rate in effect at the end of each reporting
period; revenues and costs and expenses denominated in a foreign currency are
remeasured at the average of the exchange rates that were in effect during the
period in which the revenues and costs and expenses were recognized. The
resulting gains or losses from remeasuring foreign currency denominated balances
into U.S. dollars are recorded in other income or other expense, respectively.
Nonmonetary assets and liabilities denominated in a foreign currency are
remeasured at the historic exchange rates that were in effect when the assets or
liabilities were acquired or incurred.

The functional currency of the Company's Canadian operations is the
Canadian dollar. The financial statements of the Company's Canadian subsidiary
entities are translated to U.S. dollars as follows: all assets and liabilities
are translated using the exchange rate in effect at the end of each reporting
period; revenues and costs and expenses are translated using the average of the
exchange rates that were in effect during the period in which the revenues and
costs and expenses were recognized. The resulting gains or losses from
translating non-U.S. dollar denominated balances are recorded in the
accompanying Consolidated Statements of Stockholders' Equity for the period
through accumulated other comprehensive income (loss) - cumulative translation
adjustment.

68

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2004, 2003 and 2002

The following table presents the exchange rates used to translate the
financial statements of the Company's Canadian subsidiaries in the preparation
of the consolidated financial statements as of and for the years ended December
31, 2004, 2003 and 2002:

December 31,
-----------------------
2004 2003 2002
----- ----- -----

U.S. Dollar from Canadian Dollar - Balance Sheets............... .8320 .7710 .6362
U.S. Dollar from Canadian Dollar - Statements of Operations..... .7699 .7161 .6371

Reclassifications. Certain reclassifications have been made to the 2003 and
2002 amounts in order to conform with the 2004 presentation. Specifically, the
Company reduced oil and gas revenues and production costs by $40.6 million and
$23.6 million for the years ended December 31, 2003 and 2002, respectively, to
conform with its current treatment of field fuel. During 2004, the Company
changed its treatment of field fuel, which is gas consumed to operate field
equipment, to exclude the field fuel gas from oil and gas revenues and
production costs. The Company also increased oil and gas revenues and production
costs by $15.8 million and $16.2 million for the years ended December 31, 2003
and 2002, respectively, to conform with its current treatment of Canadian gas
transportation costs. During 2004, the Company changed its treatment of Canadian
gas transportation costs to include these costs as a component of oil and gas
production costs. In prior years, transportation costs were recorded as a
reduction to oil and gas revenues.

New accounting pronouncement. On December 16, 2004, the Financial
Accounting Standards Board ("FASB") issued SFAS 123(R), which is a revision of
SFAS 123. SFAS 123(R) supersedes APB 25 and amends Statement of Accounting
Standards No. 95, "Statement of Cash Flows". Generally, the approach in SFAS
123(R) is similar to the approach described in SFAS 123. However, SFAS 123(R)
will require all share-based payments to employees, including grants of employee
stock options, to be recognized in the Company's Consolidated Statements of
Operations based on their fair values. Pro forma disclosure is no longer an
alternative.

SFAS 123(R) must be adopted no later than July 1, 2005 and permits public
companies to adopt its requirements using one of two methods:

o A "modified prospective" method in which compensation cost is recognized
beginning with the effective date based on the requirements of SFAS 123(R)
for all share-based payments granted after the adoption date and based on
the requirements of SFAS 123 for all awards granted to employees prior to
the effective date of SFAS 123(R) that remain unvested on the adoption
date.
o A "modified retrospective" method which includes the requirements of the
modified prospective method described above, but also permits entities to
restate either all prior periods presented or prior interim periods of the
year of adoption based on the amounts previously recognized under SFAS 123
for purposes of pro forma disclosures.

The Company has elected to adopt the provisions of SFAS 123(R) on July 1, 2005
using the modified prospective method.

As permitted by SFAS 123, the Company currently accounts for share-based
payments to employees using the intrinsic value method prescribed by APB 25 and
related interpretations. As such, the Company generally does not recognize
compensation expenses associated with employee stock options. Accordingly, the
adoption of SFAS 123(R)'s fair value method could have a significant impact on
the Company's future result of operations, although it will have no impact on
the Company's overall financial position. Had the Company adopted SFAS 123(R) in
prior periods, the impact would have approximated the impact of SFAS 123 as
described in the pro forma net income and earnings per share disclosures above.
The adoption of SFAS 123(R) will have no effect on the Company's unvested
outstanding restricted stock awards. The Company estimates that the adoption of
SFAS 123(R), based on the outstanding unvested stock options at December 31,
2004, will result in future compensation charges to general and administrative

69

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2004, 2003 and 2002

expenses of approximately $1.8 million during the period from July 1, 2005
through December 31, 2005, and approximately $1.1 million during 2006.

The Company has an Employee Stock Purchase Plan (the "ESPP") that allows
eligible employees to annually purchase the Company's common stock at a
discount. The provisions of SFAS 123(R) will cause the ESPP to be a compensatory
plan. However, the change in accounting for the ESPP is not expected to have a
material impact on the Company's financial position, future results of
operations or liquidity. Historically, the ESPP compensatory amounts have been
nominal. See Note H for additional information regarding the ESPP.

SFAS 123(R) also requires the tax benefits in excess of recognized
compensation expenses to be reported as a financing cash flow, rather than as an
operating cash flow as required under current literature. This requirement may
serve to reduce the Company's future cash provided by operating activities and
increase future cash provided by financing activities, to the extent of
associated tax benefits that may be realized in the future. While the Company
cannot estimate what those amounts will be in the future (because they depend
on, among other things, when employees exercise stock options), the amount of
operating cash flows recognized in prior periods for such excess tax deductions
were $6.6 million and $14.7 million during the years ended December 31, 2004 and
2003, respectively. The Company did not recognize any such tax benefits during
2002.

NOTE C. Acquisitions

Evergreen Merger. On September 28, 2004, Pioneer completed its merger with
Evergreen with Pioneer being the surviving corporation for accounting purposes.
The transaction was accounted for as a purchase of Evergreen by Pioneer in
accordance with SFAS 141. The merger with Evergreen was accomplished through the
issuance of 25.4 million shares of Pioneer common stock and $851.1 million of
cash paid, net of $12.1 million of acquired cash, to the Evergreen shareholders
at closing. The value of each share of Pioneer was based on the five-day average
closing price of Pioneer's common stock surrounding the May 3, 2004 announcement
date of the merger, which equaled $32.578 per share. In addition, as
consideration for Evergreen's Kansas assets, which were sold to a third party
for net proceeds of $20.9 million on September 27, 2004, Evergreen stockholders
received an additional cash payment equal to $.48 per Evergreen common share.
The cash consideration paid in the merger was financed through borrowings on the
Company's new $900 million 364-day senior unsecured revolving credit facility
(the "364-Day Credit Agreement"). During the fourth quarter of 2004, the Company
paid $29.3 million of transaction costs associated with the merger that were
accrued but unpaid on September 28, 2004.

70

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2004, 2003 and 2002

The following table represents the allocation of the total purchase price
of Evergreen to the acquired assets and assumed liabilities based upon the fair
values assigned to each of the significant assets acquired and liabilities
assumed. The fair value of the proved properties was based on the Company's
estimate of the present value of the acquired proved reserves. Likewise, the
fair value of the unproved properties was estimated by risk-weighting the
present value of the acquired probable reserves. Any future adjustments to the
allocation of the purchase price are not anticipated to be material to the
Company's financial statements.

(in thousands)
--------------

Fair value of Evergreen's net assets:
Net working capital, including cash of $12.1 million...................... $ (44,956)
Proved oil and gas properties............................................. 2,235,935
Unproved oil and gas properties........................................... 274,917
Other assets.............................................................. 40,506
Goodwill ................................................................. 324,835
Long-term debt............................................................ (305,500)
Deferred income tax liabilities........................................... (657,035)
Other noncurrent liabilities, including minority interest in subsidiaries. (33,320)
Deferred compensation associated with unvested restricted stock awards.... 6,001
Additional paid-in capital (excess fair value of convertible debt attributable
to equity conversion rights)............................................ (63,500)
----------
$ 1,777,883
==========
Consideration paid for Evergreen's net assets:
Pioneer common stock issued............................................... $ 826,514
Cash consideration paid................................................... 863,193
----------
Aggregate purchase consideration issued to Evergreen stockholders......... 1,689,707
Plus:
Pioneer common stock issuable to holders of unvested restricted stock
awards upon lapse of restrictions................................... 6,568
Proceeds from the sale of Kansas properties to be paid to holders of
unvested restricted stock awards upon lapse of restrictions......... 83
Exchange of Evergreen employee stock options.......................... 51,006
Estimated direct merger costs incurred................................ 30,519
----------
Total purchase price................................................ $ 1,777,883
==========

Evergreen was a publicly-traded independent oil and gas company primarily
engaged in the production, development, exploration and acquisition of North
American unconventional gas. Evergreen was based in Denver, Colorado and was one
of the leading developers of coal bed methane reserves in the United States.
Evergreen's operations were principally focused on developing and expanding its
coal bed methane field located in the Raton Basin in southern Colorado.
Evergreen also had operations in the Piceance Basin in western Colorado, the
Uinta Basin in eastern Utah and the Western Canada Sedimentary Basin as a result
of Evergreen's acquisition of Carbon Energy Corporation on October 29, 2003 (the
"Carbon acquisition").

The merger with Evergreen provided an opportunity for the Company to
rebalance its portfolio of long-lived foundation assets by adding Evergreen's
long-lived onshore producing asset base and significant low-risk development and
extension drilling opportunities. Additionally, the Company's decision to
complete the merger was positively impacted by the compatible technical and
corporate cultures of Pioneer and Evergreen, Evergreen's substantial acreage
position in key growth basins of the United States Rockies area and the

71

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2004, 2003 and 2002

opportunity to leverage Evergreen's technical expertise in the area of coal bed
methane operations, which management believes could have further application in
other areas of the United States. These strategic opportunities were among the
factors considered when the Company determined its offering price for Evergreen.

Included in working capital and other assets in the table above is $6.4
million of intangible assets attributable to noncompete agreements executed with
three former executive officers of Evergreen, including Mr. Mark Sexton, a
director of the Company since the merger and formerly Evergreen's President,
Chief Executive Officer and Chairman of the board of directors. The noncompete
agreements are being amortized on a straight-line basis as charges to the
Company's net income during the two-year period ending September 28, 2006.
Additionally, the Company recorded $324.8 million of goodwill associated with
the Evergreen merger, which amount represents the excess of the purchase
consideration over the net fair value of the identifiable net assets acquired.
Based on the expected strategic benefits of the Evergreen merger that are
expected to be realized on a reporting unit basis, the goodwill has been
recorded as an asset of the Company's United States reporting unit. The goodwill
is not expected to be deductible for income tax purposes. The fair values of the
monetary assets acquired and liabilities assumed is being monitored during the
twelve-month period ending September 28, 2005 and will be adjusted if their
settlement values differ from the estimated fair values assigned to them as of
September 28, 2004. Forthcoming adjustments of the fair values assigned to
acquired monetary assets and liabilities, if required, will change the value
assigned to goodwill in the merger.

The following unaudited pro forma combined condensed financial data for the
years ended December 31, 2004 and 2003 were derived from the historical
financial statements of Pioneer and Evergreen giving effect to the merger as if
the merger and the Carbon acquisition had each occurred on January 1, 2003. The
unaudited pro forma combined condensed financial data have been included for
comparative purposes only and are not necessarily indicative of the results that
might have occurred had the transactions taken place as of the dates indicated
and are not intended to be a projection of future results.

Year ended December 31,
-------------------------------
2004 2003
----------- -----------
(in thousands, except per share amounts)

Revenues.................................................. $ 2,029,841 $ 1,547,752
========== ==========
Income before cumulative effect of change in
accounting principle.................................... $ 326,132 $ 414,925
Cumulative effect of change in accounting principle,
net of tax.............................................. - 15,036
---------- ----------
Net income................................................ $ 326,132 $ 429,961
========== ==========
Basic earnings per share:
Income before cumulative effect of change
in accounting principle.............................. $ 2.26 $ 2.91
Cumulative effect of change in accounting
principle, net of tax................................ - .11
---------- ----------
Net income.............................................. $ 2.26 $ 3.02
========== ==========
Diluted earnings per share:
Income before cumulative effect of change
in accounting principle.............................. $ 2.20 $ 2.83
Cumulative effect of change in accounting
principle, net of tax................................ - .10
---------- ----------
Net income.............................................. $ 2.20 $ 2.93
========== ==========

72

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2004, 2003 and 2002

Falcon acquisitions. During the year ended December 31, 2002, the Company
purchased, through two transactions, an additional 30 percent working interest
in the Falcon field development and a 25 percent working interest in associated
acreage in the deepwater Gulf of Mexico for a combined purchase price of $61.1
million. As a result of these transactions, the Company owned a 75 percent
working interest in and operated the Falcon field development and related
exploration blocks at December 31, 2002. On March 28, 2003, the Company
purchased the remaining 25 percent working interest that it did not already own
in the Falcon field, the Harrier field and surrounding satellite prospects in
the deepwater Gulf of Mexico for $120.4 million, including $114.1 million of
cash, $1.7 million of asset retirement obligations assumed and $4.6 million of
closing adjustments.

West Panhandle acquisitions. During July 2002, the Company completed the
purchase of the remaining 23 percent of the rights that the Company did not
already own in its core area West Panhandle gas field, 100 percent of the
related West Panhandle field gathering system and ten blocks surrounding the
Company's deepwater Gulf of Mexico Falcon discovery. In connection with these
transactions, the Company recorded $100.4 million to proved oil and gas
properties, $3.8 million to unproved oil and gas properties and $1.9 million to
assets held for resale; retired a capital cost obligation for $60.8 million;
settled a $20.9 million gas balancing receivable; assumed trade and
environmental obligations amounting to $5.8 million in the aggregate; and paid
$140.2 million of cash. The capital cost obligation retired by the Company for
$60.8 million represented an obligation for West Panhandle gas field capital
additions that was not able to be prepaid and bore interest at an annual rate of
20 percent. The portion of the purchase price allocated to the retirement of the
capital cost obligation was based on a discounted cash flow analysis using a
market discount rate for obligations with similar terms. The capital cost
obligation had a carrying value of $45.2 million, resulting in a loss of $15.6
million from the early extinguishment of this obligation.

Other acquisitions. During 2004, the Company spent $20.2 million to acquire
various additional working interests in the Spraberry field. The Company also
spent $16.8 million to acquire acreage in Alaska and $10.5 million in Canada to
acquire producing property and undeveloped acreage in southern Alberta. In
addition to these acquisitions, the Company spent $43.2 million to acquire
producing properties in the United States and unproved properties in the Gulf of
Mexico, Canada and Africa. During 2003, in addition to the incremental 25
percent working interest acquired in the Falcon area, the Company spent $30.6
million to acquire producing properties in the Spraberry field and unproved
properties in Alaska, the Gulf of Mexico, Argentina, Canada and Tunisia. During
2002, in addition to the Falcon and West Panhandle acquisitions referred to
above, the Company spent $25.5 million to acquire additional unproved acreage in
the United States, including 34 Gulf of Mexico shelf blocks, six deepwater Gulf
of Mexico blocks, a 70 percent working interest in ten state leases on Alaska's
North Slope and property interests in other areas of the United States. Also
during 2002, the Company acquired unproved and proved oil and gas property
interests in Canada for $2.3 million and $.5 million, respectively, and $1.8
million of additional unproved property interests in Tunisia.

NOTE D. Exploratory Well Costs

The Company capitalizes exploratory well costs until a decision is made
that the well has found proved reserves or that it is impaired, in which case
the well costs are charged to expense.

73

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2004, 2003 and 2002

The following table reflects the Company's capitalized exploratory well
activity during each of the years ended December 31, 2004, 2003 and 2002:

Year ended December 31,
---------------------------------------
2004 2003 2002
--------- --------- ---------
(in thousands)

Beginning of year ................................... $ 108,986 $ 71,500 $ 52,975
Additions to exploratory well costs pending the
determination of proved reserves................... 156,937 216,352 89,128
Reclassifications to proved reserves................. (56,639) (117,966) (34,072)
Exploratory well costs charged to expense............ (82,812) (60,900) (36,531)
-------- -------- --------
End of year ......................................... $ 126,472 $ 108,986 $ 71,500
======== ======== ========

The following table provides an aging as of December 31, 2004, 2003 and
2002 of capitalized exploratory well costs based on the date the drilling was
completed and the number of wells for which exploratory well costs have been
capitalized for a period greater than one year since the date the drilling was
completed:

December 31,
---------------------------------------
2004 2003 2002
--------- --------- ---------
(in thousands, except well counts)

Capitalized exploratory well costs that have been
capitalized for a period of one year or less...... $ 35,046 $ 75,120 $ 46,020
Capitalized exploratory well costs that have been
capitalized for a period greater than one year.... 91,426 33,866 25,480
-------- -------- --------
$ 126,472 $ 108,986 $ 71,500
======== ======== ========
Number of wells that have exploratory well costs
that have been capitalized for a period greater
than one year..................................... 10 3 4
======== ======= ========

The following table provides the capitalized exploratory well costs of
significant discrete exploration prospects that have been suspended for more
than one year as of December 31, 2004, 2003 and 2002:

December 31,
---------------------------------------
2004 2003 2002
--------- --------- ---------
(in thousands)

United States:
Ozona Deep........................................ $ 19,462 $ 19,003 $ -
Alaska - Oooguruk................................. 47,083 - -

Canada:
Other............................................. 1,214 - 238

Africa:
South African gas project......................... 14,895 14,863 14,790
Tunisia - Anaguid................................. 8,772 - -
Gabon............................................. - - 10,452
-------- -------- --------
Total............................................. $ 91,426 $ 33,866 $ 25,480
======== ======== ========

74

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2004, 2003 and 2002

The Company's Ozona Deep exploration well was drilled during 2002 and found
quantities of oil believed to be commercial; however, given its location in the
Gulf of Mexico, it is necessary to have a signed production handling agreement
("PHA") with infrastructure in the area to insure the economics associated with
the discovery prior to doing further appraisal drilling. Pioneer and the
operator of Ozona Deep have been diligently engaging potential counterparties to
enter into a PHA to bring future production from the discovery to their
platform. The Company anticipates entering into a PHA and drilling an appraisal
well during 2005.

During 2003, the Company's Alaskan Oooguruk discovery wells found
quantities of oil believed to be commercial. In 2003, the Company began farm-in
discussions with the owner of undeveloped discoveries in adjacent acreage given
its proximity and the potential costs benefits of a larger scale project. The
farm-in was completed during 2004. Along with completing the farm-in agreement,
Pioneer obtained access to exploration well and seismic data to help better
understand the potential of the discoveries without having to drill additional
wells. In late 2004, the Company completed an extensive technical and economic
evaluation of the resource potential within this area and authorized a front-end
engineering and design study ("FEED study") for the area which is expected to be
completed in 2005. If the FEED study confirms favorable development economics,
the Company will seek to obtain regulatory approval to develop the field in
2006, targeting first oil sales in 2008. Simultaneously, the Company is working
to secure throughput agreements to process the associated potential oil
production at a nearby facility should the project be sanctioned.

During 2001, the Company drilled two South African discovery wells that
found quantities of condensate and gas believed to be commercial. During 2004,
2003 and 2002, the Company actively reviewed the gas supply and demand
fundamentals in South Africa and had discussions with a gas-to-liquids plant in
the area to purchase the condensate and gas. During 2004, a FEED study was
authorized for the gas development and infrastructure design. The FEED study was
completed in early 2005 and based on that study, the plant operator has
initiated purchase orders for long-lead time infrastructure components.
Currently, negotiations are underway to secure a production contract and it is
the Company's expectation that the project will be sanctioned in 2005.

During 2003, the Company drilled two exploration wells on its Anaguid Block
in Tunisia which found quantities of condensate and gas believed to be
commercial. During 2004, the wells were scheduled and approved for extended
production tests. However, the project operator delayed the extended production
tests due to issues unrelated to the Company or the project. In 2005, the
project operator, along with the Company, has approved extended production tests
of the existing wells and the drilling of two additional appraisal wells.

75

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2004, 2003 and 2002

NOTE E. Disclosures About Fair Value of Financial Instruments

The following table presents the carrying amounts and estimated fair values
of the Company's financial instruments as of December 31, 2004 and 2003:

December 31,
--------------------------------------------------
2004 2003
----------------------- -----------------------
Carrying Fair Carrying Fair
Value Value Value Value
---------- ---------- ---------- ----------
(in thousands)

Derivative contract liabilities:
Commodity price hedges......................... $ (406,546) $ (406,546) $ (201,422) $ (201,422)
Unrealized terminated commodity price hedges... $ (660) $ (660) $ (1,490) $ (1,490)
Btu swap contracts............................. $ - $ - $ (6,855) $ (6,855)
Financial assets:
Trading securities............................. $ 11,115 $ 11,115 $ 7,596 $ 7,596
5-1/2% note receivable due 2008................ $ 1,786 $ 1,786 $ 2,086 $ 2,086
Financial liabilities - long-term debt:
Lines of credit................................ $ (828,000) $ (828,000) $ (160,000) $ (160,000)
8-7/8% senior notes due 2005................... $ (131,762) $ (133,078) $ (135,239) $ (141,426)
8-1/4% senior notes due 2007................... $ (32,520) $ (35,465) $ (155,253) $ (171,188)
6-1/2% senior notes due 2008................... $ (350,326) $ (374,500) $ (354,497) $ (378,725)
9-5/8% senior notes due 2010................... $ (62,973) $ (78,672) $ (350,558) $ (424,385)
5-7/8% senior notes due 2012................... $ (199,687) $ (203,198) $ - $ -
7-1/2% senior notes due 2012................... $ (15,157) $ (18,621) $ (150,000) $ (162,990)
5-7/8% senior notes due 2016................... $ (415,609) $ (549,478) $ - $ -
4-3/4% senior convertible notes due 2021 (a)... $ (100,000) $ (165,598) $ - $ -
7-1/5% senior notes due 2028................... $ (249,916) $ (287,500) $ (249,914) $ (270,312)

- -------------
(a) Carrying value excludes $63.5 million which was recognized in additional
paid-in capital in conjunction with the Evergreen merger for the fair value
of the convertible debt attributable to the equity conversion rights. See
Note C for information regarding the Evergreen merger.

Cash and cash equivalents, accounts receivable, other current assets,
accounts payable, interest payable and other current liabilities. The carrying
amounts approximate fair value due to the short maturity of these instruments.

