Edgar Filing: PIONEER NATURAL RESOURCES CO

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, 2006
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 incorporation or (I.R.S. Employer
organization) Identification No.)
5205 N. O'Connor Blvd., Suite 200, 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:

Title of each class Name of each exchange on which registered
------------------- -----------------------------------------
Common Stock................... New York Stock Exchange

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

Indicate by check mark if the registrant is a well-known seasoned issuer, as
defined in Rule 405 of the Securities Act. Yes x No
----- -----

Indicate by check mark if the registrant is not required to file reports
pursuant to Section 13 or Section 15(d) of the Act. Yes No x
----- -----

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 a large accelerated filer, an
accelerated filer or a non-accelerated filer. See definition of "accelerated
filer and large accelerated filer" in Rule 12b-2 of the Exchange Act. (Check
one):

Large accelerated filer x Accelerated filer Non-accelerated filer
---- ---- ----

Indicate by check mark whether the registrant is a shell company (as defined in
Rule 12b-2 of the Act). Yes No x
---- ----

Aggregate market value of the voting and non-voting common
equity held by non-affiliates computed by reference to the
price at which the common equity was last sold, or the
average bid and asked price of such common equity, as of the
last business day of the registrant's most recently completed
second fiscal quarter............................................ $5,732,341,639
Number of shares of Common Stock outstanding as of
February 13, 2007................................................ 123,502,029

Documents Incorporated by Reference:

(1) Proxy Statement for Annual Meeting of Shareholders to be held during May
2007 -- Referenced in Part III of this report.

TABLE OF CONTENTS

Page
Cautionary Statement Concerning Forward-Looking Statements........... 3
Definitions of Certain Terms and Conventions Used Herein............. 4

PART I

Item 1. Business................................................... 5
General................................................. 5
Available Information................................... 5
Mission and Strategies.................................. 5
Business Activities..................................... 6
Operations by Geographic Area........................... 8
Marketing of Production................................. 8
Competition, Markets and Regulations.................... 8
Item 1A. Risk Factors............................................... 10
Item 1B. Unresolved Staff Comments.................................. 15
Item 2. Properties................................................. 15
Proved Reserves......................................... 16
Description of Properties............................... 18
Selected Oil and Gas Information........................ 25
Item 3. Legal Proceedings.......................................... 32
Item 4. Submission of Matters to a Vote of Security Holders........ 32

PART II

Item 5. Market for Registrant's Common Equity, Related Stockholder
Matters and Issuer Purchases of Equity Securities.......... 33
Purchases of Equity Securities by the Issuer and
Affiliated Purchasers................................... 33
Item 6. Selected Financial Data.................................... 34
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations of Operations.................... 36
Strategic Initiatives and Goals......................... 36
Financial and Operating Performance..................... 36
2007 Outlook and Activities............................. 37
Acquisitions............................................ 38
Divestitures............................................ 38
Results of Operations................................... 39
Capital Commitments, Capital Resources and Liquidity.... 47
Critical Accounting Estimates........................... 52
New Accounting Pronouncements........................... 55
Item 7A. Quantitative and Qualitative Disclosures About Market Risk. 56
Quantitative Disclosures................................ 56
Qualitative Disclosures................................. 60
Item 8. Financial Statements and Supplementary Data................ 63
Index to Consolidated Financial Statements.............. 63
Report of Independent Registered Public Accounting Firm. 64
Consolidated Financial Statements....................... 65
Notes to Consolidated Financial Statements.............. 71
Unaudited Supplementary Information..................... 109
Item 9. Changes in and Disagreements With Accountants on Accounting
and Financial Disclosure................................... 115
Item 9A. Controls and Procedures.................................... 115

Item 9B. Other Information.......................................... 117
PART III

Item 10. Directors, Executive Officers and Corporate Governance..... 117
Item 11. Executive Compensation..................................... 117
Item 12. Security Ownership of Certain Beneficial Owners and
Management and Related Stockholder Matters................. 117
Item 13. Certain Relationships and Related Transactions, and
Director Independence...................................... 118
Item 14. Principal Accounting Fees and Services..................... 118

PART IV

Item 15. Exhibits, Financial Statement Schedules.................... 119
Signatures....................................................... 125
Exhibit Index.................................................... 126

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. When used in
this document, the words "believes," "plans," "expects," "anticipates,"
"intends," "continue," "may," "will," "could," "should," "future," "potential,"
"estimate," or the negative of such terms and similar expressions as they relate
to Pioneer Natural Resources Company ("Pioneer" or the "Company") or its
management are intended to identify forward-looking statements. The
forward-looking statements are based on the Company's current expectations,
assumptions, estimates and projections about the Company and the industry in
which the Company operates. Although the Company believes that the expectations
and assumptions reflected in the forward-looking statements are reasonable, they
involve risks and uncertainties that are difficult to predict and, in many
cases, beyond the Company's control. 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", "Item 1A. Risk Factors" and
"Item 7A. Quantitative and Qualitative Disclosures About Market Risk" for a
description of various factors that could materially affect the ability of
Pioneer to achieve the anticipated results described in the forward-looking
statements. The Company undertakes no duty to publicly update these statements
except as required by law.

Definitions of Certain Terms and Conventions Used Herein

Within this Report, the following 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 natural gas liquid.
o "BOEPD" means BOE per day.
o "Btu" means British thermal unit, which is a measure of the amount of
energy required to raise the temperature of one pound of water one degree
Fahrenheit.
o "CBM" means coal bed methane.
o "field fuel" means gas consumed to operate field equipment (primarily
compressors) prior to the gas being delivered to a sales point.
o "GAAP" means accounting principles that are generally accepted in the
United States of America.
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 "Mcf" means one thousand cubic feet and is a measure of natural gas volume.
o "MMBbl" means one million Bbls.
o "MMBOE" means one million BOEs.
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 "VPP" means volumetric production payment.
o "U.S." means United States.
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.

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 current operations in the United States, Canada,
Equatorial Guinea, Nigeria, South Africa and Tunisia.

The Company's executive offices are located at 5205 N. O'Connor Blvd.,
Suite 200, Irving, Texas 75039. The Company's telephone number is (972)
444-9001. The Company maintains other offices in Anchorage, Alaska; Denver,
Colorado; Midland, Texas; Calgary, Canada; London, England; Lagos, Nigeria;
Capetown, South Africa and Tunis, Tunisia. At December 31, 2006, the Company had
1,624 employees, 924 of whom were employed in field and plant operations.

Available Information

Pioneer files or furnishes annual, quarterly and current reports, proxy
statements and other documents with the SEC under the Securities Exchange Act of
1934 (the "Exchange Act"). The public may read and copy any materials that
Pioneer files with the SEC at the SEC's Public Reference Room at 100 F Street,
N.E., 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 through its internet
website (www.pxd.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.

Mission and Strategies

The Company's mission is to enhance shareholder 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. These strategies are
anchored by the Company's long-lived Spraberry oil field and Hugoton, Raton and
West Panhandle gas fields which have an estimated remaining productive life in
excess of 40 years. Underlying these fields are approximately 89 percent of the
Company's proved oil and gas reserves as of December 31, 2006.

Strategic initiatives and goals. During 2006, the Company accomplished
significant goals underlying the strategic initiatives established in 2005 to
enhance shareholder value and investment returns. Specifically, the Company (i)
essentially completed its $1 billion share repurchase program, (ii) successfully
divested its deepwater Gulf of Mexico and Argentina assets at attractive
valuations, (iii) allocated and focused its investment capital more heavily
towards predictable oil and gas basins in North America that delivered strong
production growth and (iv) lowered its risk profile by expanding North American
unconventional resource investments while reducing higher-risk exploration
expenditures.