Commodity price swap and collar contracts, interest rate swaps and foreign
currency swap contracts. The fair value of commodity price swap and collar
contracts, interest rate swaps and foreign currency contracts are estimated from
quotes provided by the counterparties to these derivative contracts and
represent the estimated amounts that the Company would expect to receive or pay
to settle the derivative contracts. See Note K for a description of each of
these derivatives, including whether the derivative contract qualifies for hedge
accounting treatment or is considered a speculative derivative contract.

Financial assets. The carrying amounts of the trading securities
approximates fair value due to the short maturity of these instruments. The fair
value of the 5-1/2 percent note receivable due 2008 was determined based on
underlying market rates of interest. The current portion of the 5-1/2% note
receivable due 2008, amounting to $.4 million as of December 31, 2004 and 2003,
is included in other current assets in the Company's Consolidated Balance
Sheets. The trading securities and the noncurrent portions of the 5-1/2% note
receivable due 2008 are included in other assets in the Company's Consolidated
Balance Sheets.

76

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2004, 2003 and 2002

Long-term debt. The carrying amount of borrowings outstanding under the
Company's corporate credit facility approximates fair value because these
instruments bear interest at variable market rates. The fair values of each of
the senior note issuances were determined based on quoted market prices for each
of the issues. See Note F for additional information regarding the Company's
long-term debt.

NOTE F. Long-term Debt

Long-term debt, including the effects of net deferred fair value hedges
gains (losses) and issuance discounts and premiums, consisted of the following
components at December 31, 2004 and 2003:

December 31,
---------------------------
2004 2003
---------- -----------
(in thousands)

Outstanding debt principal balances:
Lines of credit..................................... $ 828,000 $ 160,000
8-7/8% senior notes due 2005........................ 130,950 130,950
8-1/4% senior notes due 2007........................ 32,075 150,000
6-1/2% senior notes due 2008........................ 350,000 350,000
9-5/8% senior notes due 2010........................ 64,044 339,169
5-7/8% senior notes due 2012........................ 194,485 -
7-1/2% senior notes due 2012........................ 16,175 150,000
5-7/8% senior notes due 2016........................ 526,875 -
4-3/4% senior convertible notes due 2021............ 100,000 -
7-1/5% senior notes due 2028........................ 250,000 250,000
--------- ---------
2,492,604 1,530,119
Issuance discounts and premiums, net.................... (103,170) (2,033)
Net deferred fair value hedge gains (losses)............ (3,484) 27,375
--------- ---------
Total long-term debt............................... $2,385,950 $1,555,461
========= =========

Principal maturities of long-term debt at December 31, 2004 are as follows
(in thousands):

2005....................................... $ 130,950
2006....................................... $ 800,000
2007....................................... $ 32,075
2008....................................... $ 378,000
2009....................................... $ -
Thereafter................................. $1,151,579

During the year ending December 31, 2005, $131 million of the Company's
8-7/8% senior notes due 2005 (the "8-7/8 Notes") will mature and the first
anniversary of the Company's 364-Day Credit Agreement will occur. The Company
intends to initially utilize unused borrowing capacity under its 364-Day Credit
Agreement to repay the 8-7/8% Notes and to transfer outstanding borrowings, if
any, under the 364-Day Credit Agreement to the Company's five-year unsecured
revolving credit agreement (the "Revolving Credit Agreement") on its first
anniversary. As a result of the Evergreen merger, the $100 million of 4 3/4%
senior convertible notes due 2021 (the "Convertible Notes") are redeemable at
any time at the option of the holders. If the holders of the Convertible Notes
do not redeem the Convertible Notes prior to December 20, 2006, the Company
intends to exercise its rights under the indenture and redeem the Convertible
Notes on such date for cash, common stock or a combination thereof. If the
holders exercise their rights to redeem the Convertible Notes prior to December
20, 2006, the Company intends to refinance the cash redemption costs with unused
borrowing capacity under the Revolving Credit Agreement. The Convertible Notes
are reflected in "Thereafter" in the above maturities table. Accordingly, the
Company has classified these debt obligations as long-term in its Consolidated
Balance Sheet as of December 31, 2004.

77

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2004, 2003 and 2002

Lines of credit. In December 2003, the Company entered into the Revolving
Credit Agreement, as amended, that matures in December 2008. The terms of the
Revolving Credit Agreement provide for initial aggregate loan commitments of
$700 million from a syndication of participating banks (the "Lenders").
Aggregate loan commitments under the Revolving Credit Agreement may be increased
to a maximum aggregate amount of $1 billion if the Lenders increase their loan
commitments or if loan commitments of new financial institutions are added to
the Revolving Credit Agreement. During June 2004, the Company entered into a
first amendment (the "First Amendment") to its Revolving Credit Agreement. As a
result of the First Amendment, Pioneer Natural Resources USA, Inc., a
wholly-owned subsidiary of the Company ("Pioneer USA"), is no longer a guarantor
of the Revolving Credit Agreement. Borrowings under the Revolving Credit
Agreement may be in the form of revolving loans or swing line loans. Aggregate
outstanding swing line loans may not exceed $80 million. Revolving loans bear
interest, at the option of the Company, based on (a) a rate per annum equal to
the higher of the prime rate announced from time to time by JPMorgan Chase Bank
(5.25 percent per annum at December 31, 2004) or the weighted average of the
rates on overnight Federal funds transactions with members of the Federal
Reserve System during the last preceding business day plus 50 basis point (2.47
percent per annum at December 31, 2004) or (b) a base Eurodollar rate,
substantially equal to the London Interbank Offered Rate ("LIBOR") (2.34 percent
per annum at December 31, 2004), plus a margin that is based on a grid of the
Company's debt rating (100 basis points per annum at December 31, 2004). Swing
line loans bear interest at a rate per annum equal to the "ASK" rate for Federal
funds periodically published by the Dow Jones Market Service. The Company pays
commitment fees on the undrawn amounts under the Revolving Credit Agreement
based on a grid of the Company's debt rating (.25 percent per annum at December
31, 2004). As of December 31, 2004, the Company had $28 million borrowed under
the Revolving Credit Agreement.

In September 2004, the Company entered into the 364-Day Credit Agreement,
as amended, that provided for initial loan commitments of $900 million. The
364-Day Credit Agreement was utilized to finance the Evergreen merger.
Borrowings under the 364-Day Credit Agreement may, at the option of the Company,
be designated to bear interest based on (a) a rate per annum equal to the higher
of the prime rate announced from time to time by JPMorgan Chase Bank or the
weighted average of the rates on overnight Federal funds transactions with
members of the Federal Reserve System during the last preceding business day
plus 50 basis points or (b) a base Eurodollar rate, substantially equal to
LIBOR, plus a margin that is based on a grid of the Company's debt rating (75
basis points per annum at December 31, 2004). The Company pays commitment fees
on the undrawn amounts under the 364-Day Credit Agreement based on grid of the
Company's debt rating (.25 percent per annum at December 31, 2004). As of
December 31, 2004, the Company had $800 million revolving loans outstanding on
the 364-Day Credit Agreement.

The Revolving Credit Agreement and 364-Day Credit Agreement (collectively
the "Lines of Credit") share similar restrictive covenants. Those restrictive
covenants include the maintenance of a ratio of the Company's earnings before
gain or loss on the disposition of assets, interest expense, income taxes,
depreciation, depletion and amortization expense, exploration and abandonments
expense and other noncash charges and expenses to consolidated interest expense
of at least 3.5 to 1.0; maintenance of a ratio of total debt to book
capitalization less intangible assets (other than intangible oil and gas
assets), accumulated other comprehensive income and certain noncash asset
write-downs not to exceed .60 to 1.0; and if the Company should fall below an
investment grade rating, maintenance of an annual ratio of the net present value
of the Company's oil and gas properties to total debt of at least 1.25 to 1.00.
The Company was in compliance with all of its debt covenants as of December 31,
2004.

As of December 31, 2004, the Company had $57.1 million of undrawn letters
of credit, of which $49.3 million were undrawn commitments under the Lines of
Credit. The letters of credit outstanding under the Revolving Credit Agreement
are subject to a per annum fee, based on a grid of the Company's debt rating,
representing the Company's LIBOR margin (100 basis points at December 31, 2004)
plus .125 percent. As of December 31, 2004, the Company had unused borrowing
capacity of $722.7 million under the Lines of Credit. During February 2005, the
Company requested a $250 million reduction in the loan commitments under the
364-Day Credit Agreement to $650 million.

78

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2004, 2003 and 2002

In January 2005, the Company amended the Lines of Credit primarily to (i)
provide for the Company's ability to enter into volumetric production payment
agreements and (ii) to clarify certain definitional matters.

Senior notes. The Company's senior notes are general unsecured obligations
ranking equally in right of payment with all other senior unsecured indebtedness
of the Company and are senior in right of payment to all existing and future
subordinated indebtedness of the Company. The Company is a holding company that
conducts all of its operations through subsidiaries; consequently, the senior
notes are structurally subordinated to all obligations of its subsidiaries.
Interest on the Company's senior notes is payable semiannually. The indentures
of the Company's senior notes provide for subsidiary guarantees equivalent to
any such guarantees provided under the Revolving Credit Agreement. Accordingly,
the First Amendment also had the effect of removing Pioneer USA as a guarantor
of the Company's senior notes.

On July 15, 2004, the Company accepted tenders to exchange $117.9 million,
$275.1 million and $133.8 million in principal amount of its 8 1/4% senior notes
due 2007 (the "8 1/4% Notes"), 9-5/8% senior notes due 2010 (the "9- 5/8%
Notes") and 7.50% senior notes due 2012 (the "7.50% Notes" and collectively with
the 8 1/4% Notes and the 9- 5/8% Notes, the "Old Notes"), respectively, for a
like principal amount of a new series of 5.875% senior notes due 2016 (the "New
Notes") and cash. The aggregate exchange price paid to the holders of the
tendered notes exceeded their aggregate principal balances by $109.0 million,
which amount was paid in cash to holders of the New Notes. In accordance with
EITF Abstract Issue No. 96-19, "Debtors Accounting for a Modification or
Exchange of Debt Instruments", this amount is being amortized as an increase to
the Company's interest expense over the term of the New Notes. In connection
with the tenders of the 9-5/8% Notes and the 7.50% Notes, the Company received
consents which permanently removed substantially all of the operating
restrictions with respect to those notes once certain investment grade ratings
were achieved. Associated with the tenders to exchange the Old Notes, the
Company incurred direct transaction costs of $2.2 million during the year ended
December 31, 2004, which were recorded as charges to other expense in the
accompanying Consolidated Statements of Operations.

Interest on the New Notes is payable semiannually on January 15 and July 15
of each year, commencing January 15, 2005. The New Notes are governed by an
indenture between the Company and The Bank of New York dated January 13, 1998.
The New Notes are general unsecured obligations of the Company ranking equally
in right of payment with all other senior unsecured indebtedness of the Company
and are senior in right of payment to all existing and future subordinated
indebtedness of the Company.

In connection with the Evergreen merger, the Company assumed the position
of Evergreen as the issuer of the Convertible Notes and $200 million of 5.875%
Senior Subordinated Notes due 2012 (the "EVG 5.875% Notes"). In addition to a
4.75 percent fixed annual rate of interest, the Company is required to pay
contingent interest to the holders of the Convertible Notes. The rate of
contingent interest payable in respect to any six-month period equals the
greater of (i) a per annum rate equal to five percent of the Company's estimated
per annum borrowing rate for senior nonconvertible fixed-rate debt with a
maturity date comparable to the Convertible Notes or (ii) .30 percent per annum.
In no event may the contingent interest rate exceed .40 percent per annum. The
Company is accruing contingent interest on the Convertible Notes at the rate of
..30 per annum.

The Convertible Notes are due on December 15, 2021 but are redeemable at
either the Company's option or the holder's option on other specified dates. As
a result of the Evergreen merger, the Convertible Notes are convertible at any
time by the holders as discussed in the following paragraph. Holders may also
require the Company to repurchase all or part of the Convertible Notes on
December 20, 2006, December 15, 2011 or December 15, 2016 at a repurchase price
of 100 percent of the principal amount of the Convertible Notes plus accrued and
unpaid interest (including contingent interest). On December 20, 2006, the
Company may redeem the Convertible Notes in whole or in part in cash, in shares

79

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2004, 2003 and 2002

of common stock, or in any combination of cash and common stock. On December 15,
2011 or December 15, 2016, the Company must pay the repurchase price in cash.
The Company, currently, intends to exercise its rights under the indenture and
redeem the Convertible Notes on December 20, 2006, if the Convertible Notes have
not been redeemed by the holders.

Each $25.00 principal balance outstanding under the Convertible Notes is
convertible into .58175 shares of the Company's common stock plus $19.98 per
share, which includes Evergreen Kansas properties proceeds (as an example, each
$1,000 of Convertible Notes principal would exchange for 23.27 shares of the
Company's common stock plus $799 of cash). The portion of the Convertible Notes
exchangeable into the Company's common stock is included in the computation of
the Company's average diluted shares outstanding.

The EVG 5.875% Notes assumed in the Evergreen merger are due on March 15,
2012 with interest payable on March 15 and September 15 of each year. The EVG
5.875% Notes were unsecured senior subordinated indebtedness, were subordinated
in right of payment to all of the Company's existing and future senior
indebtedness, and ranked equally in right of payment with all of the Company's
future senior unsecured subordinated indebtedness. Prior to March 15, 2007, the
Company may redeem up to 35 percent of the original principal amount of the EVG
5.875% Notes with the net cash proceeds of one or more equity offerings at a
redemption price of 105.875 percent of the principal amount of the EVG 5.875%
Notes, plus accrued and unpaid interest. On or after March 15, 2008, the Company
may redeem all or a portion of the EVG 5.875% Notes at redemption prices ranging
from 102.938 percent to 100 percent of the principal amount, as provided by the
indenture for the EVG 5.875% Notes. The EVG 5.875% Notes also contain provisions
for redemption at the holders' option upon the occurrence of certain future
events, including a change in control. During October 2004, the Company,
pursuant to the indenture for the EVG 5.875% Notes, commenced an offer, in
connection with the change of control of Evergreen (the "Change of Control
Offer"), to repurchase any or all of the EVG 5.875% Notes at a purchase price in
cash equal to 101 percent of the principal amount of the EVG 5.875% Notes, plus
accrued and unpaid interest. The Change of Control Offer expired on November 10,
2004. In addition to the Change of Control Offer, during October 2004 the
Company solicited consents to proposed amendments to the EVG 5.875% Notes
indenture to:

o eliminate the subordination of the right of payment on the EVG
5.875% Notes to the payment in full of all existing and future
senior indebtedness of Pioneer;

o amend restrictive covenants applicable to the EVG 5.875% Notes so
that they are the same as the restrictive covenants in the
Company's senior notes that were originally issued as high-yield
notes; and

o amend the provisions of the EVG 5.875% Notes that suspend the
restrictive covenants when the EVG 5.875% Notes have certain
investment grade ratings so that those provisions are the same as
the suspension and permanent-elimination provisions in Pioneer's
senior notes that were originally issued as high-yield notes.

Holders of a majority in outstanding principal amount of the EVG 5.875% Notes
approved the proposed amendments on October 29, 2004. As a result, the EVG
5.875% Notes are no longer subordinated.

As of December 31, 2004, the aggregate carrying value of the Company's
senior notes was net of $3.5 million of unamortized net deferred hedge losses
realized from terminated fair value hedge interest rate swap contracts. As of
December 31, 2003, the aggregate carrying value of the Company's senior notes
included $27.4 million of incremental carrying value attributable to unamortized
net deferred hedge gains. See Note K for additional information regarding
terminated fair value hedge interest rate swap contracts.

80

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2004, 2003 and 2002

Early extinguishment of debt and capital cost obligation. In conjunction
with the Change of Control Offer, the Company repurchased $5.5 million of the
EVG 5.875% Notes during 2004. The Company recognized $.1 million of other income
associated with these debt extinguishments.

During 2003, the Company repurchased $5.1 million of its 8-7/8 percent
senior notes and repaid its former revolving credit agreement prior to its
scheduled maturity. The Company recognized $1.5 million of charges to other
expense associated with these debt extinguishments.

During 2002, the Company repurchased $47.1 million of the 9-5/8% Notes,
$13.9 million of the 8-7/8 percent senior notes and repaid a $45.2 million
capital cost obligation. The Company recognized a charge to other expense of
$22.3 million associated with these debt extinguishments.

Interest expense. The following amounts have been incurred and charged to
interest expense for the years ended December 31, 2004, 2003 and 2002:

Year Ended December 31,
---------------------------------------
2004 2003 2002
--------- --------- ---------
(in thousands)

Cash payments for interest................................... $ 110,135 $ 117,870 $ 113,827
Accretion/amortization of discounts or premiums on loans..... 3,683 2,873 5,488
Amortization of net deferred hedge gains (see Note K)........ (19,220) (26,114) (14,108)
Amortization of capitalized loan fees........................ 2,059 2,528 2,436
Kansas ad valorem tax (see Note J)........................... 65 103 375
Argentina accrued tax liability.............................. 1,205 - -
Net change in accruals....................................... 7,476 (424) 48
-------- -------- --------
Interest incurred.......................................... 105,403 96,836 108,066
Less capitalized interest.................................. (2,016) (5,448) (12,251)
-------- -------- --------
Total interest expense.................................. $ 103,387 $ 91,388 $ 95,815
======== ======== ========

NOTE G. Related Party Transactions

Activities with affiliated partnerships. The Company, through a
wholly-owned subsidiary, serves as operator of properties in which it and its
affiliated partnerships have an interest. Accordingly, the Company receives
producing well overhead, drilling well overhead and other fees related to the
operation of the properties. The affiliated partnerships also reimburse the
Company for their allocated share of general and administrative charges.
Reimbursements of fees are recorded as reductions to general and administrative
expenses in the Company's Consolidated Statements of Operations.

The activities with affiliated partnerships are summarized for the
following related party transactions for the years ended December 31, 2004, 2003
and 2002:

Year Ended December 31,
--------------------------
2004 2003 2002
------ ------ ------
(in thousands)

Receipt of lease operating and supervision charges in
accordance with standard industry operating agreements..... $1,458 $1,473 $1,495
Reimbursement of general and administrative expenses.......... $ 193 $ 148 $ 127

81

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2004, 2003 and 2002

NOTE H. Incentive Plans

Retirement Plans

Deferred compensation retirement plan. In August 1997, the Compensation
Committee of the Board of Directors approved a deferred compensation retirement
plan for the officers and certain key employees of the Company. Each officer and
key employee is allowed to contribute up to 25 percent of their base salary and
100 percent of their annual bonus. The Company will provide a matching
contribution of 100 percent of the officer's and key employee's contribution
limited to the first 10 percent of the officer's base salary and eight percent
of the key employee's base salary. The Company's matching contribution vests
immediately. A trust fund has been established by the Company to accumulate the
contributions made under this retirement plan. The Company's matching
contributions were $.9 million, $.9 million and $.8 million for the years ended
December 31, 2004, 2003 and 2002, respectively.

401(k) plan. The Pioneer Natural Resources USA, Inc. 401(k) and Matching
Plan (the "401(k) Plan") is a defined contribution plan established under the
Internal Revenue Code Section 401. The 401(k) Plan was formed by the merger of
the Pioneer Natural Resources USA, Inc. 401(k) Plan and the Pioneer Natural
Resources USA, Inc. Matching Plan on January 1, 2002. All regular full-time and
part-time employees of Pioneer USA are eligible to participate in the 401(k)
Plan on the first day of the month following their date of hire. Participants
may contribute an amount of not less than two percent nor more than 30 percent
of their annual salary into the 401(k) Plan. Matching contributions are made to
the 401(k) Plan in cash by Pioneer USA in amounts equal to 200 percent of a
participant's contributions to the 401(k) Plan that are not in excess of five
percent of the participant's basic compensation (the "Matching Contribution").
Each participant's account is credited with the participant's contributions,
their Matching Contributions and allocations of the 401(k) Plan's earnings.
Participants are fully vested in their account balances except for Matching
Contributions and their proportionate share of 401(k) Plan earnings attributable
to Matching Contributions, which proportionately vest over a four-year period
that begins with the participant's date of hire. During the years ended December
31, 2004, 2003 and 2002, the Company recognized compensation expense of $5.4
million, $4.5 million and $4.1 million, respectively, as a result of Matching
Contributions.

Long-Term Incentive Plan

In August 1997, the Company's stockholders approved a Long-Term Incentive
Plan which provides for the granting of incentive awards in the form of stock
options, stock appreciation rights, performance units and restricted stock to
directors, officers and employees of the Company. The Long-Term Incentive Plan
provides for the issuance of a maximum number of shares of common stock equal to
10 percent of the total number of shares of common stock equivalents outstanding
less the total number of shares of common stock subject to outstanding awards
under any stock- based plan for the directors, officers or employees of the
Company.

82

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2004, 2003 and 2002

The following table calculates the number of shares or options available
for grant under the Company's Long- Term Incentive Plan as of December 31, 2004
and 2003:

December 31,
--------------------------
2004 2003
----------- -----------

Shares outstanding, net of treasury stock............................. 144,831,662 119,287,772
Outstanding awards exercisable or exercisable within 60 days.......... 4,526,415 3,279,024
----------- -----------
149,358,077 122,566,796
Maximum shares/options allowed under the Long-Term Incentive Plan..... 14,935,808 12,256,680
Less: Outstanding awards under the Long-Term Incentive Plan.......... (4,790,028) (5,534,037)
Outstanding awards under predecessor incentive plans........... (1,838,543) (417,052)
----------- -----------
Shares/options available for future grant............................. 8,307,237 6,305,591
=========== ===========

Stock option awards. Prior to 2004, the Company had a program of awarding
semiannual stock options to its employees. The Company also gives its
non-employee directors a choice to receive (i) 100 percent restricted stock,
(ii) 100 percent stock options, (iii) 100 percent cash, or (iv) a combination of
50/50 of any two, as their annual compensation. This program provides for stock
option awards at an exercise price based upon the closing sales price of the
Company's common stock on the day prior to the date of grant. Stock option
awards vest over an 18-month or three-year schedule and provide a five-year
exercise period from each vesting date. Non-employee directors' stock options
vest quarterly and provide for a five-year exercise period from each vesting
date. The Company granted 1,353,988 and 1,643,212 options under the Long-Term
Incentive Plan during the years ended December 31, 2003 and 2002, respectively.

In accordance with the Merger Agreement, on September 28, 2004, the Company
assumed fully-vested options to purchase 2,384,657 shares of the Company's
common stock at various exercise prices, the weighted average price per share of
which was $11.18. The assumed options were outstanding awards to Evergreen
employees when the Evergreen merger occurred.

During 2004, the Company's stock-based compensation philosophy shifted its
emphasis from the awarding of stock options to restricted stock awards. There
were no options granted under the Long-Term Incentive Plan during the year ended
December 31, 2004.

Restricted stock awards. During the year ended December 31, 2004, the
Company assumed 214,186 restricted stock units in exchange for Evergreen
restricted stock units outstanding on September 28, 2004 and issued 630,937
restricted shares of the Company's common stock as compensation to directors,
officers and employees of the Company.

The Company recorded $6.0 million of deferred compensation for future
expected service associated with certain of the restricted stock units assumed
from Evergreen. The deferred compensation is being amortized as charges to
compensation expense over the periods in which the restrictions on the units
lapse.

During the years ended December 31, 2003 and 2002, the Company issued
77,625 and 654,445 restricted shares of the Company's common stock,
respectively. The restricted share awards were issued as compensation to
directors, officers and key employees of the Company.

83

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2004, 2003 and 2002

The Company recorded $19.1 million, $1.1 million and $16.2 million of
deferred compensation associated with restricted stock awards in the
stockholders' equity section during the years ended December 31, 2004, 2003 and
2002, respectively. Such amounts will be amortized to compensation expense over
the vesting periods of the awards. During the years ended December 31, 2004,
2003 and 2002, amortization of restricted stock awards increased the Company's
compensation expense by $12.5 million, $5.4 million and $1.9 million,
respectively.

The following table reflects the outstanding restricted stock awards as of
December 31, 2004, 2003 and 2002 and activity related thereto for the years then
ended:

Year Ended December 31,
-------------------------------------------------------------------
2004 2003 2002
--------------------- -------------------- --------------------
Weighted Weighted Weighted
Number Average Number Average Number Average
of Shares Price of Shares Price of Shares Price
--------- --------- --------- -------- --------- --------

Restricted stock awards:
Outstanding at beginning
of year...................... 676,973 $ 24.79 652,793 $ 24.72 - $ -
Evergreen awards assumed....... 214,186 $ 32.58 - $ - - $ -
Shares granted................. 630,937 $ 31.29 77,625 $ 25.39 654,445 $ 24.72
Shares forfeited............... (32,174) $ 30.99 (36,500) $ 24.72 - $ -
Lapse of restrictions.......... (41,935) $ 33.03 (16,945) $ 25.59 (1,652) $ 24.60
--------- --------- --------
Outstanding at end of year..... 1,447,987 $ 28.46 676,973 $ 24.79 652,793 $ 24.72
========= ========= ========

A summary of the Company's stock option plans as of December 31, 2004, 2003
and 2002, and changes during the years then ended, are presented below:

Year Ended December 31,
---------------------------------------------------------------------
2004 2003 2002
---------------------- --------------------- ---------------------
Weighted Weighted Weighted
Number Average Number Average Number Average
of Shares Price of Shares Price of Shares P rice
--------- --------- ---------- -------- ---------- --------

Non-statutory stock options:
Outstanding at beginning
of year........................ 5,274,116 $ 20.13 7,268,292 $ 19.60 6,926,071 $ 18.16
Evergreen options assumed..... 2,384,657 $ 11.18 - $ - - $ -
Options granted............... - $ - 1,353,988 $ 24.84 1,643,212 $ 21.14
Options forfeited............. (102,890) $ 22.24 (1,286,370) $ 29.22 (154,717) $ 26.27
Options exercised............. (2,375,299) $ 14.39 (2,061,794) $ 15.68 (1,146,274) $ 12.19
---------- ---------- ----------
Outstanding at end of year...... 5,180,584 $ 18.60 5,274,116 $ 20.13 7,268,292 $ 19.60
========== ========== ==========
Exercisable at end of year...... 3,970,996 $ 17.08 2,581,256 $ 17.56 4,269,659 $ 20.15
========== ========== ==========
Weighted average fair value
of options granted during
the year....................... $ - (a) $ 8.95 $ 8.87
========= ========= =========

- -----------
(a) The Company did not grant any stock options under the Long-Term Incentive
Plan during the year ended December 31, 2004. The assumed Evergreen options
were valued at $32.578 per share.

84

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2004, 2003 and 2002

The following table summarizes information about the Company's stock
options outstanding and options exercisable at December 31, 2004:

Options Outstanding Options Exercisable
-------------------------------------------------------- -----------------------------------
Number Weighted Average Weighted Number Weighted
Range of Outstanding at Remaining Average Exercisable at Average
Exercise Prices December 31, 2004 Contractual Life Exercise Price December 31, 2004 Exercise Price
- --------------- ----------------- ----------------- -------------- ----------------- --------------

$ 5-11 923,207 2.4 years $ 8.62 923,207 $ 8.62
$ 12-18 2,051,553 3.6 years $ 16.71 1,810,616 $ 16.50
$ 19-26 2,070,455 4.3 years $ 24.11 1,101,804 $ 23.42
$ 27-30 104,657 1.7 years $ 28.44 104,657 $ 28.44
$ 31-43 30,712 2.1 years $ 40.06 30,712 $ 40.06
---------- ----------
5,180,584 3,970,996
========== ==========

SFAS 123 disclosures. The Company applies APB 25 and related
interpretations in accounting for its stock option awards. Accordingly, no
compensation expense has been recognized for its stock option awards. If
compensation expense for the stock option awards had been determined consistent
with SFAS 123, the Company's net income and earnings per share would have been
less than the reported amounts. See Note B for a comparison of net income and
net income per share as reported and as adjusted for the pro forma effects of
determining compensation expense in accordance with SFAS 123.

Under SFAS 123, the fair value of each stock option grant is estimated on
the date of grant using the Black- Scholes option pricing model. The Company did
not grant any stock options during the year ended December 31, 2004.

The following weighted average assumptions were used to estimate the value
of options granted during the years ended December 31, 2003 and 2002:

Year Ended December 31,
--------------------------
2003 2002
----------- ------------

Risk-free interest rate............... 3.06% 2.80%
Expected life......................... 5 years 5 years
Expected volatility................... 36% 45%
Expected dividend yield............... - -

Employee Stock Purchase Plan

As discussed above in Note B, the Company has an ESPP that allows eligible
employees to annually purchase the Company's common stock at a discounted price.
Officers of the Company are not eligible to participate in the ESPP.
Contributions to the ESPP are limited to 15 percent of an employee's pay
(subject to certain ESPP limits) during the nine- month offering period.
Participants in the ESPP purchase the Company's common stock at a price that is
15 percent below the closing sales price of the Company's common stock on either
the first day or the last day of each offering period, whichever closing sales
price is lower.

Postretirement Benefit Obligations

As of December 31, 2004 and 2003, the Company had recorded $15.5 million
and $15.6 million, respectively, of unfunded accumulated postretirement benefit
obligations, the current and noncurrent portions of which are included in other
current liabilities and other liabilities and minority interests, respectively,
in the accompanying Consolidated Balance Sheets. These obligations are comprised
of five plans of which four relate to predecessor entities that the Company

85

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2004, 2003 and 2002

acquired in prior years. These plans had no assets as of December 31, 2004 or
2003. Other than the Company's retirement plan, the participants of these plans
are not current employees of the Company.

The accumulated postretirement benefit obligations pertaining to these
plans were determined by independent actuaries for four plans representing $11.4
million of unfunded accumulated postretirement benefit obligations as of
December 31, 2004 and by the Company for one plan representing $4.1 million of
unfunded accumulated postretirement benefit obligations as of December 31, 2004.
Interest costs at an annual rate of six percent of the periodic undiscounted
accumulated postretirement benefit obligations were employed in the valuations
of the benefit obligations. Certain of the aforementioned plans provide for
medical and dental cost subsidies for plan participants. Annual medical cost
escalation trends of 11 percent in 2005, declining to five percent in 2011 and
thereafter, and annual dental cost escalation trends of seven percent in 2005,
declining to five percent in 2009 and thereafter, were employed to estimate the
accumulated postretirement benefit obligations associated with the medical and
dental cost subsidies.

The following table reconciles changes in the Company's unfunded
accumulated postretirement benefit obligations during the years ended December
31, 2004, 2003 and 2002:

Year Ended December 31,
------------------------------------
2004 2003 2002
-------- -------- --------
(in thousands)

Beginning accumulated postretirement benefit obligations.... $ 15,556 $ 19,743 $ 19,750
Benefit payments.......................................... (1,497) (1,472) (1,702)
Service costs............................................. 258 205 205
Net actuarial gains....................................... (32) (4,410) -
Accretion of discounts.................................... 909 1,490 1,490
Fair value of Evergreen obligations assumed............... 340 - -
------- ------- -------
Ending accumulated postretirement benefit obligations....... $ 15,534 $ 15,556 $ 19,743
======= ======= =======

Estimated benefit payments and service costs associated with the plans for
the year ended December 31, 2005 are $1.5 million and $1.4 million,
respectively.

NOTE I. Issuance of Common Stock

During April 2002, the Company completed a public offering of 11.5 million
shares of its common stock at $21.50 per share. Associated therewith, the
Company received $236.0 million of net proceeds after the payment of issuance
costs. The Company used the net proceeds from the public offering to fund the
2002 acquisition of Falcon assets and associated acreage in the deepwater Gulf
of Mexico and the West Panhandle gas field acquisitions. See Note C for
information regarding these acquisitions.

NOTE J. Commitments and Contingencies

Severance agreements. The Company has entered into severance agreements
with its officers, subsidiary company officers and certain key employees.
Salaries and bonuses for the Company's officers are set by the Company's board
of directors for the parent company officers and by the Company's management
committee for subsidiary company officers and key employees. The Company's board
of directors and management committee can grant increases or reductions to base
salary at their discretion. The current annual salaries for the parent company
officers, the subsidiary company officers and key employees covered under such
agreements total $23.6 million.

86

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2004, 2003 and 2002

Indemnifications. The Company has indemnified its directors and certain of
its officers, employees and agents with respect to claims and damages arising
from acts or omissions taken in such capacity, as well as with respect to
certain litigation.

Legal actions. The Company is party to various legal actions incidental to
its business, including, but not limited to, the proceedings described below.
The majority of these lawsuits primarily involve claims for damages arising from
oil and gas leases and ownership interest disputes. The Company believes that
the ultimate disposition of these legal actions will not have a material adverse
effect on the Company's consolidated financial position, liquidity, capital
resources or future results of operations. The Company will continue to evaluate
its litigation matters on a quarter-by- quarter basis and will adjust its
litigation reserves as appropriate to reflect the then current status of
litigation.

Alford. The Company is party to a 1993 class action lawsuit filed in the
26th Judicial District Court of Stevens County, Kansas by two classes of royalty
owners, one for each of the Company's gathering systems connected to the
Company's Satanta gas plant. The case was relatively inactive for several years.
In early 2000, the plaintiffs amended their pleadings and the case now contains
two material claims. First, the plaintiffs assert that they were improperly
charged expenses (primarily field compression), which are a "cost of
production", and for which the plaintiffs, as royalty owners, are not
responsible. Second, the plaintiffs claim they are entitled to 100 percent of
the value of the helium extracted at the Company's Satanta gas plant. If the
plaintiffs were to prevail on the above two claims in their entirety, it is
possible that the Company's liability (both for periods covered by the lawsuit
and from the last date covered by the lawsuit to the present - because the
deductions continue to be taken and the plaintiffs continue to be paid for a
royalty share of the helium) could reach approximately $30 million related to
the cost of production claim and approximately $40 million related to the helium
claim, plus prejudgment interest. However, the Company believes it has valid
defenses to the plaintiffs' claims, has paid the plaintiffs properly under their
respective oil and gas leases and other agreements, and intends to vigorously
defend itself.

The Company does not believe the costs it has deducted are a "cost of
production". The costs being deducted are post production costs incurred to
transport the gas to the Company's Satanta gas plant for processing, where the
valuable hydrocarbon liquids and helium are extracted from the gas. The
plaintiffs benefit from such extractions and the Company believes that charging
the plaintiffs with their proportionate share of such transportation and
processing expenses is consistent with Kansas law and with the parties'
agreements.

The Company has also vigorously defended against plaintiffs' claims to 100
percent of the value of the helium extracted, and believes that in accordance
with applicable law, it has properly accounted to the plaintiffs for their
fractional royalty share of the helium under the specified royalty clauses of
the respective oil and gas leases. The Company has not established a provision
for the helium claim.

The factual evidence in the case was presented to the 26th Judicial
District Court without a jury in December 2001. Oral arguments were heard by the
court in April 2002, and although the court has not yet entered a judgment or
findings, it could do so at any time. The Company strongly denies the existence
of any material underpayment to the plaintiffs and believes it presented strong
evidence at trial to support its positions. However, either through a negotiated
settlement or court ruling, the Company could have to pay some part of the cost
of production claim and, accordingly, the Company has established a partial
reserve for this claim. Although the amount of any resulting liability, to the
extent that it exceeds the Company's provision, could have a material adverse
effect on the Company's results of operations for the quarterly reporting period
in which such liability is recorded, the Company does not expect that any such
additional liability will have a material adverse effect on its consolidated
financial position as a whole or on its liquidity, capital resources or future
annual results of operations.

87

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2004, 2003 and 2002

Kansas ad valorem tax. The Natural Gas Policy Act of 1978 ("NGPA") allows a
"severance, production or similar" tax to be included as an add-on, over and
above the maximum lawful price for gas. Based on a Federal Energy Regulatory
Commission ("FERC") ruling that Kansas ad valorem tax was such a tax, one of the
Company's predecessor entities collected the Kansas ad valorem tax in addition
to the otherwise maximum lawful price. The FERC's ruling was appealed to the
United States Court of Appeals for the District of Columbia ("D.C. Circuit"),
which held in June 1988 that the FERC failed to provide a reasonable basis for
its findings and remanded the case to the FERC for further consideration.

On December 1, 1993, the FERC issued an order reversing its prior ruling,
but limited the effect of its decision to Kansas ad valorem taxes for sales made
on or after June 28, 1988. The FERC clarified the effective date of its decision
by an order dated May 18, 1994. The order clarified that the effective date
applies to tax bills rendered after June 28, 1988, not sales made on or after
that date. Numerous parties filed appeals on the FERC's action in the D.C.
Circuit. Various gas producers challenged the FERC's orders on two grounds: (1)
that the Kansas ad valorem tax, properly understood, does qualify for
reimbursement under the NGPA; and (2) the FERC's ruling should, in any event,
have been applied prospectively. Other parties challenged the FERC's orders on
the grounds that the FERC's ruling should have been applied retroactively to
December 1, 1978, the date of the enactment of the NGPA and producers should
have been required to pay refunds accordingly.

The D.C. Circuit issued its decision on August 2, 1996, which holds that
producers must make refunds of all Kansas ad valorem tax collected with respect
to production since October 4, 1983, as opposed to June 28, 1988. Petitions for
rehearing were denied on November 6, 1996. Various gas producers subsequently
filed a petition for writ of certiori with the United States Supreme Court
seeking to limit the scope of the potential refunds to tax bills rendered on or
after June 28, 1988 (the effective date originally selected by the FERC).
Williams Natural Gas Company filed a cross-petition for certiori seeking to
impose refund liability back to December 1, 1978. Both petitions were denied on
May 12, 1997.

The Company and other producers filed petitions for adjustment with the
FERC on June 24, 1997. The Company was seeking a waiver or set-off from the FERC
with respect to that portion of the refund associated with (i) nonrecoupable
royalties, (ii) nonrecoupable Kansas property taxes based, in part, upon the
higher prices collected and (iii) interest for all periods. On September 10,
1997, FERC denied this request, and on October 10, 1997, the Company and other
producers filed a request for rehearing. Pipelines were given until November 10,
1997 to file claims on refunds sought from producers and refund claims totaling
approximately $30.2 million were made against the Company. As of December 31,
2004, the Company has settled all of the original claim amounts and believes it
has no further obligation related to this case.

Lease agreements. The Company leases offshore production facilities,
equipment and office facilities under noncancellable operating leases. Rental
expenses associated with these operating leases for the years ended December 31,
2004, 2003 and 2002 were approximately $51.8 million, $15.5 million and $6.7
million, respectively. Future minimum lease commitments under noncancellable
operating leases at December 31, 2004 are as follows (in thousands):

2005................................................ $ 56,365
2006................................................ $ 48,821
2007................................................ $ 34,294
2008................................................ $ 20,199
2009................................................ $ 12,448
Thereafter.......................................... $ 13,214

88

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2004, 2003 and 2002

Drilling commitments. The Company periodically enters into contractual
arrangements under which the Company is committed to expend funds to drill wells
in the future. The Company also enters into agreements to secure drilling rig
services which require the Company to make future minimum payments to the rig
operators. The Company records drilling commitments in the periods in which well
capital is expended or rig services are provided.

Transportation agreements. Associated with the Evergreen merger, the
Company assumed gas transportation commitments for specified volumes of gas per
year through 2014. The transportation commitments are for approximately 132
million cubic feet ("MMcf") of gross gas sales volumes per day during 2005,
declining to approximately 40 MMcf of gross gas sales volumes per day during
2014.

One of the Company's Canadian subsidiaries is a party to pipeline
transportation service agreements, with remaining terms of approximately 11
years, whereby it has committed to transport a specified volume of gas each year
from Canada to a point in Chicago. Such gas volumes are comprised of a
significant portion of the Company's Canadian net gas production, augmented with
certain volumes purchased at market prices in Canada. The committed volumes to
be transported under the pipeline transportation service agreements are
approximately 78 MMcf of gas per day during 2005 and decline to approximately 75
MMcf of gas per day by the end of the commitment term. The net gas marketing
gains or losses resulting from purchasing third party gas in Canada and selling
it in Chicago are recorded as other income or other expense in the accompanying
Consolidated Statements of Operations. Associated with these agreements, the
Company recognized $1.2 million, $.9 million and $2.6 million of gas marketing
losses in other expense during the years ended December 31, 2004, 2003 and 2002,
respectively.

Future minimum transportation fees under the Company's gas transportation
commitments at December 31, 2004 are as follows (in thousands):

2005................................................ $ 58,622
2006................................................ $ 59,705
2007................................................ $ 59,992
2008................................................ $ 59,687
2009................................................ $ 59,242
Thereafter.......................................... $ 287,021

NOTE K. Derivative Financial Instruments

Fair value hedges. The Company monitors the debt capital markets and
interest rate trends to identify opportunities to enter into and terminate
interest rate swap contracts with the objective of minimizing its cost of
capital. During the three-year period ending December 31, 2004, the Company,
from time to time, entered into interest rate swap contracts to hedge a portion
of the fair value of its senior notes. The terms of the interest rate swap
contracts were for notional amounts that matched the scheduled maturity of the
hedged senior notes, required the counterparties to pay the Company a fixed
annual interest rate equal to the stated bond coupon rates on the notional
amounts and required the Company to pay the counterparties variable annual
interest rates on the notional amounts equal to the periodic six-month LIBOR
plus a weighted average annual margin. During the year ended December 31, 2004,
the Company paid $9.4 million, net of $2.2 million of associated settlements
receivable, to terminate fair value hedge interest rate swaps prior to their
stated maturities. Associated therewith, the Company recognized $11.6 million of
"Payments of other liabilities" in the accompanying Consolidated Statement of
Cash Flows for the year ended December 31, 2004. During the years ended December
31, 2003 and 2002, the Company terminated fair value hedge interest rate swap
contracts for cash proceeds, including accrued interest, of $21.5 million and
$36.3 million, respectively. The proceeds attributable to the fair value of the
remaining terms of the terminated contracts amounted to $18.3 million and $32.0
million and are included in "Proceeds from disposition of assets" in the
accompanying Consolidated Statements of Cash Flows during the years ended

89

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2004, 2003 and 2002

December 31, 2003 and 2002, respectively. During the years ended December 31,
2004, 2003 and 2002, settlements of open fair value hedges reduced the Company's
interest expense by $2.2 million, $29.3 million and $25.3 million, respectively.
As of December 31, 2004, the Company was not a party to any open fair value
hedges.

As of December 31, 2004, the carrying value of the Company's long-term debt
in the accompanying Consolidated Balance Sheets included a $3.5 million
reduction in the carrying value attributable to net deferred hedge losses on
terminated fair value hedges that are being amortized as net increases to
interest expense over the original terms of the terminated agreements. The
amortization of net deferred hedge gains on terminated interest rate swaps
reduced the Company's reported interest expense by $19.2 million, $26.1 million
and $14.1 million during the years ended December 31, 2004, 2003 and 2002,
respectively.

The terms of the fair value hedge agreements described above perfectly
matched the terms of the hedged senior notes. Accordingly, the Company did not
realize any hedge ineffectiveness associated with its fair value hedges during
the years ended December 31, 2004, 2003 or 2002.

The following table sets forth, as of December 31, 2004, the scheduled
amortization of net deferred hedge gains (losses) on terminated interest rate
hedges, including $3.4 million of deferred losses on terminated cash flow
interest rate hedges, that will be recognized as increases in the case of
losses, or decreases in the case of gains, to the Company's future interest
expense:

First Second Third Fourth
Quarter Quarter Quarter Quarter Total
------- ------- ------- ------- --------
(in thousands)

2005 net deferred hedge gains.......... $ 2,213 $ 1,300 $ 880 $ 569 $ 4,962
2006 net deferred hedge gains (losses). $ 440 $ 191 $ 79 $ (86) 624
2007 net deferred hedge losses......... $ (227) $ (427) $ (708) $ (860) (2,222)
2008 net deferred hedge losses......... $ (461) $ (470) $ (478) $ (528) (1,937)
2009 net deferred hedge losses......... $ (523) $ (596) $ (605) $ (627) (2,351)
2010 net deferred hedge losses......... $ (619) $ (203) $ (208) $ (211) (1,241)
Thereafter............................. (4,672)
-------
$ (6,837)
=======

Cash flow hedges. The Company utilizes commodity swap and collar contracts
to (i) reduce the effect of price volatility on the commodities the Company
produces and sells, (ii) support the Company's annual capital budgeting and
expenditure plans and (iii) reduce commodity price risk associated with certain
capital projects. The Company has also, from time to time, utilized interest
rate contracts to reduce the effect of interest rate volatility on the Company's
indebtedness and forward currency exchange agreements to reduce the effect of
U.S. dollar to Canadian dollar exchange rate volatility.