2007 Plans. During 2007, the Company plans to: (i) grow production by 10
percent or more, anchored by continued low-risk development drilling in the
Spraberry oil and Raton gas fields, (ii) commence production at the South Coast
Gas project in South Africa in the second half of 2007, (iii) complete the
construction and installation of facilities at the Company's Alaskan Oooguruk
project and initiate drilling in late 2007, with first production in 2008, (iv)
progress development of the Tunisian and Edwards Trend resource plays into
production and reserve growth areas, (v) advance several other unconventional
resource plays initiated during 2006, (vi) selectively explore for and develop
proved reserves in areas that it believes will offer superior reserve growth and
profitability potential; (vii) evaluate opportunities to acquire oil and gas
properties that will complement the Company's exploration and development

drilling activities; (viii) invest in the personnel and technology necessary to
maximize the Company's exploration and development successes; and (ix) maintain
liquidity, allowing the Company to take advantage of future exploration,
development and acquisition opportunities.

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 quality differences, 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 by employing experienced
management and staff that will lead the Company to prudent capital investment
decisions, technological innovation and price and cost management.

Petroleum industry. For the last several years the petroleum industry has
generally been characterized by volatile oil, NGL and gas commodity prices.
During 2006, the Company's performance was also impacted by increasing costs,
particularly higher drilling and well servicing rig rates and drilling supplies.
During recent years, world oil prices increased in response to increases in
demand from Asian economies and the perceived threat of supply disruptions in
the Middle East, Nigeria, Venezuela and other areas. In 2006, oil prices
initially increased due to supply uncertainty surrounding Middle East conflicts
and then later decreased on moderating world demand and the easing of world
tension, especially in the Middle East. North American gas prices fell in 2006
as a result of increased North American drilling and production, a very mild
start to winter and a very large gas inventory overhang. Significant factors
that will impact 2007 commodity prices include developments in the issues
currently impacting Iraq and Iran 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,
including the impact of increasing liquefied natural gas ("LNG") deliveries to
the United States.

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 J 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 2006, 2005 and 2004 from the Company's hedging activities and
the Company's open hedge positions at December 31, 2006.

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 Alaska, and
internationally in Canada, Equatorial Guinea, Nigeria, 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, lower-risk exploration and
development opportunities and a limited number of higher-impact exploration
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, legal, 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, Utah and the Gulf of Mexico,
and internationally in 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
year ended December 31, 2006, the Company's average daily production, on a BOE
basis, decreased as a result of (i) initiation of oil deliveries in January 2006
associated with certain VPP transactions completed in 2005, which reduced the
Company's reported production and (ii) production decreases in the Company's

Sable oil field in South Africa and the Adam Concession oil field in Tunisia.
Partially offsetting the decreases in production volumes were increases in oil
production in the Spraberry field and gas production from the Raton field and
Canada as part of the Company's aggressive 2006 drilling program. Excluding the
delivery of the VPP volumes in 2006 (5.6 MMBOE) and 2005 (2.5 MMBOE), the
Company's North American production increased approximately nine percent, which
the Company believes provides a better understanding of the actual results of
the Company's 2006 North American drilling program excluding the increased
scheduled VPP deliveries. Production, price and cost information with respect to
the Company's properties for 2006, 2005 and 2004 is set forth under "Item 2.
Properties -- Selected Oil and Gas Information -- Production, Price and Cost
Data".

Development activities. The Company seeks to increase its oil and gas
reserves, production and cash flow through development drilling and by
conducting other production enhancement activities, such as well recompletions.
During the three years ended December 31, 2006, the Company drilled 2,346 gross
(2,159 net) wells, 94 percent of which were successfully completed as productive
wells, at a total drilling cost (net to the Company's interest) of $3.0 billion.

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, 2006 include proved undeveloped
reserves and proved developed reserves that are behind pipe of 202 MMBbls of oil
and NGLs and 1,082 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 a portfolio of lower-risk exploration opportunities complemented by a
limited number of higher-impact exploration opportunities. During 2006, the
Company divested substantially all of its assets in the deepwater Gulf of Mexico
and Argentina and focused its exploration efforts towards lower-risk onshore
North America and Africa opportunities. In the 2007 capital spending budget, the
Company expects to spend approximately 20 percent of its $1.1 billion capital
budget to test and develop lower-risk resource plays in onshore North America
and Tunisia, and another five percent for high-impact exploration in the U.S.
(principally Alaska) and West Africa. 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 1A. Risk Factors
-- 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 2006, 2005 and 2004, the
Company invested $223.2 million, $272.9 million and $2.6 billion, respectively,
of acquisition capital to purchase proved oil and gas 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 2006,
2005 and 2004.

The Company periodically evaluates and pursues acquisition opportunities
(including opportunities to acquire particular oil and gas assets and entities
owning oil and gas 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. The success of any acquisition is uncertain and will depend on a
number of factors, some of which are outside the Company's control. See "Item
1A. Risk Factors -- Acquisitions".

Asset divestitures. The Company regularly reviews its asset base for the
purpose of identifying nonstrategic 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. See Notes N, T and V of Notes
to Consolidated Financial Statements included in "Item 8. Financial Statements
and Supplementary Data" for specific information regarding the Company's asset
divestitures, VPPs and discontinued operations during 2006, 2005 and 2004.

The Company anticipates that it will continue to sell nonstrategic
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, that being oil and gas
exploration and production. See Note R 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. See "Qualitative
Disclosures" in "Item 7A. Quantitative and Qualitative Disclosures About Market
Risk" for additional discussion of operations and price risk.

Significant purchasers. During 2006, the Company's significant purchasers
of oil, NGLs and gas were Oneok Resources (12 percent), Plains Marketing LP (12
percent) and Occidental Energy Marketing, Inc. (11 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.

Competition, Markets and Regulations

Competition. The oil and gas industry is highly competitive. A large number
of companies, including major integrated and other independent 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, evaluate and purchase such properties and the financial resources
necessary to acquire and develop the properties. Higher recent commodity prices
have increased the cost of properties available for acquisition. 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 and the
NYSE. 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 information included in submissions to the SEC do not
contain any untrue statement of a material fact or omit to state a material fact
necessary to make the statements made in such submissions not misleading.
Compliance with some of these regulations is costly and regulations are subject
to change or reinterpretation.

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 also generally impose a production or severance tax with respect to
the 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 the United States 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 U.S. federal, state and local, as well as foreign laws and regulations
governing the discharge of substances into the environment or otherwise 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 or impose substantial liabilities for pollution
resulting from oil and gas operations. The Company's inability to obtain these
permits in a timely manner or at all could cause delays or otherwise negatively
impact the Company's ability to implement its business plans. Failure to comply
with these environmental laws and regulations may result in the assessment of
administrative, civil, and criminal penalties, the imposition of remedial
obligations, and the issuance of injunctions that limit or prevent operations.
Although the Company believes that compliance with U.S. and foreign
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 are inherent in oil and gas operations, and there can be
no assurance that significant costs and liabilities will not be incurred or that
curtailment in production or processing might not arise as a result of such
compliance. 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.

In the U.S., 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, strict 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 in the U.S., including hazardous wastes, that
are subject to the federal Resource Conservation and Recovery Act ("RCRA") and
comparable state statutes. The U.S. Environmental Protection Agency and various
state agencies have limited the approved methods of disposal for certain

hazardous and nonhazardous 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 in the U.S. 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 hydrocarbons or wastes have been taken for recycling or 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 hydrocarbons or wastes disposed
thereon may be subject to CERCLA, RCRA and analogous state 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 of the U.S. 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
pipes and 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 Company believes the regulation of NORM has minimal effect on its
operations because the Company generates only small quantities of NORM on an
annual basis.

The Company's field operations in the U.S. involve the use of gas-fired
compressors, which are subject to the federal Clean Air Act and analogous state
laws governing the control and permitting of air emissions. The Company believes
that it is in compliance with applicable permitting and control technology
requirements of such laws and regulations; however, in the future, additional
facilities could become subject to additional permitting, monitoring and
pollution control requirements as compressor facilities are expanded.

The Company's operations outside of the U.S. are generally subject to
similar foreign governmental controls relating to protection of the environment.
The Company believes that compliance with the existing requirements of these
foreign governmental bodies has not had a material adverse effect on the
Company's operations.