90

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2004, 2003 and 2002

Oil prices. All material physical sales contracts governing the Company's
oil production have been tied directly or indirectly to the New York Mercantile
Exchange ("NYMEX") prices. The following table sets forth the volumes hedged in
barrels ("Bbl") underlying the Company's outstanding oil hedge contracts and the
weighted average NYMEX prices per Bbl for those contracts as of December 31,
2004:

Yearly
First Second Third Fourth Outstanding
Quarter Quarter Quarter Quarter Average
------------- ------------- ------------- ------------- --------------

Average daily oil production hedged (a):
2005 - Swap Contracts
Volume (Bbl)..................... 27,000 27,000 27,000 27,000 27,000
Price per Bbl.................... $ 27.97 $ 27.97 $ 27.97 $ 27.97 $ 27.97

2006 - Swap Contracts
Volume (Bbl)..................... 14,500 14,500 14,500 14,500 14,500
Price per Bbl.................... $ 34.12 $ 34.12 $ 34.12 $ 34.12 $ 34.12

2006 - Collar Contracts
Volume (Bbl)..................... 3,500 3,500 3,500 3,500 3,500
Price per Bbl.................... $35.00-$41.95 $35.00-$41.95 $35.00-$41.95 $35.00-$41.95 $ 35.00-$41.95

2007 - Swap Contracts
Volume (Bbl)..................... 17,000 17,000 17,000 17,000 17,000
Price per Bbl.................... $ 32.59 $ 32.59 $ 32.59 $ 32.59 $ 32.59

2008 - Swap Contracts
Volume (Bbl)..................... 21,000 21,000 21,000 21,000 21,000
Price per Bbl.................... $ 30.72 $ 30.72 $ 30.72 $ 30.72 $ 30.72

2009 - Swap Contracts
Volume (Bbl)..................... 3,500 3,500 3,500 3,500 3,500
Price per Bbl.................... $ 36.48 $ 36.48 $ 36.48 $ 36.48 $ 36.48

2010 - Swap Contracts
Volume (Bbl)..................... 1,000 1,000 1,000 1,000 1,000
Price per Bbl.................... $ 36.10 $ 36.10 $ 36.10 $ 36.10 $ 36.10

2011 - Swap Contracts
Volume (Bbl)..................... 2,000 2,000 2,000 2,000 2,000
Price per Bbl.................... $ 35.93 $ 35.93 $ 35.93 $ 35.93 $ 35.93

2012 - Swap Contracts
Volume (Bbl)..................... 2,000 2,000 2,000 2,000 2,000
Price per Bbl.................... $ 35.86 $ 35.86 $ 35.86 $ 35.86 $ 35.86

- ---------------
(a) Subsequent to December 31, 2004, the Company conveyed to the purchaser of
the Spraberry Volumetric Production Payment ("VPP") the following oil swap
contracts which were included in the schedule above: (i) 4,500 Bbls per day
of 2006 oil sales at a weighted average fixed price per Bbl of $39.53, (ii)
4,000 Bbls per day of 2007 oil sales at a weighted average fixed price per
Bbl of $38.14, (iii) 4,000 Bbls per day of 2008 oil sales at a weighted
average fixed price per Bbl of $37.15, (iv) 3,500 Bbls per day of 2009 oil
sales at a weighted average fixed price per Bbl of $36.48, (v) 1,000 Bbls
per day of 2010 oil sales at a weighted average fixed price per Bbl of
$36.10, (vi) 2,000 Bbls per day of 2011 oil sales at a weighted average
fixed price per Bbl of $35.93 and (vii) 2,000 Bbls per day of 2012 oil
sales at a weighted average fixed price per Bbl of $35.86. See Note U for
additional information regarding the Spraberry VPP.

91

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2004, 2003 and 2002

The Company reports average oil prices per Bbl including the effects of oil
quality adjustments and the net effect of oil hedges. The following table sets
forth the Company's oil prices, both reported (including hedge results) and
realized (excluding hedge results), and the net effect of settlements of oil
price hedges on oil revenue for the years ended December 31, 2004, 2003 and
2002:

Year Ended December 31,
-----------------------------
2004 2003 2002
------- ------- -------

Average price reported per Bbl.................. $ 31.38 $ 25.59 $ 22.89
Average price realized per Bbl.................. $ 37.61 $ 28.80 $ 22.95
Reduction to oil revenue (in millions).......... $(107.2) $ (41.3) $ (.8)

Natural gas liquids prices. During the years ended December 31, 2004, 2003
and 2002, the Company did not enter into any NGL hedge contracts. There were no
outstanding NGL hedge contracts at December 31, 2004.

Gas prices. The Company employs a policy of hedging a portion of its gas
production based on the index price upon which the gas is actually sold in order
to mitigate the basis risk between NYMEX prices and actual index prices, or
based on NYMEX prices if NYMEX prices are highly correlated with the index
price. The following table sets forth the volumes hedged in million British
thermal units ("MMBtu") underlying the Company's outstanding gas hedge contracts
and the weighted average index prices per MMBtu for those contracts as of
December 31, 2004:

Yearly
First Second Third Fourth Outstanding
Quarter Quarter Quarter Quarter Average
----------- ----------- ----------- ---------- ------------

Average daily gas production hedged (a):
2005 - Swap Contracts
Volume (MMBtu)........................ 296,556 290,000 290,000 260,000 284,055
Index price per MMBtu................. $ 5.32 $ 5.19 $ 5.19 $ 5.18 $ 5.22

2006 - Swap Contracts
Volume (MMBtu)........................ 105,000 104,176 102,500 102,500 103,534
Index price per MMBtu................. $ 4.70 $ 4.69 $ 4.67 $ 4.67 $ 4.68

2006 - Collar Contracts
Volume (MMBtu)........................ 5,000 5,000 5,000 5,000 5,000
Index price per MMBtu................. $5.25-$7.15 $5.25-$7.15 $5.25-$7.15 $5.25-$7.15 $5.25-$7.15

2007 - Swap Contracts
Volume (MMBtu)........................ 55,000 55,000 55,000 55,000 55,000
Index price per MMBtu................. $ 4.69 $ 4.69 $ 4.69 $ 4.69 $ 4.69

2008 - Swap Contracts
Volume (MMBtu)........................ 30,000 30,000 30,000 30,000 30,000
Index price per MMBtu................. $ 5.06 $ 5.06 $ 5.06 $ 5.06 $ 5.06

2009 - Swap Contracts
Volume (MMBtu)........................ 25,000 25,000 25,000 25,000 25,000
Index price per MMBtu................. $ 4.72 $ 4.72 $ 4.72 $ 4.72 $ 4.72

- --------------
(a) Subsequent to December 31, 2004, the Company conveyed to the purchaser of
the Hugoton VPP the following gas swap contracts which were included in the
schedule above: (i) 9,151 MMBtu per day 2005 gas sales at a weighted
average fixed price per MMBtu of $6.17, (ii) 33,534 MMBtu per day 2006 gas
sales at a weighted average fixed price per MMBtu of $5.78, (iii) 30,000
MMBtu per day 2007 gas sales at a weighted average fixed price per MMBtu of
$5.32, (iv) 25,000 MMBtu per day 2008 gas sales at a weighted average fixed
price per MMBtu of $5.00 and (v) 25,000 MMBtu per day of 2009 gas sales at
a weighted average fixed price per MMBtu of $4.72. See Note U for
additional information regarding the Hugoton VPP.

92

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2004, 2003 and 2002

The Company reports average gas prices per thousand cubic feet ("Mcf")
including the effects of British thermal unit ("Btu") content, gas processing,
shrinkage adjustments and the net effect of gas hedges. The following table sets
forth the Company's gas prices, both reported (including hedge results) and
realized (excluding hedge results), and the net effect of settlements of gas
price hedges on gas revenue for the years ended December 31, 2004, 2003 and
2002:

Year Ended December 31,
-------------------------------
2004 2003 2002
------- ------- -------

Average price reported per Mcf.......................... $ 4.33 $ 3.84 $ 2.58
Average price realized per Mcf.......................... $ 4.83 $ 4.25 $ 2.52
Addition (reduction) to gas revenue (in millions)....... $(125.7) $ (76.1) $ 13.6

Interest rate. During June 2004, the Company entered into costless collar
contracts and designated the contracts as cash flow hedges of the forecasted
interest rate risk attributable to the yield on the benchmark 4.75 percent U.S.
Treasury Notes due May 15, 2014 (the "U.S. Treasuries"). The terms of the collar
contracts fixed the annual yield on $250 million notional amount of U.S.
Treasuries within a yield collar having a ceiling rate of 4.70 percent and a
floor rate of 4.65 percent. The yield on the U.S. Treasuries as of July 7, 2004
was the benchmark rate used to determine the coupon rate on the Company's New
Notes, which were issued on July 15, 2004 in exchange for portions of the Old
Notes. During July 2004, the Company terminated these costless collar contracts
for $3.4 million of cash payments. The Company did not realize any
ineffectiveness in connection with the costless collar contracts during the year
ended December 31, 2004. See Note F for information regarding the July 15, 2004
debt exchange.

Hedge ineffectiveness. During the years ended December 31, 2004, 2003 and
2002, the Company recognized other expense of $4.3 million, $2.8 million and
$1.7 million, respectively, related to the ineffective portions of its cash flow
hedging instruments. These charges include amounts related to hedge volumes that
exceeded revised forecasts of production volumes due to delays in the start-up
of production in certain fields.

Accumulated other comprehensive income (loss) - net deferred hedge losses,
net of tax ("AOCI - Hedging"). As of December 31, 2004 and 2003, AOCI - Hedging
represented net deferred losses of $241.4 and $104.1 million, respectively. The
AOCI - Hedging balance as of December 31, 2004 was comprised of $363.1 million
of net deferred losses on the effective portions of open cash flow hedges, $3.0
million of net deferred losses on terminated cash flow hedges (including $3.4
million of net deferred losses on terminated cash flow interest rate hedges) and
$124.7 million of associated net deferred tax benefits. The AOCI - Hedging
balance as of December 31, 2003 was comprised of $200.6 million of net deferred
losses on the effective portions of open cash flow hedges, $45.1 million of net
deferred gains on terminated cash flow hedges and $51.4 million of associated
net deferred tax benefits. The increase in AOCI - Hedging during the year ended
December 31, 2004 was primarily attributable to increases in future commodity
prices relative to the commodity prices stipulated in the hedge contracts,
partially offset by the reclassification of net deferred hedge losses to net
income as derivatives matured by their terms. The net deferred losses associated
with open cash flow hedges remain subject to market price fluctuations until the
positions are either settled under the terms of the hedge contracts or
terminated prior to settlement. The net deferred gains (losses) on terminated
cash flow hedges are fixed.

During the twelve-month period ending December 31, 2005, based on current
estimates of future commodity prices, the Company expects to reclassify $224.1
million of net deferred losses associated with open commodity hedges and $1.7
million of net deferred gains on terminated commodity hedges from AOCI - Hedging
to oil and gas revenues. The Company also expects to reclassify approximately
$81.2 million of net deferred income tax benefits associated with commodity
hedges during the twelve-month period ending December 31, 2005 from AOCI -
Hedging to income tax benefit.

93

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2004, 2003 and 2002

The following table sets forth, as of December 31, 2004, the scheduled
amortization of net deferred gains (losses) on terminated commodity hedges that
will be recognized as increases in the case of gains, or decreases in the case
of losses, to the Company's future oil and gas revenues:

First Second Third Fourth
Quarter Quarter Quarter Quarter Total
------- ------- ------- ------- --------
(in thousands)

2005 net deferred hedge gains..... $ 424 $ 427 $ 432 $ 434 $ 1,717
2006 net deferred hedge losses.... $ (330) $ (332) $ (333) $ (330) (1,325)
-------
$ 392
=======

NOTE L. Major Customers and Derivative Counterparties

Sales to major customers. The Company's share of oil and gas production is
sold to various purchasers who must be prequalified under the Company's credit
risk policies and procedures. The Company records allowances for doubtful
accounts based on the agings of accounts receivable and the general economic
condition of its customers. The Company is of the opinion that the loss of any
one purchaser would not have an adverse effect on the ability of the Company to
sell its oil and gas production.

The following customer individually accounted for 10 percent or more of the
consolidated oil, NGL and gas revenues of the Company during one or more of the
years ended December 31, 2004, 2003 and 2002:

Year ended December 31,
----------------------------------
2004 2003 2002
-------- -------- --------

Williams Power Company, Inc................... 12% 16% 7%

At December 31, 2004, the Company had no amounts receivable from Williams
Power Company, Inc.

Derivative counterparties. The Company uses credit and other financial
criteria to evaluate the credit standing of, and to select, counterparties to
its derivative instruments. Although the Company does not obtain collateral or
otherwise secure the fair value of its derivative instruments, associated credit
risk is mitigated by the Company's credit risk policies and procedures. As of
December 31, 2004 and 2003, the Company had $5.3 million of derivative assets
for which Enron North America Corp was the Company's counterparty. Associated
therewith, the Company had a $4.5 million allowance for doubtful accounts as of
December 31, 2004 and 2003.

NOTE M. Asset Retirement Obligations

As referred to in Note B, the Company adopted the provisions of SFAS 143 on
January 1, 2003. The Company's asset retirement obligations primarily relate to
the future plugging and abandonment of proved properties and related facilities.
The Company does not provide for a market risk premium associated with asset
retirement obligations because a reliable estimate cannot be determined. The
Company has no assets that are legally restricted for purposes of settling asset

94

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2004, 2003 and 2002

retirement obligations. The following table summarizes the Company's asset
retirement obligation transactions recorded in accordance with the provisions of
SFAS 143 during the years ended December 31, 2004 and 2003 and in accordance
with the provisions of SFAS 19 during the year ended December 31, 2002:

Year Ended December 31,
-----------------------------------
2004 2003 2002
-------- ----------- --------
(in thousands)

Beginning asset retirement obligations........... $105,036 $ 34,692 $ 39,461
Cumulative effect adjustment.................. - 23,393 -
New wells placed on production and
changes in estimates....................... 4,591 46,664 293
Acquisition liabilities assumed............... 10,488 1,791 -
Liabilities settled........................... (8,562) (8,069) (6,832)
Accretion of discount......................... 8,210 5,040 2,562
Currency translation.......................... 1,116 1,525 (792)
------- ------- --------
Ending asset retirement obligations ............. $120,879 $105,036 $ 34,692
======= ======= =======

The Company records the current and noncurrent portions of asset retirement
obligations in other current liabilities and other liabilities and minority
interests, respectively, in the accompanying Consolidated Balance Sheets.

NOTE N. Interest and Other Income

The following table provides the components of the Company's interest and
other income during the years ended December 31, 2004, 2003 and 2002:

Year Ended December 31,
--------------------------------
2004 2003 2002
-------- -------- --------
(in thousands)

Kansas ad valorem escrow adjustments (see Note J)........ $ - $ - $ 3,500
Business interruption insurance claim.................... 7,563 - -
Retirement obligation revaluations (see Note H).......... 32 4,410 -
Excise tax income........................................ 3,609 2,369 2,398
Interest income.......................................... 92 981 642
Seismic data sales....................................... 172 424 87
Foreign currency remeasurement and exchange gains (a).... 304 657 142
Gain on early extinguishment of debt (see Note F)........ 95 - -
Other income............................................. 2,207 3,451 4,453
------- ------- -------
Total interest and other income..................... $ 14,074 $ 12,292 $ 11,222
======= ======= =======

- ----------
(a) The Company's operations in Argentina, Canada and Africa periodically
recognize monetary assets and liabilities in currencies other than their
functional currencies (see Note B for information regarding the functional
currencies of subsidiary entities). Associated therewith, the Company
realizes foreign currency remeasurement and transaction gains and losses.

95

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2004, 2003 and 2002

NOTE O. Asset Divestitures

During the years ended December 31, 2004, 2003 and 2002, the Company
completed asset divestitures for net proceeds of $1.7 million, $35.7 million and
$118.9 million, respectively. Associated therewith, the Company recorded gains
on disposition of assets of $39 thousand, $1.3 million and $4.4 million during
the years ended December 31, 2004, 2003 and 2002, respectively.

Hedge derivative divestitures. During the years ended December 31, 2003 and
2002, the Company terminated, prior to their scheduled maturity, hedge
derivatives for cash sales proceeds of $18.3 million and $91.3 million,
respectively. Net gains from these divestitures were deferred and are amortized
over the original contract lives of the terminated derivatives as reductions to
interest expense or increases to oil and gas revenues. See Note K for more
information regarding deferred gains and losses on terminated hedge derivatives.

Other United States divestitures. During the year ended December 31, 2004,
the Company received $1.2 million of cash proceeds from the sale of other U.S.
corporate assets. Associated with these divestitures, the Company recorded $.2
million of net gains. During the year ended December 31, 2003, the Company
received $15.2 million of cash proceeds from the sale of unproved property
interests and $.9 million of cash proceeds from the sale of other U.S. corporate
assets. Associated with these divestitures, the Company recorded $1.5 million of
net gains. During the year ended December 31, 2002, the Company received $20.9
million of proceeds from the cash settlement of a gas balancing receivable, $4.7
million from the sale of certain gas properties located in Oklahoma and $1.8
million from the sale of other corporate assets. Associated with these
divestitures, the Company recorded net gains of $4.2 million.

NOTE P. Other Expense

The following table provides the components of the Company's other expense
during the years ended December 31, 2004, 2003 and 2002:

Year Ended December 31,
--------------------------------
2004 2003 2002
-------- -------- --------
(in thousands)

Derivative ineffectiveness and mark-to-market
provisions (see Note K)............................... $ 4,341 $ 2,831 $ 1,664
Contingency adjustments (see Note J)..................... 13,552 1,776 -
Debt exchange offer costs (see Note F)................... 2,248 - -
Gas marketing losses (see Note J)........................ 1,218 922 2,556
Foreign currency remeasurement and exchange losses (a)... 2,949 2,672 7,623
Bad debt expense......................................... 3,674 354 129
Loss on early extinguishment of debt (see Note F)........ - 1,457 22,346
Argentine personal asset tax............................. 1,094 1,996 -
Other charges............................................ 4,611 9,312 5,284
------- ------- -------
Total other expense................................. $ 33,687 $ 21,320 $ 39,602
======= ======= =======

- ----------
(a) The Company's operations in Argentina, Canada and Africa periodically
recognize monetary assets and liabilities in currencies other than their
functional currencies (see Note B for information regarding the functional
currencies of subsidiary entities). Associated therewith, the Company
realizes foreign currency remeasurement and transaction gains and losses.

96

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2004, 2003 and 2002

NOTE Q. Income Taxes

The Company accounts for income taxes in accordance with the provisions of
Statement of Financial Accounting Standards No. 109, "Accounting for Income
Taxes" ("SFAS 109"). The Company and its eligible subsidiaries file a
consolidated United States federal income tax return. Certain subsidiaries are
not eligible to be included in the consolidated United States federal income tax
return and separate provisions for income taxes have been determined for these
entities or groups of entities. The tax returns and the amount of taxable income
or loss are subject to examination by United States federal, state, local and
foreign taxing authorities. Current and estimated tax payments of $17.1 million,
$5.3 million and $2.3 million were made during the years ended December 31,
2004, 2003 and 2002, respectively.

SFAS 109 requires that the Company continually assess both positive and
negative evidence to determine whether it is more likely than not that deferred
tax assets can be realized prior to their expiration. From 1998 until 2003, the
Company maintained valuation allowances against a portion of its deferred tax
asset position in the United States. During 2003, the Company concluded, based
on its improved operating results, that it was more likely than not that it
would be able to realize its gross deferred tax asset position in the United
States. Accordingly, the Company reversed its valuation allowances in the United
States.

Pioneer will continue to monitor Company-specific, oil and gas industry and
worldwide economic factors and will reassess the likelihood that the Company's
net operating loss carryforwards and other deferred tax attributes in the United
States and foreign tax jurisdictions will be utilized prior to their expiration.
As of December 31, 2004, the Company's valuation allowances related to foreign
tax jurisdictions were $108.2 million.

On October 22, 2004, the American Jobs Creation Act (the "AJCA") was signed
into law. The AJCA includes a deduction of 85 percent of certain foreign
earnings that are repatriated, as defined in the AJCA. The Company may elect to
apply this provision to qualifying earnings repatriations in 2005. The Company
has started an evaluation of the effects of the repatriation provision; however,
the Company does not expect to be able to complete this evaluation until after
Congress or the Treasury Department provide additional clarifying language on
key elements of the provision. The Company expects to complete its evaluation of
the effects of the repatriation provision within a reasonable period of time
following the publication of the additional clarifying language. The range of
possible amounts that the Company is considering for repatriation under section
965 of the Internal Revenue Code is between zero and $80 million with a related
potential range of income tax between zero and $5 million. Until the Company
decides to repatriate any foreign earnings, it will continue to treat them as
permanently invested.

During the year ended December 31, 2004, the Company recorded a $26.9
million tax benefit associated with the deduction of the Company's only
investment in Gabon resulting from the impairment of the Olowi field. See Note T
for additional discussion regarding the impairment of the Gabonese Olowi field.

97

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2004, 2003 and 2002

The Company's income tax provision (benefit) and amounts separately
allocated were attributable to the following items for the years ended December
31, 2004, 2003 and 2002:

Year Ended December 31,
-------------------------------------
2004 2003 2002
--------- --------- ---------
(in thousands)

Income before cumulative effect of change in
accounting principle...................................... $ 166,359 $ (64,403) $ 5,063
Cumulative effect of change in accounting principle......... - 1,312 -
Changes in goodwill - tax benefits related to stock
based compensation........................................ (8,955) - -
Changes in stockholders' equity:
Net deferred hedge losses................................. (73,340) (51,064) (2,561)
Tax benefits related to stock-based compensation.......... (6,612) (14,666) -
Translation adjustment.................................... (314) (324) (20)
-------- -------- --------
$ 77,138 $(129,145) $ 2,482
======== ======== ========

Income tax provision (benefit) attributable to income before cumulative
effect of change in accounting principle consisted of the following for the
years ended December 31, 2004, 2003 and 2002:

Year Ended December 31,
-------------------------------------
2004 2003 2002
--------- --------- ---------
(in thousands)

Current:
U.S. federal................................................ $ 2,500 $ 100 $ -
U.S. state and local........................................ 602 - 209
Foreign..................................................... 22,185 11,085 2,066
-------- -------- --------
25,287 11,185 2,275
-------- -------- --------
Deferred:
U.S. federal................................................ 138,723 (69,020) -
U.S. state and local........................................ 5,093 (7,291) -
Foreign..................................................... (2,744) 723 2,788
-------- -------- --------
141,072 (75,588) 2,788
-------- -------- --------
$ 166,359 $ (64,403) $ 5,063
======== ======== ========

Income before income taxes and cumulative effect of change in accounting
principle consists of the following for the years ended December 31, 2004, 2003
and 2002:

Year Ended December 31,
-------------------------------------
2004 2003 2002
--------- --------- ---------
(in thousands)

Income before income taxes and cumulative effect of
change in accounting principle:
U.S. federal................................................ $ 477,195 $ 335,170 $ 36,475
Foreign..................................................... 2,018 (4,394) (4,699)
-------- -------- --------
$ 479,213 $ 330,776 $ 31,776
======== ======== ========

98

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2004, 2003 and 2002

Reconciliations of the United States federal statutory tax rate to the
Company's effective tax rate for income before cumulative effect of change in
accounting principle are as follows for the years ended December 31, 2004, 2003
and 2003:

Year Ended December 31,
------------------------------
2004 2003 2002
------- ------- --------
(in percentages)

U.S. federal statutory tax rate..................... 35.0 35.0 35.0
U.S. valuation allowance reversal................... - (59.8) (44.1)
Foreign valuation allowances (a).................... 5.1 13.1 28.2
Rate differential on foreign operations............. 4.4 (.9) (.5)
Argentine inflation adjustment (a).................. (2.0) (12.4) -
Gabon investment deduction.......................... (5.4) - -
Other............................................... (2.4) 5.5 (2.7)
------- ------- -------
Consolidated effective tax rate.................. 34.7 (19.5) 15.9
======= ======= =======

- -----------
(a) The Company has applied an inflation adjustment to its 2004, 2003 and 2002
Argentine income tax returns based on developing case law. The Company
believes that it is more likely than not that the adjustment will be denied
by the Argentine taxing authorities and has provided a $49.3 million
valuation allowance against this tax benefit in its overall foreign
valuation allowances.