ITEM 1A. RISK FACTORS

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. Other risks are described
in "Item 1. Business -- Competition, Markets and Regulations" and "Item 7A.
Quantitative and Qualitative Disclosures About Market Risk". These risks are not
the only risks facing the Company. The Company's business could also be impacted

by additional risks and uncertainties not currently known to the Company or that
it currently deems to be immaterial. If any of these risks actually occur, they
could materially harm the Company's business, financial condition or results of
operations and impair Pioneer's ability to implement business plans or complete
development projects as scheduled. In that case, the market price of the
Company's common stock could decline.

Commodity prices. The Company's revenues, profitability, cash flow and
future rate of growth are highly dependent on oil and gas prices. These prices
are affected by the supply of and market for oil and gas and numerous other
factors beyond the Company's control. Historically, oil and gas prices 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 in the Company's
deferred tax asset valuation allowance, depending on the Company's tax
attributes in each country in which it has activities. The Company makes price
assumptions that are used for planning purposes, and a significant portion of
the Company's operating expenses, including rent, salaries and noncancellable
capital commitments, is largely fixed in nature. Accordingly, if commodity
prices are below expectations, the Company's financial results are likely to be
adversely and disproportionately affected because these expenses are not
variable in the short term and cannot be quickly reduced to respond to
unanticipated decreases in commodity prices.

Hedging activities. To reduce our exposure to fluctuations in oil and gas
prices, we have entered into, and expect in the future to enter into, hedging
arrangements for a portion of our oil and gas production. These hedging
arrangements may expose us to risk of financial loss in certain circumstances,
including when:

o production is less than the hedged volumes,
o the counterparty to the hedging contract defaults on their contract
obligations, or
o the hedging arrangements limit the benefit the Company would otherwise
receive from increases in oil and gas prices.

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. The Company expects that it will
continue to experience exploration and abandonment expense in 2007, although
only five percent of the Company's 2007 capital budget is devoted to higher-risk
exploratory projects. Increased levels of drilling activity in the oil and gas
industry in recent periods have led to reduced availability, extended delivery
times and increased costs of some drilling equipment, materials and supplies.
The Company expects that these trends will continue in the foreseeable future
and, if so, they may impact the Company's profitability, cash flow and ability
to complete development projects as scheduled.

Unproved properties. At December 31, 2006, the Company carried unproved
property costs of $210.3 million. GAAP requires 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 the assessment of 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. As
a result, among other risks, the Company's initial estimates of reserves may be
subject to revision following acquisition, materially and adversely impacting
the desired benefits of the acquisition.

Divestitures. The Company regularly reviews its property base for the
purpose of identifying nonstrategic assets, the disposition of which would
increase capital resources available for other activities and create
organizational and operational efficiencies. Various factors could materially
affect the ability of the Company to dispose of nonstrategic assets, including
the availability of purchasers willing to purchase the nonstrategic assets at
prices acceptable to the Company. Sellers typically retain certain liabilities
or indemnify buyers for certain matters. The magnitude of any such retained
liability or indemnification obligation may be difficult to quantify at the time
of the tnrasction and ultimately may be material.

Goodwill. At December 31, 2006, the Company carried goodwill of $309.9
million associated with its United States reporting unit. Goodwill is tested for
impairment at least annually, requiring an estimate of the fair values of the
Company's assets and liabilities. If the fair value of the Company's net assets
is not sufficient to fully support the goodwill balance, the Company will
recognize noncash charges in the earnings of future periods.

Operation of gas processing plants. As of December 31, 2006, the Company
owned interests in seven gas processing plants and seven treating facilities.
The Company operates five of the plants and all seven treating facilities. There
are significant risks associated with the operation of 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. For example, in May
2005, the Company's Fain gas plant was shut in for two months due to a
mechanical failure that resulted in a fire.

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. Increased hurricane activity in 2005 and 2004 resulted in production
curtailments and physical damage to the Company's Gulf of Mexico 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 the risks
described in this paragraph, either because such insurance is not available or
because of the high premium costs and deductibles associated with obtaining such
insurance. Additionally, the Company relies to a large extent on facilities
owned and operated by third-parties, and damage to or destruction of those
third-party facilities could affect the ability of the Company to produce,
transport and sell its hydrocarbons.

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 substances or gases that could expose the Company to substantial
liability due to pollution and other environmental damage. A variety of United
States federal, state and local, as well as 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 administrative, civil or
criminal penalties, remedial cleanups, and natural resource damages or other
liabilities, and compliance with these laws and regulations 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 activities, result in a
material increase in the costs of production, development, exploration or
processing operations or adversely affect the Company's future operations and
financial condition. Pollution and similar environmental risks generally are not
fully insurable.

Impact of Weather and Climate. Demand for oil and natural gas are, to a
significant degree, dependent on weather and climate, which impacts the price

the Company receives for its production. In addition the Company's production,
exploration and development activities and equipment can be adversely affected
by severe weather, which may cause a loss of production from temporary cessation
of activity or lost or damaged equipment, or unseasonal climate, which may delay
or otherwise disrupt drilling and production schedules. Not all such effects can
be predicted, eliminated or insured against.

Debt restrictions and availability. The Company is a borrower under fixed
rate senior notes and a variable rate credit facility. The terms of the
Company's borrowings under the senior notes and the credit facility 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 and interest rates. 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, 2006 and the terms associated therewith.

The Company's ability to obtain additional financing is also impacted by
the Company's debt credit ratings and competition for available debt financing.
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.

Key personnel. Our business depends to a significant extent upon the
continued service and performance of a relatively small number of key senior
managers and technical personnel. The loss of any existing key personnel, or the
inability to attract, motivate and retain additional key personnel, could harm
our business, financial condition and results of operations.

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, 2006, approximately five percent
of the Company's proved reserves of oil, NGLs and gas were located outside the
United States (three percent in Canada and two 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. In some
cases, the market for the Company's production in foreign countries is limited
to some extent. For example, all of the Company's gas and condensate production
from the South Coast Gas project is currently committed by contract to a single,
government-affiliated gas-to-liquids facility. If such facility ceased to
purchase the gas because of an unforeseen event excusing performance, it might
be difficult to find an alternative market for the production, and if such a
market were secured, the price received by the Company might be less than that
provided under its current gas sales contract. See "Critical Accounting
Estimates" included in "Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations", "Qualitative Disclosures -
Foreign currency, operations and price risk" 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 regarding other risks associated with the Company's
international operations.

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 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 sales 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 differences may be material.

As required by the SEC, the estimated discounted future net cash flows from
proved reserves are 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 increases or decreases in the supply of or demand for oil and gas and

o changes in governmental regulations or taxation.

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 prices, as well as operating and
development costs, 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, nor may it reflect the actual costs that will be required to
produce or develop the oil and gas properties. 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.

Production forecasts. From time to time the Company provides forecasts of
expected quantities of future oil and gas production. These forecasts are based
on a number of estimates, including expectations of production decline rates
from existing wells and the outcome of future drilling activity. Should these
estimates prove inaccurate, actual production could be adversely impacted.
Downturns in commodity prices could make certain drilling activities or
production uneconomical, which would also adversely impact production.

Stock repurchases. The Board of Directors (the "Board") approves share
repurchase programs and sets limits on the price per share at which Pioneer's
common stock can be repurchased. The Company is not permitted to repurchase its
stock during certain periods because of scheduled and unscheduled trading
blackouts. Additionally, business conditions and availability of capital may
dictate that repurchases be suspended or canceled. As a result, there can be no
assurance that additional repurchases will be commenced and, if so, that they
will be completed.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

The information included in this Report about the Company's proved reserves
as of December 31, 2006, 2005 and 2004, which were located in the United States,
Argentina, Canada, South Africa and Tunisia, were based on evaluations prepared
by the Company's engineers and audited by Netherland, Sewell & Associates, Inc.
("NSAI") with respect to the Company's major properties and prepared by the
Company's engineers with respect to all other properties. The reserve audits
performed by NSAI in aggregate represented 89 percent, 82 percent and 88 percent
of the Company's 2006, 2005 and 2004 proved reserves, respectively; and, 83
percent, 76 percent and 84 percent of the Company's 2006, 2005 and 2004
associated pre-tax present value of proved reserves discounted at ten percent,
respectively.

NSAI follows the general principles set forth in the standards pertaining
to the estimating and auditing of oil and gas reserve information promulgated by
the Society of Petroleum Engineers ("SPE"). A reserve audit as defined by the
SPE is not the same as a financial audit. The SPE's definition of a reserve
audit includes the following concepts:

o A reserve audit is an examination of reserve information that is
conducted for the purpose of expressing an opinion as to whether such
reserve information, in the aggregate, is reasonable and has been
presented in conformity with generally accepted petroleum engineering
and evaluation principles.

o The estimation of proved reserves is an imprecise science due to the
many unknown geologic and reservoir factors that cannot be estimated
through sampling techniques. Since reserves are only estimates, they
cannot be audited for the purpose of verifying exactness. Instead,
reserve information is audited for the purpose of reviewing in
sufficient detail the policies, procedures and methods used by a
company in estimating its reserves so that the reserve auditors may
express an opinion as to whether, in the aggregate, the reserve
information furnished by a company is reasonable and has been
estimated and presented in conformity with generally accepted
petroleum engineering and evaluation principles.

o The methods and procedures used by a company, and the reserve
information furnished by a company, must be reviewed in sufficient
detail to permit the reserve auditor, in its professional judgment,
to express an opinion as to the reasonableness of the reserve
information. The auditing procedures require the reserve auditor to
prepare its own estimates of reserve information for the audited
properties.

To further clarify, in conjunction with the audits of the Company's proved
reserves and associated pre-tax present value discounted at ten percent, the
Company provided to NSAI its external and internal engineering and geoscience
technical data and analyses. Following NSAI's review of that data, it had the
option of honoring the Company's interpretation, or making its own
interpretation. No data was withheld from NSAI. NSAI accepted without

independent verification the accuracy and completeness of the historical
information and data furnished by the Company with respect to ownership
interest; oil and gas production; well test data; oil, NGL and gas prices;
operating and development costs; and any agreements relating to current and
future operations of the properties and sales of production. However, if in the
course of its evaluation something came to its attention that brought into
question the validity or sufficiency of any such information or data, NSAI did
not rely on such information or data until it had satisfactorily resolved its
questions relating thereto or had independently verified such information or
data.

In the course of its evaluations, NSAI prepared, for all of the audited
properties, its own estimates of the Company's proved reserves and pre-tax
present value of such reserves discounted at ten percent. NSAI's estimates of
those proved reserves and pre-tax present value of such reserves discounted at
ten percent did not differ from the Company's estimates by more than ten percent
in the aggregate. However, when compared on a field-by-field or area-by-area
basis, some of the Company's estimates were greater than those of NSAI and some
were less than the estimates of NSAI. When such differences did not exceed ten
percent in the aggregate and NSAI was satisfied that the proved reserves and
pre-tax present value of such reserves discounted at ten percent were reasonable
and that its audit objectives had been met, NSAI issued a completed unqualified
audit opinion. Remaining differences were not resolved due to the limited cost
benefit of continuing such analyses by the Company and NSAI. At the conclusion
of the audit process, it was NSAI's opinion, as set forth in its audit letters,
that Pioneer's estimates of the Company's proved oil and gas reserves and
associated pre-tax future net revenues discounted at ten percent are, in the
aggregate, reasonable and have been prepared in accordance with generally
accepted petroleum engineering and evaluation principles.

The Company did not provide estimates of total proved oil and gas reserves
during 2006, 2005 or 2004 to any federal authority or agency, other than the
SEC. The Company's reserve estimates do not include any probable or possible
reserves. Also, see "Item 1A. Risk Factors" and "Critical Accounting Estimates"
in "Item 7. Management's Discussion and Analysis and Results of Operations" for
additional discussions regarding proved reserves and their related cash flows.

Proved Reserves

The Company's proved reserves totaled 904.9 MMBOE, 986.7 MMBOE and 1.0
billion BOE at December 31, 2006, 2005 and 2004, respectively, representing $4.7
billion, $7.3 billion and $6.6 billion, respectively, of Standardized Measure.
The Company's proved reserves include field fuel, which is gas consumed to
operate field equipment (primarily compressors) prior to the gas being delivered
to a sales point. The following table shows the changes in the Company's proved
reserve volumes by geographic area during the year ended December 31, 2006 (in
MBOE):

Purchases of Sales of Revisions of
Extensions and Minerals-in Minerals-in- Previous
Production Discoveries Place Place Estimates
---------- -------------- ----------- ------------ ------------

United States..... (36,499) 34,733 50,543 (29,395) (9,244)
Argentina......... (3,743) 898 -- (97,920) (646)
Canada............ (2,924) 11,351 -- -- (1,485)
South Africa...... (1,506) -- -- -- 1,541
Tunisia........... (943) 1,870 -- -- 1,588
------- ------- ------- --------- --------
Total............. (45,615) 48,852 50,543 (127,315) (8,246)
======= ======= ======= ========= ========

Production. Production volumes include 2,894 MBOE of field fuel and 6,811
MBOE of production associated with divested assets being presented as
discontinued operations.

Extensions and discoveries. Extensions and discoveries are primarily the
result of extension drilling in the Raton field and Spraberry field in the
United States and the Horseshoe Canyon field in Canada and lower-risk
exploratory drilling in the Company's South Texas Edwards Trend and Tunisian
resource plays.

Purchases of minerals-in-place. Purchases of minerals-in-place are
primarily attributable to bolt-on acquisitions and joint venture activities in
the Company's Spraberry field and Edwards Trend area.

Sales of minerals-in-place. Sales of minerals-in-place are principally
related to the Company's divestiture of its deepwater Gulf of Mexico and
Argentine assets during 2006. See Note N of Notes to Consolidated Financial
Statements included in "Item 8. Financial Statements and Supplementary Data".

Revisions of previous estimates. Revisions of previous estimates are
comprised of 14 MMBOE of negative price revisions offset by 6 MMBOE of positive
technical revisions. The Company's proved reserves at December 31, 2006 were
determined using year-end NYMEX equivalent prices of $60.82 per barrel of oil
and $5.64 per Mcf of gas, compared to $61.04 per barrel of oil and $10.08 per
Mcf of gas at December 31, 2005. The lower gas prices at December 31, 2006
decreased the economic life on certain gas properties, the majority of which
were in the Raton gas field.

On a BOE basis, 60 percent of the Company's total proved reserves at
December 31, 2006 were proved developed reserves. Based on reserve information
as of December 31, 2006, and using the Company's production information for the
year then ended, excluding production associated with divested assets included
in discontinued operations, the reserve-to-production ratio associated with the
Company's proved reserves was in excess of 20 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, 2006:

2006 Average Daily
Proved Reserves as of December 31, 2006 Sales Volumes (b)
---------------------------------------------------- ---------------------------------
Oil Oil
& NGLs Gas Standardized & NGLS Gas
(MBbls) (MMcf) (a) MBOE Measure (Bbls) (Mcf) BOE
------- ---------- -------- ------------ ------- -------- --------
(in thousands)

United States.. 406,725 2,685,961 854,385 $ 4,189,171 36,204 284,732 83,659
Canada......... 2,199 173,509 31,117 269,289 774 43,420 8,011
South Africa... 3,070 60,511 13,156 143,722 4,127 -- 4,127
Tunisia........ 4,977 7,846 6,284 86,807 2,386 1,195 2,585
------- --------- ------- ------------ ------ ------- ------
Total.......... 416,971 2,927,827 904,942 $ 4,688,989 43,491 329,347 98,382
======= ========= ======= ============ ====== ======= ======

----------

(a) The gas reserves contain 316,528 MMcf of gas that will be produced and
utilized as field fuel.