The tax effects of temporary differences that give rise to significant
portions of the deferred tax assets and deferred tax liabilities are as follows
as of December 31, 2004 and 2003:

December 31,
-------------------------
2004 2003
---------- ----------
(in thousands)

Deferred tax assets:
Net operating loss carryforwards....................... $ 303,002 $ 300,296
Alternative minimum tax credit carryforwards........... 4,144 1,457
Net deferred hedge losses.............................. 124,689 56,842
Asset retirement obligations........................... 41,874 29,040
Other.................................................. 110,677 92,561
--------- ---------
Total deferred tax assets............................ 584,386 480,196
Valuation allowances................................... (108,214) (94,910)
--------- ---------
Net deferred tax assets.............................. 476,172 385,286
--------- ---------
Deferred tax liabilities:
Oil and gas properties, principally due to
differences in basis, depletion and the
deduction of intangible drilling costs for
tax purposes......................................... 898,753 161,532
Other.................................................. 66,665 3,017
--------- ---------
Total deferred tax liabilities....................... 965,418 164,549
--------- ---------
Net deferred tax asset (liability)................... $ (489,246) $ 220,737
========= =========

At December 31, 2004, the Company had net operating loss carryforwards
("NOLs") for United States, Equatorial Guinea, South Africa and Tunisia income
tax purposes as set forth below, which are available to offset future regular
taxable income in each respective tax jurisdiction, if any. Additionally, the

99

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2004, 2003 and 2002

Company has alternative minimum tax NOLs ("AMT NOLs") in the United States which
are available to reduce future alternative minimum taxable income, if any. These
carryforwards expire as follows:

U.S. Equatorial South
---------------------- Guinea Africa Tunisia
Expiration Date NOL AMT NOL NOL NOL NOL
- --------------- --------- --------- ---------- --------- --------
(in thousands)

December 31, 2007......... $ 99,241 $ 57,377 $ - $ - $ -
December 31, 2008......... 105,787 106,558 - - -
December 31, 2009......... 46,110 28,796 - - -
December 31, 2010......... 25,144 15,253 - - -
December 31, 2011......... 3,849 3,149 - - -
December 31, 2012......... 69,098 58,723 - - -
December 31, 2018......... 129,363 99,982 - - -
December 31, 2019......... 149,351 148,070 - - -
December 31, 2020......... 16,723 15,562 - - -
December 31, 2021......... 52,914 49,672 - - -
December 31, 2022......... 41,833 39,950 - - -
December 31, 2023......... 81,564 81,784 - - -
Indefinite................ - - 10,105 10,924 16,562
-------- -------- -------- -------- -------
$ 820,977 $ 704,876 $ 10,105 $ 10,924 $ 16,562
======== ======== ======== ======== ========

The Company believes $120 million of the U.S. NOLs and AMT NOLs are subject
to Section 382 of the Internal Revenue Code and are limited in each taxable year
to approximately $20 million. During the years ended December 31, 2004, 2003 and
2002, the Company utilized $124.2 million, $17.1 million and $34.6 million of
NOLs, respectively.

NOTE R. Income Per Share Before Cumulative Effect of Change in Accounting
Principle

Basic income per share before cumulative effect of change in accounting
principle is computed by dividing income before cumulative effect of change in
accounting principle by the weighted average number of common shares outstanding
for the period. The computation of diluted income per share before cumulative
effect of change in accounting principle reflects the potential dilution that
could occur if securities or other contracts to issue common stock that are
dilutive to income before cumulative effect of change in accounting principle
were exercised or converted into common stock or resulted in the issuance of
common stock that would then share in the earnings of the Company.

The following table is a reconciliation of the basic and diluted earnings
before cumulative effect of change in accounting principle for the years ended
December 31, 2004, 2003 and 2002:

Year Ended December 31,
-----------------------------------
2004 2003 2002
--------- --------- ---------
(in thousands)

Income before cumulative effect of change in
accounting principle................................ $ 312,854 $ 395,179 $ 26,713
Interest expense on Convertible Notes, net of tax...... 802 - -
-------- -------- --------
Diluted income before cumulative effect of change
in accounting principle............................. $ 313,656 $ 395,179 $ 26,713
======== ======== ========

100

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2004, 2003 and 2002

The following table is a reconciliation of the basic and diluted weighted
average common shares outstanding for the years ended December 31, 2004, 2003
and 2002:

Year Ended December 31,
--------------------------------
2004 2003 2002
-------- -------- --------
(in thousands)

Weighted average common shares outstanding (a):
Basic............................................... 125,156 117,185 112,542
Dilutive common stock options (b)................... 1,218 1,112 1,725
Restricted stock awards............................. 529 216 21
Convertible Notes dilution.......................... 585 - -
-------- -------- --------
Diluted............................................. 127,488 118,513 114,288
======== ======== ========

- ---------------
(a) Associated with the Evergreen merger on September 28, 2004, the Company
issued 25.4 million shares of common stock, assumed 2.4 million of
in-the-money stock options, assumed 214,186 restricted stock units and
assumed the Convertible Notes.
(b) Common stock options to purchase 30,712 shares, 976,506 shares and
1,925,743 shares of common stock were outstanding but not included in the
computations of diluted income per share before cumulative effect of change
in accounting principle for the years ended December 31, 2004, 2003 and
2002, respectively, because the exercise prices of the options were greater
than the average market price of the common shares and would be
anti-dilutive to the computations.

101

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2004, 2003 and 2002

NOTE S. Geographic Operating Segment Information

The Company has operations in only one industry segment, that being the oil
and gas exploration and production industry; however, the Company is
organizationally structured along geographic operating segments, or regions. The
Company has reportable operations in the United States, Argentina, Canada and
Africa and Other. Africa and Other is primarily comprised of operations in
Equatorial Guinea, Gabon, South Africa and Tunisia.

The following tables provide the geographic operating segment data required
by Statement of Financial Accounting Standards No. 131, "Disclosure about
Segments of an Enterprise and Related Information", as well as results of
operations of oil and gas producing activities required by Statement of
Financial Accounting Standards No. 69, "Disclosures about Oil and Gas Producing
Activities" as of and for the years ended December 31, 2004, 2003 and 2002.
Geographic operating segment income tax benefits (provisions) have been
determined based on statutory rates existing in the various tax jurisdictions
where the Company has oil and gas producing activities. The "Headquarters" table
column includes revenues, expenses, additions to property, plant and equipment
and assets that are not routinely included in the earnings measures or
attributes internally reported to management on a geographic operating segment
basis.

United Africa Consolidated
States Argentina Canada and Other Headquarters Total
---------- ---------- --------- --------- ------------ ------------
(in thousands)

Year Ended December 31, 2004:
Revenues and other income:
Oil and gas revenues................... $1,451,928 $ 134,065 $ 83,749 $ 162,921 $ - $1,832,663
Interest and other..................... - - - - 14,074 14,074
Gain (loss) on disposition of
assets, net......................... 51 - (252) - 240 39
--------- --------- -------- -------- -------- ---------
1,451,979 134,065 83,497 162,921 14,314 1,846,776
--------- --------- -------- -------- -------- ---------
Costs and expenses:
Oil and gas production................. 249,551 33,174 31,269 31,510 - 345,504
Depletion, depreciation and
amortization........................ 420,363 61,773 32,123 47,835 12,780 574,874
Impairment of oil and gas properties... - - - 39,684 - 39,684
Exploration and abandonments........... 98,984 23,406 20,000 39,299 - 181,689
General and administrative............. - - - - 80,528 80,528
Accretion of discount on asset
retirement obligations............... - - - - 8,210 8,210
Interest............................... - - - - 103,387 103,387
Other.................................. - - - - 33,687 33,687
--------- --------- -------- -------- -------- ---------
768,898 118,353 83,392 158,328 238,592 1,367,563
--------- --------- -------- -------- -------- ---------
Income (loss) before income taxes...... 683,081 15,712 105 4,593 (224,278) 479,213
Income tax benefit (provision)......... (249,325) (5,499) (40) 1,413 87,092 (166,359)
--------- --------- -------- -------- -------- ---------
Net income (loss)...................... $ 433,756 $ 10,213 $ 65 $ 6,006 $(137,186) $ 312,854
========= ========= ======== ======== ======== =========
Cost incurred for oil and gas assets... $2,876,185 $ 102,452 $ 120,626 $ 74,906 $ - $3,174,169
========= ========= ======== ======== ======== =========
Segment assets (as of December 31,
2004)............................... $5,455,688 $ 708,391 $ 316,124 $ 123,073 $ 43,965 $6,647,241
========= ========= ======== ======== ======== =========

102

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2004, 2003 and 2002

United Africa Consolidated
States Argentina Canada and Other Headquarters Total
---------- ---------- --------- --------- ------------ ------------
(in thousands)

Year Ended December 31, 2003:
Revenues and other income:
Oil and gas revenues................... $1,056,796 $ 111,315 $ 84,417 $ 21,343 $ - $1,273,871
Interest and other..................... - - - - 12,292 12,292
Gain (loss) on disposition of
assets, net......................... 1,458 - 1 - (203) 1,256
--------- --------- -------- -------- --------- ----------
1,058,254 111,315 84,418 21,343 12,089 1,287,419
--------- --------- -------- -------- --------- ----------
Costs and expenses:
Oil and gas production................. 196,915 26,110 28,838 2,887 - 254,750
Depletion, depreciation and
amortization........................ 298,005 46,518 28,991 7,729 9,597 390,840
Exploration and abandonments........... 72,732 18,076 17,691 24,261 - 132,760
General and administrative............. - - - - 60,545 60,545
Accretion of discount on asset
retirement obligations............... - - - - 5,040 5,040
Interest............................... - - - - 91,388 91,388
Other.................................. - - - - 21,320 21,320
--------- --------- -------- -------- --------- ----------
567,652 90,704 75,520 34,877 187,890 956,643
--------- --------- -------- -------- --------- ----------
Income (loss) before income taxes and
cumulative effect of change in
accounting principle................. 490,602 20,611 8,898 (13,534) (175,801) 330,776
Income tax benefit (provision)......... (179,070) (7,214) (3,426) 4,738 249,375 64,403
--------- --------- -------- -------- --------- ----------
Income (loss) before cumulative effect
of change in accounting principle.... $ 311,532 $ 13,397 $ 5,472 $ (8,796) $ 73,574 $ 395,179
========= ========= ======== ======== ========= =========
Cost incurred for oil and gas assets... $ 602,167 $ 51,671 $ 54,800 $ 62,817 $ - $ 771,455
========= ========= ======== ======== ========= =========
Segment assets (as of December 31,
2003)............................... $2,645,153 $ 675,425 $ 224,921 $ 159,747 $ 246,326 $3,951,572
========= ======== ========= ======== ========= =========
Year Ended December 31, 2002:
Revenues and other income:
Oil and gas revenues................... $ 549,675 $ 77,615 $ 67,065 $ - $ - $ 694,355
Interest and other..................... - - - - 11,222 11,222
Gain (loss) on disposition of
assets, net......................... 3,248 (3) 995 - 192 4,432
--------- --------- -------- -------- --------- ---------
552,923 77,612 68,060 - 11,414 710,009
--------- --------- -------- -------- --------- ---------
Costs and expenses:
Oil and gas production................. 151,315 13,870 26,960 - - 192,145
Depletion, depreciation and
amortization........................ 140,107 39,659 27,857 - 8,752 216,375
Exploration and abandonments........... 62,955 10,306 5,841 6,792 - 85,894
General and administrative............. - - - - 48,402 48,402
Interest............................... - - - - 95,815 95,815
Other.................................. - - - - 39,602 39,602
--------- --------- -------- -------- --------- ---------
354,377 63,835 60,658 6,792 192,571 678,233
--------- --------- -------- -------- --------- ---------
Income (loss) before income taxes...... 198,546 13,777 7,402 (6,792) (181,157) 31,776
Income tax benefit (provision)......... (69,491) (4,822) (3,118) 2,377 69,991 (5,063)
--------- --------- -------- -------- --------- ---------
Net income (loss)...................... $ 129,055 $ 8,955 $ 4,284 $ (4,415) $ (111,166) $ 26,713
========= ========= ======== ======== ========= =========
Cost incurred for oil and gas assets... $ 533,560 $ 35,121 $ 33,506 $ 70,268 $ - $ 672,455
========= ========= ======== ======== ========= =========

103

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2004, 2003 and 2002

NOTE T. Impairment of Oil and Gas Properties

During October 2004, the Company concluded that a material charge for
impairment was required under SFAS 144 for its Gabonese Olowi field as
development of the discovery was canceled. Due to significant increases in
projected field development costs, primarily due to recent increases in steel
costs, the project does not offer competitive returns. The Olowi field was the
Company's only Gabonese investment. The Company's current Gabonese permit
expires in April 2005. The Company has verbally requested an extension to the
permit to allow more time for the Company to determine the best manner to exit
Gabon, however, no assurance can be given that such extension will be granted.
During 2004, the Company recorded an associated impairment charge to eliminate
the carrying value of the Company's Gabonese Olowi field of $39.7 million.

NOTE U. Subsequent Event - Volumetric Production Payments

During January 2005, the Company sold two percent of its total proved
reserves, or 20.5 million BOE of proved reserves, by means of VPPs for total
proceeds of $593 million and the assumption of the Company's obligations under
certain derivative hedge agreements. Proceeds from the VPPs were initially used
to pay down indebtedness.

The VPPs represent limited term overriding royalty interests in oil and gas
reserves which: (i) entitle the purchaser to receive production volumes over a
period of time from specific lease interests; (ii) are free and clear of all
associated future production costs and capital expenditures; (iii) are
nonrecourse to the Company (i.e., the purchaser's only recourse is to the assets
acquired); (iv) transfers title to the purchaser and (v) allows the Company to
retain the assets after the VPP's volumetric obligations have been satisfied.

The first VPP sells 58 billion cubic feet of Hugoton field gas volumes over
an expected five-year term beginning in February 2005 for $275 million of
proceeds. The second VPP sells 10.8 million barrels of oil equivalent ("MMBOE")
of Spraberry field oil volumes over an expected seven-year term beginning in
January 2006 for $318 million of proceeds.

Under SFAS 19, a VPP is considered a sale of proved reserves and the
related future production of those proved reserves. As a result the Company will
(i) remove the proved reserves associated with the VPPs; (ii) recognize the VPP
proceeds as deferred revenue which will be amortized on a unit-of-production
basis to future oil and gas revenues over the terms of the VPPs; (iii) retain
responsibility for 100 percent of the production costs and capital costs related
to VPP interests and (iv) no longer recognize production associated with the VPP
volumes.

The Company will amortize to oil and gas revenues $62.9 million of net
deferred gas revenue during 2005 associated with the Hugoton field VPP. During
2006, the Company will amortize $53.7 million of net deferred gas revenue
associated with the Hugoton field VPP and $57.6 million of net deferred oil
revenue associated with the Spraberry field VPP.

104

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTARY INFORMATION
Years Ended December 31, 2004, 2003 and 2002

Capitalized Costs

December 31,
----------------------------
2004 2003
----------- -----------
(in thousands)

Oil and gas properties:
Proved........................................................... $ 7,654,181 $ 4,983,558
Unproved......................................................... 470,435 179,825
---------- ----------
Capitalized costs for oil and gas properties..................... 8,124,616 5,163,383
Less accumulated depletion, depreciation and amortization........ (2,243,549) (1,676,136)
---------- ----------
Net capitalized costs for oil and gas properties................. $ 5,881,067 $ 3,487,247
========== ==========

Costs Incurred for Oil and Gas Producing Activities

Property
Acquisition Costs Asset Total
----------------------- Exploration Development Retirement Costs
Proved Unproved Costs Costs Obligation (a) Incurred
---------- --------- ----------- --------- -------------- ----------
(in thousands)

Year Ended December 31, 2004:
United States............... $2,213,879 $ 301,856 $ 127,338 $ 229,636 $ 3,476 $2,876,185
Argentina................... - - 49,745 49,937 2,770 102,452
Canada...................... 46,988 20,921 33,406 13,036 6,275 120,626
Africa and other............ - 18,238 32,932 21,178 2,558 74,906
--------- -------- -------- -------- -------- ---------
Total..................... $2,260,867 $ 341,015 $ 243,421 $ 313,787 $ 15,079 $3,174,169
========= ======== ======== ======== ======== ==========
Year Ended December 31, 2003:
United States............... $ 130,876 $ 12,264 $ 191,809 $ 228,064 $ 39,154 $ 602,167
Argentina................... 97 1,787 24,893 25,361 (467) 51,671
Canada...................... 63 5,028 24,899 23,040 1,770 54,800
Africa and other............ - 910 33,212 20,697 7,998 62,817
--------- -------- -------- -------- -------- ---------
Total .................... $ 131,036 $ 19,989 $ 274,813 $ 297,162 $ 48,455 $ 771,455
========= ======== ======== ======== ======== =========
Year Ended December 31, 2002:
United States............... $ 156,736 $ 34,048 $ 72,831 $ 269,945 $ - $ 533,560
Argentina................... 12 51 14,530 20,528 - 35,121
Canada...................... 457 2,329 9,992 20,728 - 33,506
Africa and other............ - 1,843 34,125 34,300 - 70,268
--------- -------- -------- -------- -------- ---------
Total .................... $ 157,205 $ 38,271 $ 131,478 $ 345,501 $ - $ 672,455
========= ======== ======== ======== ======== =========

- -------------
(a) The Company adopted SFAS 143 on January 1, 2003. See Notes B and M for
additional information regarding the Company's asset retirement
obligations.

105

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTARY INFORMATION
Years Ended December 31, 2004, 2003 and 2002

Results of Operations

Information about the Company's results of operations for oil and gas
producing activities by geographic operating segment is presented in Note S of
the accompanying Notes to Consolidated Financial Statements.

Reserve Quantity Information

The estimates of the Company's proved oil and gas reserves as of December
31, 2004, 2003 and 2002, which are located in the United States, Argentina,
Canada, Gabon, South Africa and Tunisia, were based on evaluations audited by
independent petroleum engineers with respect to the Company's major properties
and prepared by the Company's engineers with respect to all other properties.
Reserves were estimated in accordance with guidelines established by the United
States Securities and Exchange Commission and the FASB, which require that
reserve estimates be prepared under existing economic and operating conditions
with no provision for price and cost escalations except by contractual
arrangements. The Company reports all reserves held under production sharing
arrangements and concessions utilizing the "economic interest" method, which
excludes the host country's share of proved reserves. Estimated quantities for
production sharing arrangements reported under the "economic interest" method
are subject to fluctuations in the prices of oil and gas and recoverable
operating expenses and capital costs. If costs remain stable, reserve quantities
attributable to recovery of costs will change inversely to changes in commodity
prices. The reserve estimates as of December 31, 2004, 2003 and 2002 utilize
respective oil prices of $41.96, $31.10 and $29.67 per Bbl (reflecting
adjustments for oil quality), respective NGL prices of $29.12, $20.26 and $19.01
per Bbl, and respective gas prices of $4.76, $4.23 and $3.37 per Mcf (reflecting
adjustments for Btu content, gas processing and shrinkage).

Oil and gas reserve quantity estimates are subject to numerous
uncertainties inherent in the estimation of quantities of proved reserves and in
the projection of future rates of production and the timing of development
expenditures. The accuracy of such estimates is a function of the quality of
available data and of engineering and geological interpretation and judgment.
Results of subsequent drilling, testing and production may cause either upward
or downward revision of previous estimates. Further, the volumes considered to
be commercially recoverable fluctuate with changes in prices and operating
costs. The Company emphasizes that reserve estimates are inherently imprecise
and that estimates of new discoveries are more imprecise than those of currently
producing oil and gas properties. Accordingly, these estimates are expected to
change as additional information becomes available in the future.

Proved reserves at December 31, 2004 include 6.1 MMBOE related to the
ten-year extension periods contained in the Company's Argentine concession
agreements. Upon approval by the government, the extension periods begin in 2016
and 2017 depending on the effective date that each concession agreement was
granted. The Company believes, based on historical precedent, that such
extensions will be obtained as a matter of course.

The following table provides a rollforward of total proved reserves by
geographic area and in total for the years ended December 31, 2004, 2003 and
2002, as well as proved developed reserves by geographic area and in total as of
the beginning and end of each respective year. Oil and NGL volumes are expressed
in thousands of Bbls ("MBbls"), gas volumes are expressed in MMcf and total
volumes are expressed in thousands of barrels oil equivalent ("MBOE").