(b) The 2006 average daily sales volumes are from continuing operations and (i)
do not include the field fuel produced, which averaged 47,568 Mcf per day,
and (ii) were calculated using a 365-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, 2006
(dollars in thousands):

Estimated
Future Future Future Future
Production Cash Production Development Future Net
Year Ended December 31, (a) (MBOE) Inflows Costs Costs Cash Flows
--------------------------- ---------- ----------- ----------- ----------- ------------

2007..................... 4,481 $ 175,426 $ 24,487 $ 589,438 $ (438,499)
2008..................... 10,127 389,933 61,873 691,380 (363,320)
2009..................... 15,803 611,695 100,032 572,748 (61,085)
2010..................... 19,240 741,831 128,291 475,130 138,410
Thereafter............... 312,710 12,893,943 3,465,588 1,331,388 8,096,967
-------- ----------- ----------- ----------- ------------
362,361 $14,812,828 $ 3,780,271 $ 3,660,084 $ 7,372,473
======== =========== =========== =========== ============

-----------

(a) Beginning in 2008 and thereafter, the production and cash flows represent
the drilling results from the respective year plus the incremental effects
of proved undeveloped drilling since 2007.

Description of Properties

United States

Approximately 89 percent of the Company's proved reserves at December 31,
2006 are located in the Spraberry field in the Permian Basin area, the Hugoton
and West Panhandle fields in the Mid-Continent area and the Raton field in the
Rocky Mountains area. These fields generate substantial operating cash flow and
the Spraberry and Raton fields have a large portfolio of low-risk drilling
opportunities. The cash flows generated from these fields provide funding for
the Company's other development and exploration activities both domestically and
internationally.

The following tables summarize the Company's United States development and
exploration/extension drilling activities during 2006:

Development Drilling
-----------------------------------------------------------------------------------
Beginning Wells Wells Successful Unsuccessful Divested Ending Wells
In Progress Spud Wells Wells Wells In Progress
--------------- ------- --------- ------------ -------- ------------

Permian Basin.............. 27 313 327 3 -- 10
Mid-Continent.............. -- 43 41 1 -- 1
Rocky Mountains............ -- 289 281 3 -- 5
Onshore Gulf Coast.........` 2 14 13 1 -- 2
---- ---- ---- ---- ---- ----
Total United States...... 29 659 662 8 -- 18
==== ==== ==== ==== ==== ====

Exploration/Extension Drilling
-----------------------------------------------------------------------------------
Beginning Wells Wells Successful Unsuccessful Divested Ending Wells
In Progress Spud Wells Wells Wells In Progress
--------------- ------- --------- ------------ -------- ------------

Permian Basin.............. -- 16 14 1 -- 1
Rocky Mountains............ 1 32 17 -- -- 16
Gulf of Mexico:
Continuing operations.... -- 2 1 1 -- --
Discontinued operations.. 3 - 3 -- -- --
Onshore Gulf Coast......... -- 21 14 3 -- 4
Alaska..................... 3 3 3 3 -- --
---- ---- ---- --- ---- ----
Total United States...... 7 74 52 8 -- 21
==== ==== ==== ==== ==== ====

The following tables summarize by geographic area the Company's United
States costs incurred during 2006:

Property
Acquisition Costs Asset
--------------------- Exploration Development Retirement
Proved Unproved Costs Costs Obligations Total
-------- --------- ----------- ----------- ----------- -----------
(in thousands)

Permian Basin........... $ 51,421 $ 30,703 $ 12,411 $ 285,980 $ 1,884 $ 382,399
Mid-Continent........... 133 -- 156 35,759 2,650 38,698
Rocky Mountains......... 1,240 17,495 64,924 170,863 9,561 264,083
Gulf of Mexico:
Continuing operations.. -- 8 94,167 5,045 6,028 105,248
Discontinued operations -- 2 3,808 3,167 -- 6,977
Onshore Gulf Coast...... 19,743 33,157 82,775 61,705 1,396 198,776
Alaska.................. 4,800 27,956 34,684 119,309 (a) 1,350 188,099
-------- --------- ----------- --------- ----------- -----------
Total United States.... $ 77,337 $ 109,321 $ 292,925 $ 681,828 $ 22,869 $ 1,184,280
======== ========= =========== ========= =========== ===========

-----------

(a) Includes $6.8 million of capitalized interest related to the Oooguruk
project.

Permian Basin

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 are produced primarily from three formations, the
upper and lower Spraberry and the Dean, at depths ranging from 6,700 feet to
9,200 feet. In addition, the Company has started completing the majority of its
wells in the Wolfcamp formation at depths ranging from 9,300 feet to 10,300 feet
with successful results. The Company believes the Spraberry field offers
excellent opportunities to enhance oil and gas production because of the
numerous undeveloped drilling locations, many of which are reflected in the
Company's proved undeveloped reserves, and the ability to contain operating
expenses through economies of scale.

During 2006, the Company (a) drilled 299 wells, an increase of 118 wells
over 2005, (b) acquired approximately 200,000 gross acres, bringing its total
acreage position to approximately 684,000 gross acres (593,000 net acres), (c)
completed several bolt-on property acquisitions and joint ventures, (d)
successfully drilled a majority of the wells to the Wolfcamp formation and (e)
acquired a well servicing operation as a measure to control costs.

Mid-Continent

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
285,000 gross acres (247,000 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
69 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 near allowable capacity during the year ended December
31, 2006.

During 2006, the Company reached a settlement agreement on the class action
Alford royalty lawsuit which primarily revolved around costs being charged to
the royalty owners. The settlement agreement provides for adjustment to the
manner in which royalty payments will be calculated and accordingly, the Company
expects a small increase in its production costs beginning in 2007. See Note I
of Notes to Consolidated Financial Statements included in "Item 8. Financial
Statements and Supplementary Data".

West Panhandle field. The West Panhandle properties are located in the
panhandle region of Texas. 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 (240,000 net 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.

The Company is pursuing regulatory relief in the West Panhandle field to
allow for future additional drilling locations.

Rocky Mountains

Raton field. The Raton Basin properties are located in the southeast
portion of Colorado. 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 pipeline system. The Company's gas in the Raton Basin has
an average energy content of 1,000 Btu. Since the completion of the Picketwire
lateral, production has continued to grow, resulting in expansion of the
system's capacity by its operator, the most recent expansion of which was in
October 2005. The Company owns approximately 317,000 gross acres (281,000 net
acres) in the center of the Raton Basin with current production from coal seams
of the Vermejo and Raton formations. The Company owns the well servicing and
frac equipment that it utilizes in the Raton field to control costs and insure
availability.

During 2006, the Company (a) drilled 288 wells, (b) added wellhead
compression and (c) continued efforts to optimize gathering and compression
facilities.

Piceance/Uinta Basins. The Piceance Basin is located in the central portion
of western Colorado, and the Uinta Basin is located in the central portion of
eastern Utah. The Company owns approximately 244,000 gross acres covering
producing and prospective regions of the Piceance and Uinta Basins. Currently,
production is established from various tight sandstone, coal and shale
formations. The Company's significant projects in the area are CBM plays at
Columbine Springs and Castlegate and a deep gas play at Main Canyon.

At Columbine Springs, in northwest Colorado, the Company is completing its
extension pilot program, with all wells expected to be on production by the end
of the first quarter of 2007. If the pilot project is successful in achieving
commercial quantities of gas production, full field development could begin in
2008.

In northeast Utah, the Company continues to monitor its CBM pilot at
Castlegate and is testing the wells recently drilled in the Main Canyon area. An
assessment of whether either project will be commercial is not expected until
the second half of 2007.

Sand Wash Basin. The Sand Wash Basin is the site of a potential CBM project
located north of the Company's Piceance Basin properties. The Company holds a 50
percent operated interest in 114,000 gross acres in the Lay Creek field. At Lay
Creek, the Company has drilled 15 wells in five separate pilot areas and
completed workovers and recompletions on 14 wells drilled by a previous
operator. The Company has completed the water treatment facility and plans to
initiate production in the first quarter of 2007. If the pilot projects are
successful in achieving commercial quantities of gas production, full field
development could begin in 2008.

Gulf of Mexico

Gulf of Mexico area. During March 2006, the Company sold all of its
interests in certain oil and gas properties in the deepwater Gulf of Mexico for
net proceeds of $1.2 billion, resulting in a gain of $726.2 million. See Notes N
and V of Notes to Consolidated Financial Statements included in "Item 8.
Financial Statements and Supplementary Data" for a description of the deepwater
Gulf of Mexico divestiture.

During 2005, the Company announced a discovery on its Clipper prospect in
the Green Canyon Blocks 299 and 300 in the deepwater Gulf of Mexico. During
2006, the Company drilled two successful Clipper appraisal wells, but drilled an
unsuccessful exploratory well at the Flying Cloud prospect, a prospect near the
Clipper discovery. The Company expects to develop the Clipper discovery and is
currently evaluating sub-sea tie-back options to third-party production handling
facilities in the area. Pioneer operates the Clipper discovery with a 55 percent
working interest.

As a result of Hurricane Rita, the Company's East Cameron facility, located
on the Gulf of Mexico shelf, was destroyed and the Company does not plan to
rebuild the facility based on the economics of the field. During the fourth
quarter of 2006, the Company's application to "reef in-place" a substantial
portion of the East Cameron debris was denied. As a result, the Company
currently estimates that it will cost approximately $119 million to reclaim and
abandon the East Cameron facility. The estimate to reclaim and abandon the East
Cameron facility is based upon an analysis and fee proposal prepared by a
third-party engineering firm for the majority of the work and an estimate by the
Company for the remainder. During 2006 and 2005, the Company recorded additional
abandonment obligation charges of $75.0 million and $39.8 million, respectively,
which amounts are included in hurricane activity, net in the accompanying
Consolidated Statements of Operations. The operations to reclaim and abandon the
East Cameron facilities began in January 2007 and the Company expects to incur a
substantial portion of the costs in 2007. The Company expects that a substantial
portion of the total estimated cost to reclaim and abandon the facility will be
covered by insurance, including 100 percent of the debris removal costs.
Consequently, the Company has recorded a $43.0 million insurance recovery
receivable corresponding to the estimated debris removal costs.

During 2006, the Company announced its intent to divest of its Gulf of
Mexico shelf properties; however, the Company has decided not to divest of these
properties after its sales efforts in 2006 did not result in an acceptable
offer.

Onshore Gulf Coast

South Texas. The Company has historically focused its drilling efforts in
South Texas on the Pawnee field in the Edwards Trend in South Texas. The Edwards
Trend is a tight gas limestone reservoir characterized by narrow bands of dry
gas fields extending over 250 miles. The Company has acquired over 270,000 gross
acres in the Edwards Trend. In addition to the operations in the Pawnee field,
the Company has operations in the SW Kenedy and Washburn fields. Production
depths in the Edwards Trend range from 9,500 feet to 14,000 feet.

During 2006, the Company drilled 16 exploration and appraisal wells
targeting new field discoveries in the Edwards Trend area with 88 percent
success, exceeding expectations and increasing proved gas reserves. Eight new
wells have been added to production and six wells are awaiting pipelines or
testing.

Having 3-D seismic data has significantly enhanced field development in the
Pawnee field, allowing the Company to more accurately locate and orient the
horizontal wells for optimal results. To expand its 3-D data coverage to include
new discoveries and additional prospects, the Company plans to shoot and
interpret approximately 850 square miles of new data. Multiple surveys are
planned for 2007, with three already underway. While the new seismic work is
being completed, the Company will direct most of its investments in the Edwards
Trend to lower-risk, lower-cost development drilling on existing discoveries
where 3-D data is currently available.

To revitalize existing horizontal wells in the area, the Company has
initiated a pilot using more extensive fracture stimulation techniques.
Horizontal wells in the field are completed open-hole and have traditionally
been lightly stimulated with acid. Recently, the Company began performing a new
fracture stimulation procedure on additional wells. The Company plans to

fracture stimulate additional horizontal wells, including newer producing wells,
during 2007 to further evaluate the potential for a more extensive program. The
Company also recently drilled a new horizontal well within a developed section
of the Pawnee field with very successful results. The Company is currently
evaluating additional infill drilling locations given this success. Plans are
also in progress to expand the gas gathering infrastructure in the area to
accommodate expected production growth and to maximize efficiency at the
Company's Pawnee Plant.

Northern Louisiana and Mississippi. The Company has acquired significant
acreage in Northern Louisiana and Mississippi. The Company has built an acreage
position covering multiple plays in the Mississippi Salt Basin and now holds
leases and option interests covering over 300,000 acres. Over the next two to
three years, the Company expects to test a number of opportunities and to
continue technical work that is currently underway.

One of the lower-risk opportunities in the portfolio is the redevelopment
of the Bolton Gas Field in Hinds County, Mississippi. The first well of the
project was drilled to 17,600 feet and penetrated multiple gas-bearing Cotton
Valley sands. Currently, the well is being logged and completion design work is
progressing. The location for the next well has been built and drilling will
commence immediately after operations are completed on the current well. The
Company plans to drill at least one more well in 2007 during this initial phase
of the project. Facility construction is underway and first production is
anticipated in mid-2007.

The Company has also concluded drilling operations on its first well
testing the Norphlet formation in Mississippi. The well was drilled in Wayne
County and, after extensive evaluation, has been plugged and abandoned. Future
drilling plans will be determined after a technical analysis of the initial well
is completed.

Alaska

Oooguruk. During 2002, the Company acquired a 70 percent working interest
and operatorship in ten state leases on Alaska's North Slope. In connection
therewith, the Company drilled three exploratory wells during 2003 to test a
possible extension of the productive sands in the Kuparuk River field in the
shallow waters offshore the North Slope of Alaska. 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 Bbls per day. In January 2004, the Company farmed-into a
large acreage block to the southwest of the Company's discovery. In 2004,
Pioneer completed an extensive technical and economic evaluation of the resource
potential within this area. As a result of this evaluation, the Company
performed front-end engineering and permitting activities during 2005 to further
define the scope of the project. In early 2006, the Company announced that it
had approved the development of the Oooguruk field in the project area.

The Company has constructed and armored the gravel drilling and production
island site and installation of a sub-sea flowline and facilities are planned
for 2007 to carry produced liquids to existing onshore processing facilities at
the Kuparuk River Unit. The Company continues to procure equipment and services,
fabricate equipment and modify a drilling rig for installation in 2007.
Development drilling of approximately 40 wells on the project is expected to
begin in late 2007 and be completed in 2009. First production is expected in
2008.

Cosmopolitan. During 2005, Pioneer announced that it entered into an
agreement on the Cosmopolitan Unit in the Cook Inlet. Under this agreement,
Pioneer earned a ten percent working interest in the unit from ConocoPhillips
through a disproportionate spending arrangement for a 3-D seismic program
undertaken during the fourth quarter of 2005. In June 2006, the Company
exercised an option to acquire an additional 40 percent working interest in the
Cosmopolitan Unit, bringing its working interest to 50 percent. Pioneer was
elected operator of the Cosmopolitan Unit and plans to drill an appraisal well
in 2007.

Onshore North Slope area. The Company holds a large acreage position in the
onshore North Slope area of Alaska, primarily in the National Petroleum Reserve
- Alaska ("NPRA"). During the 2006-2007 drilling season, the Company plans to
participate in the drilling of two non-operated exploratory wells in the NPRA.

International

The Company's international operations are located in Canada, offshore
South Africa and in southern Tunisia. Additionally, the Company has exploration
activities West Africa (Equatorial Guinea and Nigeria). As of December 31, 2006,
approximately three percent and two percent of the Company's proved reserves
were located in Canada and Africa, respectively.