106

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTARY INFORMATION
Years Ended December 31, 2004, 2003 and 2002

Year Ended December 31,
-------------------------------------------------------------------------------------------------
2004 2003 2002
-------------------------------- ------------------------------ -----------------------------
Oil Oil Oil
& NGLs Gas & NGLs Gas & NGLs Gas
Total Proved Reserves: (MBbls) (MMcf) MBOE (MBbls) (MMcf) MBOE (MBbls) (MMcf) MBOE
-------- --------- --------- -------- --------- ------- ------- --------- -------

UNITED STATES
Balance, January 1............... 362,751 1,553,976 621,747 337,631 1,483,971 584,960 279,146 1,474,090 524,829
Revisions of previous estimates.. 4,671 25,764 8,965 36,823 94,759 52,616 61,529 5,983 62,525
Purchases of minerals-in-place... 11,803 1,571,053 273,646 4,422 57,124 13,942 8,634 83,361 22,528
New discoveries and extensions... 1,017 56,690 10,465 250 80,769 13,712 4,364 5,349 5,255
Production....................... (16,974) (200,598) (50,407) (16,375) (162,647) (43,483) (16,042) (84,812) (30,177)
Sales of minerals-in-place....... (11) (6,550) (1,103) - - - - - -
-------- --------- --------- -------- --------- ------- ------- --------- -------
Balance, December 31............. 363,257 3,000,335 863,313 362,751 1,553,976 621,747 337,631 1,483,971 584,960

ARGENTINA
Balance, January 1............... 33,469 549,856 125,112 31,532 532,081 120,211 35,669 471,150 114,193
Revisions of previous estimates.. (3,040) (61,483) (13,287) 2,027 44,064 9,372 (4,954) 47,829 3,017
New discoveries and extensions... 6,428 116,526 25,849 3,562 8,068 4,907 3,985 41,652 10,927
Production....................... (3,689) (44,525) (11,110) (3,652) (34,357) (9,378) (3,168) (28,550) (7,926)
-------- --------- --------- -------- --------- ------- ------- --------- -------
Balance, December 31............. 33,168 560,374 126,564 33,469 549,856 125,112 31,532 532,081 120,211

CANADA
Balance, January 1............... 2,407 93,829 18,045 2,361 119,328 22,249 2,659 132,061 24,669
Revisions of previous estimates.. 710 8,580 2,140 344 (14,920) (2,143) 24 (1,150) (167)
Purchases of mineral-in-place.... 823 22,127 4,511 - - - - - -
New discoveries and extensions... 541 10,656 2,317 73 4,630 845 68 6,070 1,080
Production....................... (386) (15,323) (2,940) (371) (15,209) (2,906) (390) (17,653) (3,333)
-------- --------- --------- -------- --------- ------- ------- --------- -------
Balance, December 31............. 4,095 119,869 24,073 2,407 93,829 18,045 2,361 119,328 22,249

AFRICA
Balance, January 1............... 24,154 - 24,154 9,320 - 9,320 7,685 - 7,685
Revisions of previous estimates.. (12,111) - (12,111) (1,817) - (1,817) 790 - 790
New discoveries and extensions... 502 - 502 17,374 - 17,374 845 - 845
Production....................... (4,274) - (4,274) (723) - (723) - - -
-------- --------- --------- -------- --------- ------- ------- --------- -------
Balance, December 31............. 8,271 - 8,271 24,154 - 24,154 9,320 - 9,320

TOTAL
Balance, January 1............... 422,781 2,197,661 789,058 380,844 2,135,380 736,740 325,159 2,077,301 671,376
Revisions of previous estimates.. (9,770) (27,139) (14,293) 37,377 123,903 58,028 57,389 52,662 66,165
Purchases of minerals-in-place... 12,626 1,593,180 278,157 4,422 57,124 13,942 8,634 83,361 22,528
New discoveries and extensions... 8,488 183,872 39,133 21,259 93,467 36,838 9,262 53,071 18,107
Production....................... (25,323) (260,446) (68,731) (21,121) (212,213) (56,490) (19,600) (131,015) (41,436)
Sales of minerals-in-place....... (11) (6,550) (1,103) - - - - - -
-------- --------- --------- -------- --------- ------- ------- --------- --------
Balance, December 31............. 408,791 3,680,578 1,022,221 422,781 2,197,661 789,058 380,844 2,135,380 736,740
======== ========= ========= ======== ========= ======= ======= ========= ========

Proved Developed Reserves:
United States.................. 209,349 1,202,264 409,727 209,948 1,067,701 387,899 196,893 1,027,750 368,184
Argentina...................... 21,149 352,660 79,926 22,180 402,640 89,287 28,248 341,967 85,243
Canada......................... 2,312 86,500 16,728 2,042 90,003 17,042 2,086 94,607 17,854
Africa......................... 6,817 - 6,817 - - - - - -
-------- ---------- --------- -------- --------- ------- ------- --------- --------
Balance, January 1........... 239,627 1,641,424 513,198 234,170 1,560,344 494,228 227,227 1,464,324 471,281
======== ========== ========= ======== ========= ======= ======= ========= ========

United States.................. 223,749 2,045,275 564,628 209,349 1,202,264 409,727 209,948 1,067,701 387,899
Argentina...................... 20,565 320,616 74,001 21,149 352,660 79,926 22,180 402,640 89,287
Canada......................... 3,849 107,547 21,773 2,312 86,500 16,728 2,042 90,003 17,042
Africa......................... 8,271 - 8,271 6,817 - 6,817 - - -
-------- ---------- --------- -------- --------- ------- ------- --------- --------
Balance, December 31......... 256,434 2,473,438 668,673 239,627 1,641,424 513,198 234,170 1,560,344 494,228
======== ========== ========= ======== ========= ======= ======= ========= ========

- --------------------------------------------------------------------------------
o The proved gas reserves as of December 31, 2004 include 271.7 MMcf of gas
that will be produced and utilized as field fuel. Field fuel is gas
consumed to operate field equipment (primarily compressors) prior to the
gas being delivered to a sales point. The above production amounts for 2004
include approximately 9,600 MMcf of field fuel.
- --------------------------------------------------------------------------------

107

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTARY INFORMATION
Years Ended December 31, 2004, 2003 and 2002

Standardized Measure of Discounted Future Net Cash Flows

The standardized measure of discounted future net cash flows is computed by
applying year-end prices of oil and gas (with consideration of price changes
only to the extent provided by contractual arrangements) to the estimated future
production of proved oil and gas reserves less estimated future expenditures
(based on year-end costs) to be incurred in developing and producing the proved
reserves, discounted using a rate of 10 percent per year to reflect the
estimated timing of the future cash flows. Future income taxes are calculated by
comparing undiscounted future cash flows to the tax basis of oil and gas
properties plus available carryforwards and credits and applying the current tax
rates to the difference. The discounted future cash flow estimates do not
include the effects of the Company's commodity hedging contracts. Utilizing
December 31, 2004 commodity prices held constant over each hedge contract's
term, the net present value of the Company's hedge contracts, less associated
estimated income taxes and discounted at 10 percent, was a liability of
approximately $291 million at December 31, 2004.

Discounted future cash flow estimates like those shown below are not
intended to represent estimates of the fair value of oil and gas properties.
Estimates of fair value should also consider probable reserves, anticipated
future oil and gas prices, interest rates, changes in development and production
costs and risks associated with future production. Because of these and other
considerations, any estimate of fair value is necessarily subjective and
imprecise.

108

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTARY INFORMATION
Years Ended December 31, 2004, 2003 and 2002

The following tables provide the standardized measure of discounted future
cash flows by geographic area and in total for the years ended December 31,
2004, 2003 and 2002, as well as a rollforward in total for each respective year:

Year Ended December 31,
-----------------------------------------
2004 2003 2002
----------- ----------- -----------
(in thousands)

UNITED STATES
Oil and gas producing activities:
Future cash inflows................................... $28,373,520 $17,760,911 $14,725,914
Future production costs............................... (8,232,530) (5,440,383) (4,394,491)
Future development costs.............................. (1,829,937) (1,188,394) (864,386)
Future income tax expense............................. (5,612,935) (3,057,968) (2,325,946)
---------- ---------- ----------
12,698,118 8,074,166 7,141,091
10% annual discount factor............................ (7,116,815) (4,276,678) (3,684,400)
---------- ---------- ----------
Standardized measure of discounted future cash flows..... $ 5,581,303 $ 3,797,488 $ 3,456,691
========== ========== ==========
ARGENTINA
Oil and gas producing activities:
Future cash inflows................................... $ 1,747,737 $ 1,257,068 $ 986,716
Future production costs............................... (289,742) (233,399) (175,938)
Future development costs.............................. (234,309) (136,663) (84,669)
Future income tax expense............................. (221,733) (161,683) (143,845)
---------- ---------- ----------
1,001,953 725,323 582,264
10% annual discount factor............................ (354,661) (282,205) (242,158)
---------- ---------- ----------
Standardized measure of discounted future cash flows..... $ 647,292 $ 443,118 $ 340,106
========== ========== ==========
CANADA
Oil and gas producing activities:
Future cash inflows................................... $ 889,940 $ 520,976 $ 502,260
Future production costs............................... (286,197) (91,675) (89,246)
Future development costs.............................. (40,023) (11,551) (22,294)
Future income tax expense............................. (96,431) (72,895) (87,363)
---------- ---------- ----------
467,289 344,855 303,357
10% annual discount factor............................ (190,822) (126,436) (104,345)
---------- ---------- ----------
Standardized measure of discounted future cash flows..... $ 276,467 $ 218,419 $ 199,012
========== ========== ==========
AFRICA
Oil and gas producing activities:
Future cash inflows................................... $ 333,091 $ 713,459 $ 279,896
Future production costs............................... (75,381) (212,615) (95,216)
Future development costs.............................. (14,497) (261,413) (26,770)
Future income tax expense............................. (81,680) (17,062) (10,912)
---------- ---------- ----------
161,533 222,369 146,998
10% annual discount factor............................ (23,520) (98,141) (16,255)
---------- ---------- ----------
Standardized measure of discounted future cash flows..... $ 138,013 $ 124,228 $ 130,743
========== ========== ==========
TOTAL
Oil and gas producing activities:
Future cash inflows................................... $31,344,288 $20,252,414 $16,494,786
Future production costs............................... (8,883,850) (5,978,072) (4,754,891)
Future development costs (a).......................... (2,118,766) (1,598,021) (998,119)
Future income tax expense............................. (6,012,779) (3,309,608) (2,568,066)
---------- ---------- ----------
14,328,893 9,366,713 8,173,710
10% annual discount factor............................ (7,685,818) (4,783,460) (4,047,158)
---------- ---------- ----------
Standardized measure of discounted future cash flows..... $ 6,643,075 $ 4,583,253 $ 4,126,552
========== ========== ==========

- -------------
(a) Includes $258.1 million and $208.1 million of undiscounted future asset
retirement expenditures estimated as of December 31, 2004 and 2003,
respectively, using current estimates of future abandonment costs. See
Notes B and M for corresponding information regarding the Company's
discounted asset retirement obligations.

109

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTARY INFORMATION
Years Ended December 31, 2004, 2003 and 2002

Changes in Standardized Measure of Discounted Future Net Cash Flows

Year Ended December 31,
-----------------------------------------
2004 2003 2002
----------- ----------- -----------
(in thousands)

Oil and gas sales, net of production costs............. $(1,719,990) $(1,136,520) $ (489,338)
Net changes in prices and production costs............. 2,082,706 670,165 2,042,575
Extensions and discoveries............................. 302,794 413,777 152,253
Development costs incurred during the period........... 249,890 202,396 262,469
Sales of minerals-in-place............................. (14,222) - -
Purchases of minerals-in-place......................... 2,058,195 198,442 187,460
Revisions of estimated future development costs........ (447,828) (444,726) (387,404)
Revisions of previous quantity estimates............... 140,950 458,468 527,987
Accretion of discount.................................. 644,238 514,608 250,033
Changes in production rates, timing and other.......... (167,400) (71,557) 99,722
---------- ---------- ----------
Change in present value of future net revenues......... 3,129,333 805,053 2,645,757
Net change in present value of future income taxes..... (1,069,511) (348,352) (1,019,531)
---------- ---------- ----------
2,059,822 456,701 1,626,226
Balance, beginning of year............................. 4,583,253 4,126,552 2,500,326
---------- ---------- ----------
Balance, end of year................................... $ 6,643,075 $ 4,583,253 $ 4,126,552
========== ========== ==========

110

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTARY INFORMATION
Years Ended December 31, 2004, 2003 and 2002

Selected Quarterly Financial Results

The following table provides selected quarterly financial results for the
years ended December 31, 2004 and 2003:

Quarter
------------------------------------------------
First Second Third (a) Fourth
--------- --------- --------- ---------
(in thousands, except per share data)

2004:
Oil and gas revenues........................... $ 435,527 $ 435,930 $ 441,724 $ 519,482
Total revenues and other income................ $ 437,249 $ 437,308 $ 443,151 $ 529,068
Total costs and expenses....................... $ 337,284 $ 315,847 $ 338,708 $ 375,724
Net income..................................... $ 60,188 $ 69,702 $ 80,916 $ 102,048
Net income per share:
Basic ...................................... $ .51 $ .59 $ .68 $ .71
======== ======== ======== ========
Diluted..................................... $ .50 $ .58 $ .67 $ .69
======== ======== ======== ========
2003:
Oil and gas revenues........................... $ 273,431 $ 334,077 $ 326,210 $ 340,153
Total revenues and other income................ $ 277,570 $ 335,441 $ 326,604 $ 347,804
Total costs and expenses....................... $ 206,459 $ 255,626 $ 234,686 $ 259,872
Net income:
Income before cumulative effect of change
in accounting principle................... $ 68,807 $ 77,185 $ 191,813 $ 57,374
Cumulative effect of change in accounting
principle, net of tax..................... 15,413 - - -
-------- -------- -------- --------
Net income.................................. $ 84,220 $ 77,185 $ 191,813 $ 57,374
======== ======== ======== ========
Basic earnings per share:
Income before cumulative effect of change
in accounting principle................... $ .59 $ .66 $ 1.64 $ .49
Cumulative effect of change in accounting
principle, net of tax..................... .13 - - -
-------- -------- -------- --------
Net income.................................. $ .72 $ .66 $ 1.64 $ .49
======== ======== ======== ========
Diluted earnings per share:
Income before cumulative effect of change
in accounting principle................... $ .58 $ .65 $ 1.62 $ .48
Cumulative effect of change in accounting
principle, net of tax..................... .13 - - -
-------- -------- -------- --------
Net income.................................. $ .71 $ .65 $ 1.62 $ .48
======== ======== ======== ========

- -------------
(a) The Company's third quarter results for 2003 include a $104.7 million
adjustment to reduce United States deferred tax asset valuation allowances.
See Note Q for additional information regarding income taxes.

111

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of disclosure controls and procedures. The Company's principal
executive officer and principal financial officer have evaluated, as required by
Rule 13a-15(b) under the Securities Exchange Act of 1934 (the "Exchange Act"),
the Company's disclosure controls and procedures (as defined in Exchange Act
Rule 13a-15(e)) as of the end of the period covered by this annual report on
Form 10-K. Based on that evaluation, the principal executive officer and
principal financial officer concluded that the design and operation of the
Company's disclosure controls and procedures are effective in ensuring that
information required to be disclosed by the Company in the reports that it files
or submits under the Exchange Act is recorded, processed, summarized and
reported within the time periods specified in the SEC's rules and forms.

Changes in internal control over financial reporting. There have been no
changes in the Company's internal control over financial reporting (as defined
in Rule 13a-15(f) under the Exchange Act) that occurred during the Company's
last fiscal quarter that have materially affected or are reasonably likely to
materially affect the Company's internal control over financial reporting.

MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of Pioneer Natural Resources Company (the "Company") is
responsible for establishing and maintaining adequate internal control over
financial reporting. The Company's internal control over financial reporting is
a process designed under the supervision of the Company's Chief Executive
Officer and Chief Financial Officer to provide reasonable assurance regarding
the reliability of financial reporting and the preparation of the Company's
financial statements for external purposes in accordance with generally accepted
accounting principles.

As of December 31, 2004, management assessed the effectiveness of the
Company's internal control over financial reporting based on the criteria for
effective internal control over financial reporting established in "Internal
Control -- Integrated Framework", issued by the Committee of Sponsoring
Organizations of the Treadway Commission. Based on the assessment, management
determined that the Company maintained effective internal control over financial
reporting as of December 31, 2004, based on those criteria.

Ernst & Young LLP, the independent registered public accounting firm that
audited the consolidated financial statements of the Company included in this
Annual Report on Form 10-K, has issued an attestation report on management's
assessment of the effectiveness of the Company's internal control over financial
reporting as of December 31, 2004. The report, which expresses unqualified
opinions on management's assessment and on the effectiveness of the Company's
internal control over financial reporting as of December 31, 2004, is included
in this Item under the heading "Report of Independent Registered Public
Accounting Firm on Internal Control Over Financial Reporting".

112

REPORT OF INDEPENDENT REGISTERED PUBLIC
ACCOUNTING FIRM ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The Board of Directors and Stockholders of
Pioneer Natural Resources Company:

We have audited management's assessment, included in the accompanying
Management's Report on Internal Control Over Financial Reporting, that Pioneer
Natural Resources Company and subsidiaries (the "Company") maintained effective
internal control over financial reporting as of December 31, 2004, based on
criteria established in Internal Control - Integrated Framework issued by the
Committee of Sponsoring Organizations of the Treadway Commission (the "COSO
criteria"). The Company's management is responsible for maintaining effective
internal control over financial reporting and for its assessment of the
effectiveness of internal control over financial reporting. Our responsibility
is to express an opinion on management's assessment and an opinion on the
effectiveness of the Company's internal control over financial reporting based
on our audit.

We conducted our audit in accordance with the standards of the Public
Company Accounting Oversight Board (United States). Those standards require that
we plan and perform the audit to obtain reasonable assurance about whether
effective internal control over financial reporting was maintained in all
material respects. Our audit included obtaining an understanding of internal
control over financial reporting, evaluating management's assessment, testing
and evaluating the design and operating effectiveness of internal control, and
performing such other procedures as we considered necessary in the
circumstances. We believe that our audit provides a reasonable basis for our
opinion.

A company's internal control over financial reporting is a process designed
to provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles. A company's internal control over
financial reporting includes those policies and procedures that (1) pertain to
the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the company; (2)
provide reasonable assurance that transactions are recorded as necessary to
permit preparation of financial statements in accordance with generally accepted
accounting principles, and that receipts and expenditures of the company are
being made only in accordance with authorizations of management and directors of
the company; and (3) provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use, or disposition of the company's
assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial
reporting may not prevent or detect misstatements. Also, projections of any
evaluation of effectiveness to future periods are subject to the risk that
controls may become inadequate because of changes in conditions, or that the
degree of compliance with the policies or procedures may deteriorate.

In our opinion, management's assessment that the Company maintained
effective internal control over financial reporting as of December 31, 2004, is
fairly stated, in all material respects, based on the COSO criteria. Also, in
our opinion, the Company maintained, in all material respects, effective
internal control over financial reporting as of December 31, 2004, based on the
COSO criteria.

We also have audited, in accordance with the standards of the Public
Company Accounting Oversight Board (United States), the consolidated balance
sheets as of December 31, 2004 and 2003 and the related consolidated statements
of operations, stockholders' equity, cash flows and comprehensive income (loss)
for each of the three years in the period ended December 31, 2004 of the Company
and our report dated February 17, 2005 expressed an unqualified opinion thereon.

Ernst & Young LLP

Dallas, Texas
February 17, 2005
113

ITEM 9B. OTHER INFORMATION

None.

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

The information required in response to this item is set forth in the
Company's definitive proxy statement for the annual meeting of stockholders to
be held on May 12, 2005 and is incorporated herein by reference.

ITEM 11. EXECUTIVE COMPENSATION

The information required in response to this item is set forth in the
Company's definitive proxy statement for the annual meeting of stockholders to
be held on May 12, 2005 and is incorporated herein by reference.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT

See "Item 5. Market for Registrant's Common Stock, Related Stockholder
Matters and Issuer Purchases of Equity Securities" for information regarding the
Company's equity compensation plans. The information required in response to
this item is set forth in the Company's definitive proxy statement for the
annual meeting of stockholders to be held on May 12, 2005 and is incorporated
herein by reference.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

The information required by Item 201(d) of Regulation S-K in response to
this item is provided in "Item 5. Market for Registrant's Common Stock, Related
Stockholder Matters and Issuer Purchases of Equity Securities". The information
required by Item 403 of Regulation S-K in response to this item is set forth in
the Company's definitive proxy statement for the annual meeting of stockholders
to be held on May 12, 2005 and is incorporated herein by reference.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

The information required in response to this item is set forth in the
Company's definitive proxy statement for the annual meeting of stockholders to
be held on May 12, 2005 and is incorporated herein by reference.

114

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a) Listing of Financial Statements

Financial Statements

The following consolidated financial statements of the Company are included
in "Item 8. Financial Statements and Supplementary Data":

Report of Independent Registered Pubic Accounting Firm
Consolidated Balance Sheets as of December 31, 2004 and 2003
Consolidated Statements of Operations for the Years Ended December 31,
2004, 2003 and 2002
Consolidated Statements of Stockholders' Equity for the Years Ended
December 31, 2004, 2003 and 2002
Consolidated Statements of Cash Flows for the Years Ended December 31,
2004, 2003 and 2002
Consolidated Statements of Comprehensive Income (Loss) for the Years
Ended December 31, 2004, 2003 and 2002
Notes to Consolidated Financial Statements
Unaudited Supplementary Information

(b) Exhibits

The exhibits to this Report required to be filed pursuant to Item 15(c) are
listed below and in the "Index to Exhibits" attached hereto.

(c) Financial Statement Schedules

No financial statement schedules are required to be filed as part of this
Report or they are inapplicable.