The following tables summarize the Company's international development and
exploration/extension drilling activities during 2006:

Argentina - discontinued
operations............. 2 21 14 1 8 --
Canada................... 3 2 2 -- -- 3
South Africa............. -- 4 2 -- -- 2
---- ---- ---- ---- ---- ----
Total International.... 5 27 18 1 8 5
==== ==== ==== ==== ==== ====

Argentina - discontinued
operations............. 4 6 4 2 4 --
Canada................... 109 249 326 16 -- 16
South Africa............. 1 -- -- 1 -- --
Tunisia.................. 2 7 2 2 -- 5
West Africa - Nigeria.... -- 1 -- 1 -- --
---- ---- ---- ---- ---- ----
Total International.... 116 263 332 22 4 21
==== ==== ==== ==== ==== ====

The following tables summarize by geographic area the Company's
international costs incurred during 2006:

Argentina--discontinued
operations............ $ -- $ 2 $ 10,223 $ 25,542 $ -- $ 35,767
Canada................... -- 19,932 103,245 97,188 8,299 228,664
South Africa............. -- -- 288 117,511 (a) 13,964 131,763
Tunisia.................. -- 5,000 40,813 -- 336 46,149
Other.................... -- -- 11,358 -- -- 11,358
West Africa:
Equatorial Guinea...... -- -- (1,688) -- -- (1,688)
Nigeria................ -- 10,584 26,502 -- -- 37,086
-------- --------- ----------- --------- ----------- ------------
Total International... $ -- $ 35,518 $ 190,741 $ 240,241 $ 22,599 $ 489,099
======== ========= =========== ========= =========== ============

-----------

(a) Includes $5.3 million of capitalized interest related to the South Coast
Gas project.

Argentina. During April 2006, the Company sold its Argentine assets for net
proceeds of $669.6 million, resulting in a gain of $10.9 million. See Notes N
and V of Notes to Consolidated Financial Statements included in "Item 8.
Financial Statements and Supplementary Data" for a description of the Argentine
divestiture.

Canada. The Company's Canadian producing properties are located primarily
in Alberta and British Columbia, Canada. The Company continues to exploit
lower-risk opportunities identified in the Chinchaga field in northeast British
Columbia and Alberta. Production from the Chinchaga field is relatively dry gas
from formation depths averaging 3,400 feet.

The Company has commenced production and continued significant drilling,
pipeline and facility activities in south-central Alberta targeting Horseshoe
Canyon CBM in the greater Drumheller area. The greater Drumheller area produces
gas, condensate and minor oil from Cretaceous to Devonian formations at depths
ranging from 400 to 6,500 feet.

Also, in southern Alberta the Company has initiated a CBM pilot in the
Mannville coals. Currently, six wells have been drilled and are in the
dewatering stages to see if commercial quantities of gas can be achieved. The
Company is also evaluating other completion techniques that could potentially
accelerate the dewatering and increase production rates.

South Africa. The Company has agreements to explore for oil and gas
offshore South Africa covering over 3.6 million acres along the southern coast
in water depths generally less than 650 feet. The Sable oil field began
producing in August 2003 and the majority of the gas from the field has been
reinjected. The Company has a 40 percent working interest in the Sable field.

In 2005, the Company sanctioned the non-operated South Coast Gas
development project, which includes the sub-sea tie-back of gas from the Sable
field and six additional gas accumulations to an existing production facility on
the F-A platform for transportation via existing pipelines to a gas-to liquids
plant. Pioneer has a 45 percent working interest in the project. As part of
sanctioning of the South Coast Gas project, the Company signed a six-year
contract for the sale of all of its gas and condensate production from the
project. The contract contains an obligation for the purchaser to take or pay
for a total of 91.4 BCF and associated condensate if the anticipated
deliverability estimates are achieved. The price for both gas and condensate is
indexed to Brent oil sales. During 2006, the Company drilled four wells. During
the first half of 2007, the Company plans to drill two additional development
wells and complete the sub-sea well tie-backs to the existing production
facilities on the F-A platform. First production is expected to commence in the
second half of 2007.

Tunisia. The Company's Tunisian exploration permits can be separated into
three categories: (i) two exploration permits (Jenein Nord and El Hamra)
covering 1.6 million acres which the Company operates with a 100 percent working
interest, (ii) the Anadarko-operated Anaguid exploration permit covering over
1.2 million acres in which the Company has a 45 percent working interest and
(iii) the ENI-operated Adam Concession and Borj El Khadra exploration permit
covering approximately 212,000 acres and 970,000 acres, respectively, in which
the Company has a 20 percent and 40 percent working interest, respectively. All
exploration permits and concessions are onshore southern Tunisia.

Production from the Adam Concession began in May 2003. During 2006, the
Company continued its exploratory and appraisal activities on the Adam
Concession by drilling four wells, of which three were successful, and completed
a 3-D seismic survey. In 2006, the Company's interest in the Adam Concession was
reduced from 24 percent to 20 percent in accordance with the terms of the
concession. At December 31, 2006, the Company had an exploratory well in
progress on each of the Adam Concession and Borj El Khadra block. Both wells
were successful and are being added to production in the first quarter of 2007.
The Company plans to drill an additional two to three wells in the concession
during 2007.

In 2006, the Company acquired the remaining equity interest in the Jenein
Nord block that it did not already own and became the operator of the block.
During 2006, the Company completed a 3-D seismic survey on the Jenein Nord
block. The Company drilled an exploratory well during 2006 that encountered
multiple oil bearing zones and its commercial development is being analyzed. At
December 31, 2006, the Company had an additional exploratory well in progress
which was successful. The Company plans to drill one to two additional wells in
the block during 2007. After the performance of the wells has been monitored for
several months, additional exploration and appraisal wells may also be drilled.

Recently, the Company entered into a farm-out agreement of its interest in
the El Hamra block pursuant to which it retained an economic interest in the
block. In the Anaguid block, the Company continues to evaluate the results of
its past drilling on the block and other blocks in the area to determine the
go-forward plans on the block.

West Africa

The Company previously disclosed that it had retained a third party adviser
to assist it in marketing its West Africa assets. No agreement to sell these
assets has been reached to date, but the Company continues to consider interest
from potential purchasers. As such, the capital budget includes amounts for
expected drilling activities in West Africa during 2007. A first well is
expected to spud during the second quarter of 2007, with drilling on a second
well expected to commence in the second half of 2007, both in deepwater Nigeria.
The timing of the drilling of a third well is uncertain and therefore no amounts
have been budgeted for this prospect in 2007.

Equatorial Guinea. The Company owns a 50 percent working interest in Block
H located in the northern Rio Muni Basin of Equatorial Guinea. The block covers
an area of over 240,000 acres and water depth ranging from 300 meters in the
southeastern corner of the block to over 1,800 meters near the western block
boundary. Currently, as a result of new hydrocarbon law in Equatorial Guinea,
the government in Equatorial Guinea is claiming an additional participation
interest in the block. The Company is evaluating the effect of the claim with
the operator of the block. The Company has identified several prospects on the
block that are being evaluated for future drilling. In light of the government's
claim, the timing of drilling a well is uncertain.

Nigeria. A partially-owned subsidiary of the Company joined Oranto
Petroleum and Orandi Petroleum in an existing production sharing contract on
Block 320 in deepwater Nigeria gaining exploration rights from the Nigerian
National Petroleum Corporation. The subsidiary, which holds a 51 percent
interest in Block 320, is owned 59 percent by the Company and 41 percent by an
unaffiliated third party. The Company completed a 3-D seismic survey covering
the block in 2006. The Company currently expects to drill the first exploration
well on the block in the second half of 2007.

The Company owns a 25 percent working interest in Devon Energy-operated
Block 256 offshore Nigeria. During the first quarter of 2006, the Company
participated in the drilling of the Pina 1-X well on Block 256 in the deepwater
of Nigeria, which was unsuccessful. The partners plan to drill an additional
well on Block 256 in the second quarter of 2007 to test a different type of
play.