115

Exhibits

Exhibit
Number Description

2.1 - Agreement and Plan of Merger, dated as of May 3, 2004, among the
Company, Evergreen and BC Merger Sub, Inc. (incorporated by
reference to Exhibit 2.1 to the Company's Current Report on Form
8-K, File No. 1-13245, filed with the SEC on May 5, 2004).
3.1 - Amended and Restated Certificate of Incorporation of the Company
(incorporated by reference to Exhibit 3.1 to the Company's
Registration Statement on Form S-4, dated June 27, 1997,
Registration No. 333-26951).
3.2 - Restated Bylaws of the Company (incorporated by reference to Exhibit
3.2 to the Company's Registration Statement on Form S-4, dated June
27, 1997, Registration No. 333-26951).
4.1 - Form of Certificate of Common Stock, par value $.01 per share, of
the Company (incorporated by reference to Exhibit 4.1 to the
Company's Registration Statement on Form S-4, dated June 27, 1997,
Registration No. 333-26951).
4.2 - Rights Agreement dated July 24, 2001, between the Company and
Continental Stock Transfer & Trust Company, as Rights Agent
(incorporated by reference to Exhibit 4.1 to the Company's
Registration Statement on Form 8-A, File No. 1-13245, filed with the
SEC on July 24, 2001).
4.3 - Certificate of Designation of Series A Junior Participating
Preferred Stock (incorporated by reference to Exhibit A to Exhibit
4.1 to the Company's Registration Statement on Form 8-A, File No.
1-13245, filed with the SEC on July 24, 2001).
4.4 - Indenture dated April 12, 1995, between Pioneer USA (successor to
Parker & Parsley Petroleum Company ("Parker & Parsley")) and The
Chase Manhattan Bank (National Association), as trustee
(incorporated by reference to Exhibit 4.1 to Parker & Parsley's
Current Report on Form 8-K, dated April 12, 1995, File No. 1-10695).
4.5 - First Supplemental Indenture dated as of August 7, 1997, among
Parker & Parsley, The Chase Manhattan Bank, as trustee, and Pioneer
USA, with respect to the indenture identified above as Exhibit 4.4
(incorporated by reference to Exhibit 10.5 to the Company's
Quarterly Report on Form 10-Q for the period ended September 30,
1997, File No. 1-13245).
4.6 - Second Supplemental Indenture dated as of December 30, 1997, among
Pioneer USA, Pioneer NewSub1, Inc. and The Chase Manhattan Bank, as
trustee, with respect to the indenture identified above as Exhibit
4.4 (incorporated by reference to Exhibit 10.17 to the Company's
Current Report on Form 8-K, File No. 1-13245, filed with the SEC on
January 2, 1998).
4.7 - Third Supplemental Indenture dated as of December 30, 1997, among
Pioneer NewSub1, Inc. (as successor to Pioneer USA), Pioneer DebtCo,
Inc. and The Chase Manhattan Bank, as trustee, with respect to the
indenture identified above as Exhibit 4.4 (incorporated by reference
to Exhibit 10.18 to the Company's Current Report on Form 8-K, File
No. 1-13245, filed with the SEC on January 2, 1998).
4.8 - Fourth Supplemental Indenture dated as of December 30, 1997, among
Pioneer DebtCo, Inc. (as successor to Pioneer NewSub1, Inc., as
successor to Pioneer USA), the Company, Pioneer USA and The Chase
Manhattan Bank, as trustee, with respect to the indenture identified
above as Exhibit 4.4 (incorporated by reference to Exhibit 10.19 to
the Company's Current Report on Form 8-K, File No. 1-13245, filed
with the SEC on January 2, 1998).
4.9 - Indenture dated January 13, 1998, between the Company and The Bank
of New York, as trustee (incorporated by reference to Exhibit 99.1
to the Company's and Pioneer USA's Current Report on Form 8-K, File
No. 1-13245, filed with the SEC on January 14, 1998).
4.10 - First Supplemental Indenture dated as of January 13, 1998, among the
Company, Pioneer USA, as the subsidiary guarantor, and The Bank of
New York, as trustee, with respect to the indenture identified above
as Exhibit 4.9 (incorporated by reference to Exhibit 99.2 to the
Company's and Pioneer USA's Current Report on Form 8-K, File No.
1-13245, filed with the SEC on January 14, 1998).
4.11 - Second Supplemental Indenture dated as of April 11, 2000, among the
Company, Pioneer USA, as the subsidiary guarantor, and The Bank of
New York, as trustee, with respect to the indenture identified above
as Exhibit 4.9 (incorporated by reference to Exhibit 10.1 to the
Company's Quarterly Report on Form 10-Q for the period ended March
31, 2000, File No. 1-13245).

116

Exhibit
Number Description

4.12 - Third Supplemental Indenture dated as of April 30, 2002, among the
Company, Pioneer USA, as the subsidiary guarantor, and The Bank of
New York, as trustee, with respect to the indenture identified above
as Exhibit 4.9 (incorporated by reference to Exhibit 10.4 to the
Company's Quarterly Report on Form 10-Q for the three months ended
March 31, 2002, File No. 1-13245).
4.13 - Fourth Supplemental Indenture dated as of July 15, 2004, among the
Company and The Bank of New York, as trustee, with respect to the
indenture identified above as Exhibit 4.9 (incorporated by reference
to Exhibit 99.1 to the Company's Current Report on Form 8-K, File
No. 1-13245, filed with the SEC on July 19, 2004).
4.14 - Fifth Supplemental Indenture dated as of July 15, 2004, among the
Company, Pioneer USA, as the subsidiary guarantor, and The Bank of
New York, as trustee, with respect to the indenture identified above
as Exhibit 4.9 (incorporated by reference to Exhibit 99.2 to the
Company's Current Report on Form 8-K, File No. 1-13245, filed with
the SEC on July 19, 2004).
4.15 - Indenture dated as of March 10, 2004, among Evergreen and Wachovia
Bank, National Association, as trustee, relating to Evergreen's
5.875% Senior Subordinated Notes due 2012 (incorporated by reference
to Exhibit 4.1 to Evergreen's Quarterly Report on Form 10-Q for the
quarter ended March 31, 2004, File No. 1-13171, filed with the SEC
on May 10, 2004).
4.16 - Indenture dated as of December 18, 2001, among Evergreen and First
Union National Bank, as trustee, relating to Evergreen's 4.75%
Senior Convertible Notes due December 15, 2021 (incorporated by
reference to Exhibit 4.3 to Evergreen's Annual Report on Form 10-K
for the year ended December 31, 2001, File No. 1-13171, filed with
the SEC on March 11, 2002).
4.17 - First Supplemental Indenture dated as of September 28, 2004, among
Pioneer Evergreen Properties, LLC (as successor to Evergreen) and
Wachovia Bank, National Association, as trustee, with respect to the
indenture identified above as Exhibit 4.15 (incorporated by
reference to Exhibit 4.5 to the Company's Current Report on Form
8-K, File No. 1-13245, filed with the SEC on October 1, 2004).
4.18 - First Supplemental Indenture dated as of September 28, 2004, among
the Company, Evergreen and Wachovia Bank, National Association (as
successor to First Union National Bank), as trustee, with respect
to the indenture identified above as Exhibit 4.16 (incorporated by
reference to Exhibit 4.1 to the Company's Amendment to the Current
Report on Form 8-K/A, File No. 1-13245, filed with the SEC on
November 5, 2004).
4.19 - Second Supplemental Indenture dated as of September 28, 2004, among
the Company, Pioneer Evergreen Properties, LLC (as successor to
Evergreen) and Wachovia Bank, National Association (as successor to
First Union National Bank), as trustee, with respect to the
indenture identified above as Exhibit 4.16 (incorporated by
reference to Exhibit 4.7 to the Company's Current Report on Form
8-K, File No. 1-13245, filed with the SEC on October 1, 2004).
4.20 - Third Supplemental Indenture dated as of September 30, 2004, among
the Company, Pioneer Debt Sub, LLC and Wachovia Bank, National
Association (as successor to First Union National Bank), as trustee,
with respect to the indenture identified above as Exhibit 4.16
(incorporated by reference to Exhibit 4.1 to the Company's Current
Report on Form 8-K, File No. 1-13245, filed with the SEC on November
5, 2004).
4.21 - Fourth Supplemental Indenture dated as of September 30, 2004, among
the Company and Wachovia Bank, National Association (as successor to
First Union National Bank), as trustee, with respect to the
indenture identified above as Exhibit 4.16 (incorporated by
reference to Exhibit 4.2 to the Company's Current Report on Form
8-K, File No. 1-13245, filed with the SEC on November 5, 2004).
4.22 - Second Supplemental Indenture dated as of September 30, 2004, among
Pioneer Debt Sub, LLC and Wachovia Bank, National Association, as
trustee, with respect to the indenture identified above as Exhibit
4.15 (incorporated by reference to Exhibit 4.3 to the Company's
Current Report on Form 8-K, File No. 1-13245, filed with the SEC on
November 5, 2004).
4.23 - Third Supplemental Indenture dated as of September 30, 2004, among
the Company and Wachovia Bank, National Association, as trustee,
with respect to the indenture identified above as Exhibit 4.15
(incorporated by reference to Exhibit 4.15 to the Company's Current
Report on Form 8-K, File No. 1-13245, filed with the SEC on November
5, 2004).
4.24 - Fourth Supplemental Indenture dated as of November 1, 2004, among
the Company, Pioneer USA, as guarantor, and Wachovia Bank, National
Association, as trustee, with respect to the indenture identified
above as Exhibit 4.15 (incorporated by reference to Exhibit 4.5 to
the Company's Current Report on Form 8-K, File No. 1-13245, filed
with the SEC on November 5, 2004).

117

Exhibit
Number Description

10.1H - 1991 Stock Option Plan of Mesa Inc. ("Mesa") (incorporated by
reference to Exhibit 10(v) to Mesa's Annual Report on Form 10-K for
the period ended December 31, 1991).
10.2H - 1996 Incentive Plan of Mesa (incorporated by reference to Exhibit
10.28 to the Company's Registration Statement on Form S-4, dated
June 27, 1997, Registration No. 333-26951).
10.3H - Parker & Parsley Long-Term Incentive Plan, dated February 19, 1991
(incorporated by reference to Exhibit 4.1 to Parker & Parsley's
Registration Statement on Form S-8, Registration No. 33-38971).
10.4H - First Amendment to the Parker & Parsley Long-Term Incentive Plan,
dated August 23, 1991 (incorporated by reference to Exhibit 10.2 to
Parker & Parsley's Registration Statement on Form S-1, dated
February 28, 1992, Registration No. 33-46082).
10.5H - The Company's Long-Term Incentive Plan (incorporated by reference
to Exhibit 4.1 to the Company's Registration Statement on Form S-8,
Registration No. 333-35087, filed with the SEC on September 8,
1997).
10.6H - First Amendment to the Company's Long-Term Incentive Plan, effective
as of November 23, 1998 (incorporated by reference to Exhibit 10.72
to the Company's Annual Report on Form 10-K for the period ended
December 31, 1999, File No. 1-13245).
10.7H - Second Amendment to the Company's Long-Term Incentive Plan,
effective as of May 20, 1999 (incorporated by reference to Exhibit
10.73 to the Company's Annual Report on Form 10-K for the period
ended December 31, 1999, File No. 1-13245).
10.8H - Third Amendment to the Company's Long-Term Incentive Plan,
effective as of February 17, 2000 (incorporated by reference to
Exhibit 10.76 to the Company's Annual Report on Form 10-K for the
period ended December 31, 1999, File No. 1-13245).
10.9H - The Company's Employee Stock Purchase Plan (incorporated by
reference to Exhibit 4.1 to the Company's Registration Statement on
Form S-8, Registration No. 333-35165, filed with the SEC on
September 8, 1997).
10.10H - First Amendment to the Company's Employee Stock Purchase Plan,
dated December 9, 1998 (incorporated by reference to the Company's
Annual Report on Form 10-K for the year ended December 31, 1998,
File No. 1-13245).
10.11H - Second Amendment to the Company's Employee Stock Purchase Plan,
dated December 14, 1999 (incorporated by reference to Exhibit 10.74
to the Company's Annual Report on Form 10-K for the period ended
December 31, 1999, File No. 1-13245).
10.12H - The Company's Deferred Compensation Retirement Plan (incorporated
by reference to Exhibit 4.1 to the Company's Registration Statement
on Form S-8, Registration No. 333-39153, filed with the SEC on
October 31, 1997).
10.13H - Omnibus Amendment to Nonstatutory Stock Option Agreements, included
as part of the Parker & Parsley Long-Term Incentive Plan, dated as
of November 16, 1995, between Parker & Parsley and Named Executive
Officers identified on Schedule 1 setting forth additional details
relating to the Parker & Parsley Long-Term Incentive Plan
(incorporated by reference to Parker & Parsley's Annual Report on
Form 10-K for the year ended December 31, 1995, File No. 1-10695).
10.14H - Severance Agreement, dated as of August 8, 1997, between the Company
and Scott D. Sheffield, together with a schedule identifying
substantially identical agreements between the Company and each of
the other named executive officers identified on Schedule I for the
purpose of defining the payment of certain benefits upon the
termination of the officer's employment under certain circumstances
(incorporated by reference to Exhibit 10.7 to the Company's
Quarterly Report on Form 10-Q for the period ended September 30,
1997, File No. 1-13245).
10.15G - Amendment to Schedule I with respect to the Severance Agreement
identified above as Exhibit 10.14.
10.16G - Form of Severance Agreement, dated January 1, 2005, between the
Company and the Officer, together with a schedule identifying
substantially identical agreements between the Company and each of
the other named officers identified on Exhibit A for the purpose of
defining the payment of certain benefits upon the termination of the
officer's employment under certain circumstances.
10.17G - Severance Agreement, dated as of January 1, 2005, between the
Company and Kenneth H. Sheffield, Jr., for the purpose of defining
the payment of certain benefits upon the termination of the
officer's employment under certain circumstances.

118

Exhibit
Number Description

10.18G - Severance Agreement, dated as of December 1, 2000, between the
Company and Chris J. Cheatwood, for the purpose of defining the
payment of certain benefits upon the termination of the officer's
employment under certain circumstances.
10.19G - Amendment to Severance Agreement, dated as of February 19, 2002,
between the Company and Chris J. Cheatwood, for the purpose of
redefining the payment of certain benefits upon the termination of
the officer's employment under certain circumstances with respect to
the Severance Agreement identified above as Exhibit 10.18.
10.20G - Severance Agreement, dated as of November 1, 2003, between the
Company and A. R. Alameddine, for the purpose of defining the
payment of certain benefits upon the termination of the officer's
employment under certain circumstances.
10.21G - Severance Agreement, dated as of December 1, 1999, between the
Company and Thomas C. Halbouty, for the purpose of defining the
payment of certain benefits upon the termination of the officer's
employment under certain circumstances.
10.22G - Severance Agreement, dated as of August 8, 1997, between the
Company and Larry N. Paulsen, for the purpose of defining the
payment of certain benefits upon the termination of the officer's
employment under certain circumstances.
10.23G - Amendment to August 8, 1997 Severance Agreement, dated as of
February 19, 2002, between the Company and Larry N. Paulsen, for the
purpose of redefining the payment of certain benefits upon the
termination of the officer's employment under certain circumstances
with respect to the Severance Agreement identified above as Exhibit
10.22.
10.24G - Severance Agreement, dated as of August 24, 1999, between the
Company and Danny Kellum, for the purpose of defining the payment of
certain benefits upon the termination of the officer's employment
under certain circumstances.
10.25G - Amendment to August 24, 1999 Severance Agreement, dated as of
February 19, 2002, between the Company and Danny L. Kellum, for the
purpose of redefining the payment of certain benefits upon the
termination of the officer's employment under certain circumstances
with respect to the Severance Agreement identified above as Exhibit
10.24.
10.26G - Severance Agreement, dated as of January 1, 2005, between the
Company and Todd A. Dillabough, for the purpose of defining the
payment of certain benefits upon the termination of the officer's
employment under certain circumstances.
10.27H - Indemnification Agreement, dated as of August 8, 1997, between the
Company and Scott D. Sheffield, together with a schedule identifying
substantially identical agreements between the Company and each of
the Company's other directors and named executive officers
identified on Schedule I (incorporated by reference to Exhibit 10.8
to the Company's Quarterly Report on Form 10-Q for the period ended
September 30, 1997, File No. 1-13245).
10.28G - Amendment to Schedule I with respect to the Indemnification
Agreement identified above as Exhibit 10.27.
10.29H - Pioneer USA 40l(k) and Matching Plan, Amended and Restated Effective
as of January 1, 2002 (incorporated by reference to Exhibit 10.30 to
the Company's Annual Report on Form 10-K for the year ended December
31, 2002, File No. 1-13245).
10.30 - 5-Year Revolving Credit Agreement dated as of December 16, 2003,
among the Company, as the Borrower; JP Morgan Chase Bank as the
Administrative Agent; JP Morgan Chase Bank and Bank of America,
N.A., as the Issuing Banks; Wachovia Bank, National Association as
the Syndication Agent; Bank of America, N.A., Bank One, N.A., Fleet
National Bank and Wells Fargo Bank, National Association, as the
Co-Documentation Agents and certain other lenders (incorporated by
reference to Exhibit 10.1 to the Company's Quarterly Report on Form
10-Q for the period ended June 30, 2004, File No. 1-13245).
10.31 - First Amendment to 5-Year Revolving Credit Agreement dated as of
June 9, 2004 among the Company, as the Borrower; JP Morgan Chase
Bank as the Administrative Agent; JP Morgan Chase Bank and Bank of
America, N.A., as the Issuing Banks; Wachovia Bank, National
Association as the Syndication Agent; Bank of America, N.A., Bank
One, N.A., Fleet National Bank and Wells Fargo Bank, National
Association, as the Co-Documentation Agents and certain other
lenders (incorporated by reference to Exhibit 10.1 to the Company's
Quarterly Report on Form 10-Q for the period ended June 30, 2004,
File No. 1-13245).

119

Exhibit
Number Description

10.32 - 364-Day Credit Agreement dated as of September 28, 2004 among the
Company, as the Borrower; JP Morgan Chase Bank as the Administrative
Agent; Bank of America, N.A., Barclays Bank PLC, Wells Fargo Bank,
National Association and Wachovia Bank, National Association as the
Co-Documentation Agents and certain other lenders (incorporated by
reference to Exhibit 99.2 to the Company's Current Report on Form
8-K, File No. 1-13245, filed with the SEC on October 1, 2004).
10.33 - Non-Competition Agreement dated October 29, 2004, between the
Company and Mark S. Sexton (incorporated by reference to Exhibit
10.1 to the Company's Current Report on Form 8-K, File No. 1-13245,
filed with the SEC on November 4, 2004).
10.34 - Second Amendment to 5-Year Revolving Credit Agreement dated as of
January 21, 2005 among the Company, as the Borrower; JPMorgan Chase
Bank as the Administrative Agent; JPMorgan Chase Bank and Bank of
America, N.A., as the Issuing Banks; Wachovia Bank, National
Association as the Syndication Agent; Bank of America, N.A., Bank
One, N.A., Fleet National Bank and Wells Fargo Bank, National
Association, as the Co-Documentation Agents; J.P. Morgan Securities
Inc. and Wachovia Capital Markets, LLC, as the Co-Arrangers and
Joint Bookrunners; and certain other lenders (incorporated by
reference to Exhibit 99.1 to the Company's Current Report on Form
8-K, File No. 1-13245, filed with the SEC on January 27, 2005).
10.35 - First Amendment to 364-Day Credit Agreement dated as of January 21,
2005 among the Company, as the Borrower; JPMorgan Chase Bank as the
Administrative Agent; Bank of America, N.A., Barclays Bank PLC,
Wells Fargo Bank, National Association and Wachovia Bank, National
Association as the Co-Documentation Agents; J.P. Morgan Securities
Inc. as the Lead Arranger and Sole Bookrunner; and certain other
lenders (incorporated by reference to Exhibit 99.2 to the Company's
Current Report on Form 8-K, File No. 1-13245, filed with the SEC on
January 27, 2005).
10.36 - Production Payment Purchase and Sale Agreement dated as of January
26, 2005 among the Company, as the Seller, and Royalty Acquisition
Company, LLC, as the Buyer (related to Hugoton gas) (incorporated
by reference to Exhibit 99.2 to the Company's Current Report on
Form 8-K, File No. 1-13245, filed with the SEC on February 1, 2005).
10.37 - Production Payment Purchase and Sale Agreement dated as of January
26, 2005 among the Company, as the Seller, and Royalty Acquisition
Company, LLC, as the Buyer (related to Spraberry oil)(incorporated
by reference to Exhibit 99.3 to the Company's Current Report on Form
8-K, File No. 1-13245, filed with the SEC on February 1, 2005).
10.38H - 2000 Stock Incentive Plan of Evergreen Resources, Inc. (incorporated
by reference to Exhibit 4.4 to the Company's Registration Statement
on Form S-8, File No. 333-119355, filed with the SEC on September
29, 2004).
10.39H - Carbon Energy Corporation 1999 Stock Option Plan (incorporated by
reference to Exhibit 4.5 to the Company's Registration Statement on
Form S-8, File No. 333-119355, filed with the SEC on September 29,
2004).
10.40H - Evergreen Resources, Inc. Initial Stock Option Plan (incorporated
by reference to Exhibit 4.6 to the Company's Registration Statement
on Form S-8, File No. 333-119355, filed with the SEC on September
29, 2004).
14.1 - Code of Business Conduct and Ethics (incorporated by reference to
Annex D of the Company's Schedule 14A Definitive Proxy Statement,
File No. 1-13245, filed with the SEC on April 7, 2003).
21.1(a) - Subsidiaries of the registrant.
23.1(a) - Consent of Ernst & Young LLP.
23.2(a) - Consent of Netherland, Sewell & Associates, Inc.
31.1(a) - Chief Executive Officer certification under Section 302 of the
Sarbanes-Oxley Act of 2002.
31.2(a) - Chief Financial Officer certification under Section 302 of the
Sarbanes-Oxley Act of 2002.
32.1(b) - Chief Executive Officer certification under Section 906 of the
Sarbanes-Oxley Act of 2002.
32.2(b) - Chief Financial Officer certification under Section 906 of the
Sarbanes-Oxley Act of 2002.
- ---------------
(a) Filed herewith.
(b) Furnished herewith.

H Executive Compensation Plan or Arrangement previously filed pursuant to
Item 14(c).
G Executive Compensation Plan or Arrangement filed herewith pursuant to Item
14(c).

120

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this Report to be signed on
its behalf by the undersigned, thereunto duly authorized.

PIONEER NATURAL RESOURCES COMPANY

Date: February 16, 2005 By: /s/ Scott D. Sheffield
------------------------------------------
Scott D. Sheffield, Chairman of the Board,
Chief Executive Officer and Assistant
Secretary

Pursuant to the requirements of the Securities Exchange Act of 1934, this
Report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the dates indicated.

Signature Title Date
--------- ----- ----

/s/ Scott D. Sheffield Chairman of the Board, Chief Executive February 16, 2005
- ------------------------------
Scott D. Sheffield Officer and Assistant Secretary
(principal executive officer)

/s/ Richard P. Dealy Executive Vice President and Chief February 16, 2005
- ------------------------------
Richard P. Dealy Financial Officer
(principal financial officer)

/s/ Darin G. Holderness Vice President and Chief Accounting February 16, 2005
- ------------------------------
Darin G. Holderness Officer

/s/ James R. Baroffio Director February 16, 2005
- ------------------------------
James R. Baroffio

/s/ Edison C. Buchanan Director February 16, 2005
- ------------------------------
Edison C. Buchanan

/s/ R. Hartwell Gardner Director February 16, 2005
- ------------------------------
R. Hartwell Gardner

/s/ James L. Houghton Director February 16, 2005
- ------------------------------
James L. Houghton

/s/ Jerry P. Jones Director February 16, 2005
- ------------------------------
Jerry P. Jones

/s/ Linda K. Lawson Director February 16, 2005
- ------------------------------
Linda K. Lawson

/s/ Andrew D. Lundquist Director February 16, 2005
- ------------------------------
Andrew D. Lundquist

/s/ Charles E. Ramsey, Jr. Director February 16, 2005
- ------------------------------
Charles E. Ramsey, Jr.

/s/ Mark S. Sexton Director February 16, 2005
- ------------------------------
Mark S. Sexton

/s/ Robert A. Solberg Director February 16, 2005
- ------------------------------
Robert A. Solberg

/s/ Jim A. Watson Director February 16, 2005
- ------------------------------
Jim A. Watson

121

Exhibit Index

2.1 - Agreement and Plan of Merger, dated as of May 3, 2004, among the
Company, Evergreen and BC Merger Sub, Inc. (incorporated by
reference to Exhibit 2.1 to the Company's Current Report on Form
8-K, File No. 1-13245, filed with the SEC on May 5, 2004).
3.1 - Amended and Restated Certificate of Incorporation of the Company
(incorporated by reference to Exhibit 3.1 to the Company's
Registration Statement on Form S-4, dated June 27, 1997,
Registration No. 333-26951).
3.2 - Restated Bylaws of the Company (incorporated by reference to Exhibit
3.2 to the Company's Registration Statement on Form S-4, dated June
27, 1997, Registration No. 333-26951).
4.1 - Form of Certificate of Common Stock, par value $.01 per share, of
the Company (incorporated by reference to Exhibit 4.1 to the
Company's Registration Statement on Form S-4, dated June 27, 1997,
Registration No. 333-26951).
4.2 - Rights Agreement dated July 24, 2001, between the Company and
Continental Stock Transfer & Trust Company, as Rights Agent
(incorporated by reference to Exhibit 4.1 to the Company's
Registration Statement on Form 8-A, File No. 1-13245, filed with the
SEC on July 24, 2001).
4.3 - Certificate of Designation of Series A Junior Participating
Preferred Stock (incorporated by reference to Exhibit A to Exhibit
4.1 to the Company's Registration Statement on Form 8-A, File No.
1-13245, filed with the SEC on July 24, 2001).
4.4 - Indenture dated April 12, 1995, between Pioneer USA (successor to
Parker & Parsley Petroleum Company ("Parker & Parsley")) and The
Chase Manhattan Bank (National Association), as trustee
(incorporated by reference to Exhibit 4.1 to Parker & Parsley's
Current Report on Form 8-K, dated April 12, 1995, File No. 1-10695).
4.5 - First Supplemental Indenture dated as of August 7, 1997, among
Parker & Parsley, The Chase Manhattan Bank, as trustee, and Pioneer
USA, with respect to the indenture identified above as Exhibit 4.4
(incorporated by reference to Exhibit 10.5 to the Company's
Quarterly Report on Form 10-Q for the period ended September 30,
1997, File No. 1-13245).
4.6 - Second Supplemental Indenture dated as of December 30, 1997, among
Pioneer USA, Pioneer NewSub1, Inc. and The Chase Manhattan Bank, as
trustee, with respect to the indenture identified above as Exhibit
4.4 (incorporated by reference to Exhibit 10.17 to the Company's
Current Report on Form 8-K, File No. 1-13245, filed with the SEC on
January 2, 1998).
4.7 - Third Supplemental Indenture dated as of December 30, 1997, among
Pioneer NewSub1, Inc. (as successor to Pioneer USA), Pioneer DebtCo,
Inc. and The Chase Manhattan Bank, as trustee, with respect to the
indenture identified above as Exhibit 4.4 (incorporated by reference
to Exhibit 10.18 to the Company's Current Report on Form 8-K, File
No. 1-13245, filed with the SEC on January 2, 1998).
4.8 - Fourth Supplemental Indenture dated as of December 30, 1997, among
Pioneer DebtCo, Inc. (as successor to Pioneer NewSub1, Inc., as
successor to Pioneer USA), the Company, Pioneer USA and The Chase
Manhattan Bank, as trustee, with respect to the indenture identified
above as Exhibit 4.4 (incorporated by reference to Exhibit 10.19 to
the Company's Current Report on Form 8-K, File No. 1-13245, filed
with the SEC on January 2, 1998).
4.9 - Indenture dated January 13, 1998, between the Company and The Bank
of New York, as trustee (incorporated by reference to Exhibit 99.1
to the Company's and Pioneer USA's Current Report on Form 8-K, File
No. 1-13245, filed with the SEC on January 14, 1998).
4.10 - First Supplemental Indenture dated as of January 13, 1998, among the
Company, Pioneer USA, as the subsidiary guarantor, and The Bank of
New York, as trustee, with respect to the indenture identified above
as Exhibit 4.9 (incorporated by reference to Exhibit 99.2 to the
Company's and Pioneer USA's Current Report on Form 8-K, File No.
1-13245, filed with the SEC on January 14, 1998).

122

Exhibit Index

4.11 - Second Supplemental Indenture dated as of April 11, 2000, among the
Company, Pioneer USA, as the subsidiary guarantor, and The Bank of
New York, as trustee, with respect to the indenture identified above
as Exhibit 4.9 (incorporated by reference to Exhibit 10.1 to the
Company's Quarterly Report on Form 10-Q for the period ended March
31, 2000, File No. 1-13245).
4.12 - Third Supplemental Indenture dated as of April 30, 2002, among the
Company, Pioneer USA, as the subsidiary guarantor, and The Bank of
New York, as trustee, with respect to the indenture identified above
as Exhibit 4.9 (incorporated by reference to Exhibit 10.4 to the
Company's Quarterly Report on Form 10-Q for the three months ended
March 31, 2002, File No. 1-13245).
4.13 - Fourth Supplemental Indenture dated as of July 15, 2004, among the
Company and The Bank of New York, as trustee, with respect to the
indenture identified above as Exhibit 4.9 (incorporated by reference
to Exhibit 99.1 to the Company's Current Report on Form 8-K, File
No. 1-13245, filed with the SEC on July 19, 2004).
4.14 - Fifth Supplemental Indenture dated as of July 15, 2004, among the
Company, Pioneer USA, as the subsidiary guarantor, and The Bank of
New York, as trustee, with respect to the indenture identified above
as Exhibit 4.9 (incorporated by reference to Exhibit 99.2 to the
Company's Current Report on Form 8-K, File No. 1-13245, filed with
the SEC on July 19, 2004).
4.15 - Indenture dated as of March 10, 2004, among Evergreen and Wachovia
Bank, National Association, as trustee, relating to Evergreen's
5.875% Senior Subordinated Notes due 2012 (incorporated by reference
to Exhibit 4.1 to Evergreen's Quarterly Report on Form 10-Q for the
quarter ended March 31, 2004, File No. 1-13171, filed with the SEC
on May 10, 2004).
4.16 - Indenture dated as of December 18, 2001, among Evergreen and First
Union National Bank, as trustee, relating to Evergreen's 4.75%
Senior Convertible Notes due December 15, 2021 (incorporated by
reference to Exhibit 4.3 to Evergreen's Annual Report on Form 10-K
for the year ended December 31, 2001, File No. 1-13171, filed with
the SEC on March 11, 2002).
4.17 - First Supplemental Indenture dated as of September 28, 2004, among
Pioneer Evergreen Properties, LLC (as successor to Evergreen) and
Wachovia Bank, National Association, as trustee, with respect to the
indenture identified above as Exhibit 4.15 (incorporated by
reference to Exhibit 4.5 to the Company's Current Report on Form
8-K, File No. 1-13245, filed with the SEC on October 1, 2004).
4.18 - First Supplemental Indenture dated as of September 28, 2004, among
the Company, Evergreen and Wachovia Bank, National Association (as
successor to First Union National Bank), as trustee, with respect to
the indenture identified above as Exhibit 4.16 (incorporated by
reference to Exhibit 4.1 to the Company's Amendment to the Current
Report on Form 8-K/A, File No. 1-13245, filed with the SEC on
November 5, 2004).
4.19 - Second Supplemental Indenture dated as of September 28, 2004, among
the Company, Pioneer Evergreen Properties, LLC (as successor to
Evergreen) and Wachovia Bank, National Association (as successor to
First Union National Bank), as trustee, with respect to the
indenture identified above as Exhibit 4.16 (incorporated by
reference to Exhibit 4.7 to the Company's Current Report on Form
8-K, File No. 1-13245, filed with the SEC on October 1, 2004).
4.20 - Third Supplemental Indenture dated as of September 30, 2004, among
the Company, Pioneer Debt Sub, LLC and Wachovia Bank, National
Association (as successor to First Union National Bank), as trustee,
with respect to the indenture identified above as Exhibit 4.16
(incorporated by reference to Exhibit 4.1 to the Company's Current
Report on Form 8-K, File No. 1-13245, filed with the SEC on November
5, 2004).
4.21 - Fourth Supplemental Indenture dated as of September 30, 2004, among
the Company and Wachovia Bank, National Association (as successor to
First Union National Bank), as trustee, with respect to the
indenture identified above as Exhibit 4.16 (incorporated by
reference to Exhibit 4.2 to the Company's Current Report on Form
8-K, File No. 1-13245, filed with the SEC on November 5, 2004).

123

Exhibit Index

4.22 - Second Supplemental Indenture dated as of September 30, 2004, among
Pioneer Debt Sub, LLC and Wachovia Bank, National Association, as
trustee, with respect to the indenture identified above as Exhibit
4.15 (incorporated by reference to Exhibit 4.3 to the Company's
Current Report on Form 8-K, File No. 1-13245, filed with the SEC on
November 5, 2004).
4.23 - Third Supplemental Indenture dated as of September 30, 2004, among
the Company and Wachovia Bank, National Association, as trustee,
with respect to the indenture identified above as Exhibit 4.15
(incorporated by reference to Exhibit 4.15 to the Company's Current
Report on Form 8-K, File No. 1-13245, filed with the SEC on November
5, 2004).
4.24 - Fourth Supplemental Indenture dated as of November 1, 2004, among
the Company, Pioneer USA, as guarantor, and Wachovia Bank, National
Association, as trustee, with respect to the indenture identified
above as Exhibit 4.15 (incorporated by reference to Exhibit 4.5 to
the Company's Current Report on Form 8-K, File No. 1-13245, filed
with the SEC on November 5, 2004).
10.1H - 1991 Stock Option Plan of Mesa Inc. ("Mesa") (incorporated by
reference to Exhibit 10(v) to Mesa's Annual Report on Form 10-K for
the period ended December 31, 1991).
10.2H - 1996 Incentive Plan of Mesa (incorporated by reference to Exhibit
10.28 to the Company's Registration Statement on Form S-4, dated
June 27, 1997, Registration No. 333-26951).
10.3H - Parker & Parsley Long-Term Incentive Plan, dated February 19, 1991
(incorporated by reference to Exhibit 4.1 to Parker & Parsley's
Registration Statement on Form S-8, Registration No. 33-38971).
10.4H - First Amendment to the Parker & Parsley Long-Term Incentive Plan,
dated August 23, 1991 (incorporated by reference to Exhibit 10.2 to
Parker & Parsley's Registration Statement on Form S-1, dated
February 28, 1992, Registration No. 33-46082).
10.5H - The Company's Long-Term Incentive Plan (incorporated by reference
to Exhibit 4.1 to the Company's Registration Statement on Form S-8,
Registration No. 333-35087, filed with the SEC on September 8,
1997).
10.6H - First Amendment to the Company's Long-Term Incentive Plan,
effective as of November 23, 1998 (incorporated by reference to
Exhibit 10.72 to the Company's Annual Report on Form 10- K for the
period ended December 31, 1999, File No. 1-13245).
10.7H - Second Amendment to the Company's Long-Term Incentive Plan,
effective as of May 20, 1999 (incorporated by reference to Exhibit
10.73 to the Company's Annual Report on Form 10-K for the period
ended December 31, 1999, File No. 1-13245).
10.8H - Third Amendment to the Company's Long-Term Incentive Plan,
effective as of February 17, 2000 (incorporated by reference to
Exhibit 10.76 to the Company's Annual Report on Form 10- K for the
period ended December 31, 1999, File No. 1-13245).
10.9H - The Company's Employee Stock Purchase Plan (incorporated by
reference to Exhibit 4.1 to the Company's Registration Statement on
Form S-8, Registration No. 333-35165, filed with the SEC on
September 8, 1997).
10.10H - First Amendment to the Company's Employee Stock Purchase Plan,
dated December 9, 1998 (incorporated by reference to the Company's
Annual Report on Form 10-K for the year ended December 31, 1998,
File No. 1-13245).
10.11H - Second Amendment to the Company's Employee Stock Purchase Plan,
dated December 14, 1999 (incorporated by reference to Exhibit 10.74
to the Company's Annual Report on Form 10-K for the period ended
December 31, 1999, File No. 1-13245).
10.12H - The Company's Deferred Compensation Retirement Plan (incorporated
by reference to Exhibit 4.1 to the Company's Registration Statement
on Form S-8, Registration No. 333-39153, filed with the SEC on
October 31, 1997).

124

Exhibit Index

10.13H - Omnibus Amendment to Nonstatutory Stock Option Agreements, included
as part of the Parker & Parsley Long-Term Incentive Plan, dated as
of November 16, 1995, between Parker & Parsley and Named Executive
Officers identified on Schedule 1 setting forth additional details
relating to the Parker & Parsley Long-Term Incentive Plan
(incorporated by reference to Parker & Parsley's Annual Report on
Form 10-K for the year ended December 31, 1995, File No. 1-10695).
10.14H - Severance Agreement, dated as of August 8, 1997, between the Company
and Scott D. Sheffield, together with a schedule identifying
substantially identical agreements between the Company and each of
the other named executive officers identified on Schedule I for the
purpose of defining the payment of certain benefits upon the
termination of the officer's employment under certain circumstances
(incorporated by reference to Exhibit 10.7 to the Company's
Quarterly Report on Form 10-Q for the period ended September 30,
1997, File No. 1-13245).
10.15G - Amendment to Schedule I with respect to the Severance Agreement
identified above as Exhibit 10.14.
10.16G - Form of Severance Agreement, dated January 1, 2005, between the
Company and the Officer, together with a schedule identifying
substantially identical agreements between the Company and each of
the other named officers identified on Exhibit A for the purpose of
defining the payment of certain benefits upon the termination of the
officer's employment under certain circumstances.
10.17G - Severance Agreement, dated as of January 1, 2005, between the
Company and Kenneth H. Sheffield, Jr., for the purpose of defining
the payment of certain benefits upon the termination of the
officer's employment under certain circumstances.
10.18G - Severance Agreement, dated as of December 1, 2000, between the
Company and Chris J. Cheatwood, for the purpose of defining the
payment of certain benefits upon the termination of the officer's
employment under certain circumstances.
10.19G - Amendment to Severance Agreement, dated as of February 19, 2002,
between the Company and Chris J. Cheatwood, for the purpose of
redefining the payment of certain benefits upon the termination of
the officer's employment under certain circumstances with respect to
the Severance Agreement identified above as Exhibit 10.18.
10.20G - Severance Agreement, dated as of November 1, 2003, between the
Company and A. R. Alameddine, for the purpose of defining the
payment of certain benefits upon the termination of the officer's
employment under certain circumstances.
10.21G - Severance Agreement, dated as of December 1, 1999, between the
Company and Thomas C. Halbouty, for the purpose of defining the
payment of certain benefits upon the termination of the officer's
employment under certain circumstances.
10.22G - Severance Agreement, dated as of August 8, 1997, between the
Company and Larry N. Paulsen, for the purpose of defining the
payment of certain benefits upon the termination of the officer's
employment under certain circumstances.
10.23G - Amendment to August 8, 1997 Severance Agreement, dated as of
February 19, 2002, between the Company and Larry N. Paulsen, for the
purpose of redefining the payment of certain benefits upon the
termination of the officer's employment under certain circumstances
with respect to the Severance Agreement identified above as Exhibit
10.22.
10.24G - Severance Agreement, dated as of August 24, 1999, between the
Company and Danny Kellum, for the purpose of defining the payment of
certain benefits upon the termination of the officer's employment
under certain circumstances.
10.25G - Amendment to August 24, 1999 Severance Agreement, dated as of
February 19, 2002, between the Company and Danny L. Kellum, for the
purpose of redefining the payment of certain benefits upon the
termination of the officer's employment under certain circumstances
with respect to the Severance Agreement identified above as Exhibit
10.24.

125

Exhibit Index

10.26G - Severance Agreement, dated as of January 1, 2005, between the
Company and Todd A. Dillabough, for the purpose of defining the
payment of certain benefits upon the termination of the officer's
employment under certain circumstances.
10.27H - Indemnification Agreement, dated as of August 8, 1997, between the
Company and Scott D. Sheffield, together with a schedule identifying
substantially identical agreements between the Company and each of
the Company's other directors and named executive officers
identified on Schedule I (incorporated by reference to Exhibit 10.8
to the Company's Quarterly Report on Form 10-Q for the period ended
September 30, 1997, File No. 1-13245).
10.28G - Amendment to Schedule I with respect to the Indemnification
Agreement identified above as Exhibit 10.27.
10.29H - Pioneer USA 40l(k) and Matching Plan, Amended and Restated Effective
as of January 1, 2002 (incorporated by reference to Exhibit 10.30 to
the Company's Annual Report on Form 10-K for the year ended December
31, 2002, File No. 1-13245).
10.30 - 5-Year Revolving Credit Agreement dated as of December 16, 2003,
among the Company, as the Borrower; JP Morgan Chase Bank as the
Administrative Agent; JP Morgan Chase Bank and Bank of America,
N.A., as the Issuing Banks; Wachovia Bank, National Association as
the Syndication Agent; Bank of America, N.A., Bank One, N.A., Fleet
National Bank and Wells Fargo Bank, National Association, as the
Co-Documentation Agents and certain other lenders (incorporated by
reference to Exhibit 10.1 to the Company's Quarterly Report on Form
10-Q for the period ended June 30, 2004, File No. 1-13245).
10.31 - First Amendment to 5-Year Revolving Credit Agreement dated as of
June 9, 2004 among the Company, as the Borrower; JP Morgan Chase
Bank as the Administrative Agent; JP Morgan Chase Bank and Bank of
America, N.A., as the Issuing Banks; Wachovia Bank, National
Association as the Syndication Agent; Bank of America, N.A., Bank
One, N.A., Fleet National Bank and Wells Fargo Bank, National
Association, as the Co-Documentation Agents and certain other
lenders (incorporated by reference to Exhibit 10.1 to the Company's
Quarterly Report on Form 10-Q for the period ended June 30, 2004,
File No. 1-13245).
10.32 - 364-Day Credit Agreement dated as of September 28, 2004 among the
Company, as the Borrower; JP Morgan Chase Bank as the Administrative
Agent; Bank of America, N.A., Barclays Bank PLC, Wells Fargo Bank,
National Association and Wachovia Bank, National Association as the
Co-Documentation Agents and certain other lenders (incorporated by
reference to Exhibit 99.2 to the Company's Current Report on Form
8-K, File No. 1-13245, filed with the SEC on October 1, 2004).
10.33 - Non-Competition Agreement dated October 29, 2004, between the
Company and Mark S. Sexton (incorporated by reference to Exhibit
10.1 to the Company's Current Report on Form 8-K, File No. 1-13245,
filed with the SEC on November 4, 2004).
10.34 - Second Amendment to 5-Year Revolving Credit Agreement dated as of
January 21, 2005 among the Company, as the Borrower; JPMorgan Chase
Bank as the Administrative Agent; JPMorgan Chase Bank and Bank of
America, N.A., as the Issuing Banks; Wachovia Bank, National
Association as the Syndication Agent; Bank of America, N.A., Bank
One, N.A., Fleet National Bank and Wells Fargo Bank, National
Association, as the Co-Documentation Agents; J.P. Morgan Securities
Inc. and Wachovia Capital Markets, LLC, as the Co-Arrangers and
Joint Bookrunners; and certain other lenders (incorporated by
reference to Exhibit 99.1 to the Company's Current Report on Form
8-K, File No. 1-13245, filed with the SEC on January 27, 2005).

126

Exhibit Index

10.35 - First Amendment to 364-Day Credit Agreement dated as of January 21,
2005 among the Company, as the Borrower; JPMorgan Chase Bank as the
Administrative Agent; Bank of America, N.A., Barclays Bank PLC,
Wells Fargo Bank, National Association and Wachovia Bank, National
Association as the Co-Documentation Agents; J.P. Morgan Securities
Inc. as the Lead Arranger and Sole Bookrunner; and certain other
lenders (incorporated by reference to Exhibit 99.2 to the Company's
Current Report on Form 8-K, File No. 1-13245, filed with the SEC on
January 27, 2005).
10.36 - Production Payment Purchase and Sale Agreement dated as of January
26, 2005 among the Company, as the Seller, and Royalty Acquisition
Company, LLC, as the Buyer (related to Hugoton gas) (incorporated by
reference to Exhibit 99.2 to the Company's Current Report on Form
8-K, File No. 1-13245, filed with the SEC on February 1, 2005).
10.37 - Production Payment Purchase and Sale Agreement dated as of January
26, 2005 among the Company, as the Seller, and Royalty Acquisition
Company, LLC, as the Buyer (related to Spraberry oil)(incorporated
by reference to Exhibit 99.3 to the Company's Current Report on
Form 8-K, File No. 1-13245, filed with the SEC on February 1, 2005).
10.38H - 2000 Stock Incentive Plan of Evergreen Resources, Inc.
(incorporated by reference to Exhibit 4.4 to the Company's
Registration Statement on Form S-8, File No. 333-119355, filed with
the SEC on September 29, 2004).
10.39H - Carbon Energy Corporation 1999 Stock Option Plan (incorporated by
reference to Exhibit 4.5 to the Company's Registration Statement on
Form S-8, File No. 333-119355, filed with the SEC on September 29,
2004).
10.40H - Evergreen Resources, Inc. Initial Stock Option Plan (incorporated
by reference to Exhibit 4.6 to the Company's Registration Statement
on Form S-8, File No. 333-119355, filed with the SEC on September
29, 2004).
14.1 - Code of Business Conduct and Ethics (incorporated by reference to
Annex D of the Company's Schedule 14A Definitive Proxy Statement,
File No. 1-13245, filed with the SEC on April 7, 2003).
21.1(a) - Subsidiaries of the registrant.
23.1(a) - Consent of Ernst & Young LLP.
23.2(a) - Consent of Netherland, Sewell & Associates, Inc.
31.1(a) - Chief Executive Officer certification under Section 302 of the
Sarbanes-Oxley Act of 2002.
31.2(a) - Chief Financial Officer certification under Section 302 of the
Sarbanes-Oxley Act of 2002.
32.1(b) - Chief Executive Officer certification under Section 906 of the
Sarbanes-Oxley Act of 2002.
32.2(b) - Chief Financial Officer certification under Section 906 of the
Sarbanes-Oxley Act of 2002.

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(a) Filed herewith.
(b) Furnished herewith.

H Executive Compensation Plan or Arrangement previously filed pursuant to
Item 14(c).
G Executive Compensation Plan or Arrangement filed herewith pursuant to Item
14(c).

127