Selected Oil and Gas Information

The following tables set forth selected oil and gas information from
continuing operations for the Company as of and for each of the years ended
December 31, 2006, 2005 and 2004. Because of normal production declines,
increased or decreased drilling activities and the effects of 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 tables set forth production,
price and cost data with respect to the Company's properties for 2006, 2005 and
2004. These amounts represent the Company's historical results from continuing
operations without making pro forma adjustments for any acquisitions,
divestitures or drilling activity that occurred during the respective years. The
production amounts will not agree to the reserve volume tables in the "Unaudited
Supplementary Information" section included in "Item 8. Financial Statements and
Supplementary Data" due to field fuel volumes and production from discontinued
operations being included in the reserve volume tables.

PRODUCTION, PRICE AND COST DATA

Year Ended December 31, 2006
-----------------------------------------------------------
United South
States Canada Africa Tunisia Total
-------- -------- -------- -------- --------

Production information:
Annual sales volumes:
Oil (MBbls)............................... 6,467 113 1,506 871 8,957
NGLs (MBbls).............................. 6,748 169 -- -- 6,917
Gas (MMcf)................................ 103,928 15,848 -- 436 120,212
Total (MBOE).............................. 30,536 2,924 1,506 944 35,910
Average daily sales volumes:
Oil (Bbls)................................ 17,716 311 4,127 2,386 24,540
NGLs (Bbls)............................... 18,488 463 -- -- 18,951
Gas (Mcf)................................. 284,732 43,420 -- 1,195 329,347
Total (BOE)............................... 83,659 8,011 4,127 2,585 98,382
Average prices, including hedge results and
amortization of deferred VPP revenue:
Oil (per Bbl)............................... $ 65.73 $ 65.57 $ 65.92 $ 63.16 $ 65.51
NGLs (per Bbl).............................. $ 35.24 $ 51.47 $ -- $ -- $ 35.64
Gas (per Mcf)............................... $ 6.15 $ 6.75 $ -- $ 5.97 $ 6.23
Revenue (per BOE)........................... $ 42.64 $ 42.11 $ 65.92 $ 61.05 $ 44.06
Average prices, excluding hedge results and
amortization of deferred VPP revenue:
Oil (per Bbl)............................... $ 62.92 $ 65.57 $ 65.74 $ 63.16 $ 63.45
NGLs (per Bbl).............................. $ 35.24 $ 51.47 $ -- $ -- $ 35.64
Gas (per Mcf)............................... $ 5.96 $ 6.61 $ -- $ 5.97 $ 6.04
Revenue (per BOE)........................... $ 41.37 $ 41.35 $ 65.74 $ 61.05 $ 42.91
Average costs (per BOE):
Production costs:
Lease operating........................... $ 5.64 $ 9.50 $ 14.47 $ 1.99 $ 6.23
Third-party transportation charges........ .82 6.03 -- 1.42 1.22
Taxes:
Ad valorem.............................. 1.45 -- -- -- 1.24
Production.............................. 1.99 -- -- -- 1.69
Workover.................................. .72 1.29 -- -- .71
-------- -------- -------- -------- --------
Total..................................... $ 10.62 $ 16.82 $ 14.47 $ 3.41 $ 11.09
======== ======== ======== ======== ========
Depletion expense........................... $ 9.07 $ 15.39 $ 6.28 $ 4.25 $ 9.34
======== ======== ======== ======== ========

PRODUCTION, PRICE AND COST DATA - (Continued)

Year Ended December 31, 2005
-----------------------------------------------------------
United South
States Canada Africa Tunisia Total
-------- -------- -------- -------- --------

Production information:
Annual sales volumes:
Oil (MBbls)................................ 8,008 77 2,405 1,269 11,759
NGLs (MBbls)............................... 6,352 184 -- -- 6,536
Gas (MMcf)................................. 98,927 13,296 -- -- 112,223
Total (MBOE)............................... 30,849 2,476 2,405 1,269 36,999
Average daily sales volumes:
Oil (Bbls)................................. 21,942 210 6,588 3,477 32,217
NGLs (Bbls)................................ 17,403 503 -- -- 17,906
Gas (Mcf).................................. 271,033 36,427 -- -- 307,460
Total (BOE)................................ 84,517 6,784 6,588 3,477 101,366
Average prices, including hedge results and
amortization of deferred VPP revenue:
Oil (per Bbl)................................ $ 32.01 $ 52.12 $ 53.01 $ 52.98 $ 38.70
NGLs (per Bbl)............................... $ 31.72 $ 45.79 $ -- $ -- $ 32.12
Gas (per Mcf)................................ $ 6.94 $ 7.67 $ -- $ -- $ 7.02
Revenue (per BOE)............................ $ 37.09 $ 46.18 $ 53.01 $ 52.98 $ 39.28
Average prices, excluding hedge results and
amortization of deferred VPP revenue:
Oil (per Bbl)................................ $ 54.05 $ 52.12 $ 53.01 $ 52.98 $ 53.71
NGLs (per Bbl)............................... $ 31.72 $ 45.79 $ -- $ -- $ 32.12
Gas (per Mcf)................................ $ 7.26 $ 7.67 $ -- $ -- $ 7.31
Revenue (per BOE)............................ $ 43.86 $ 46.21 $ 53.01 $ 52.98 $ 44.93
Average costs (per BOE):
Production costs:
Lease operating............................ $ 4.55 $ 6.65 $ 11.79 $ 1.66 $ 5.06
Third-party transportation charges......... .66 6.29 -- 1.54 1.03
Taxes:
Ad valorem............................... 1.31 -- -- -- 1.09
Production............................... 1.94 -- -- -- 1.61
Workover................................... .53 1.89 -- -- .57
-------- -------- -------- -------- --------
Total...................................... $ 8.99 $ 14.83 $ 11.79 $ 3.20 $ 9.36
======== ======== ======== ======== ========
Depletion expense............................ $ 7.10 $ 12.71 $ 10.19 $ 3.75 $ 7.56
======== ======== ======== ======== ========

PRODUCTION, PRICE AND COST DATA - (Continued)

Year Ended December 31, 2004
-----------------------------------------------------------
United South
States Canada Africa Tunisia Total
-------- -------- -------- -------- --------

Production information:
Annual sales volumes:
Oil (MBbls)................................ 8,001 26 3,429 845 12,301
NGLs (MBbls)............................... 7,203 155 -- -- 7,358
Gas (MMcf)................................. 76,629 9,372 -- -- 86,001
Total (MBOE)............................... 27,976 1,743 3,429 845 33,993
Average daily sales volumes:
Oil (Bbls)................................. 21,863 72 9,368 2,308 33,611
NGLs (Bbls)................................ 19,678 425 -- -- 20,103
Gas (Mcf).................................. 209,371 25,606 -- -- 234,977
Total (BOE)................................ 76,437 4,764 9,368 2,308 92,877
Average prices, including hedge results and
amortization of deferred VPP revenue:
Oil (per Bbl)................................ $ 29.53 $ 48.37 $ 37.87 $ 39.14 $ 32.56
NGLs (per Bbl)............................... $ 25.05 $ 32.03 $ -- $ -- $ 25.20
Gas (per Mcf)................................ $ 4.99 $ 4.72 $ -- $ -- $ 4.96
Revenue (per BOE)............................ $ 28.57 $ 28.93 $ 37.87 $ 39.14 $ 29.79
Average prices, excluding hedge results and
amortization of deferred VPP revenue:
Oil (per Bbl)................................ $ 39.22 $ 48.37 $ 38.60 $ 39.14 $ 39.06
NGLs (per Bbl)............................... $ 25.05 $ 32.03 $ -- $ -- $ 25.20
Gas (per Mcf)................................ $ 5.46 $ 5.37 $ -- $ -- $ 5.45
Revenue (per BOE)............................ $ 32.62 $ 32.45 $ 38.60 $ 39.14 $ 33.37
Average costs (per BOE):
Production costs:
Lease operating............................ $ 3.32 $ 4.90 $ 8.31 $ 2.04 $ 3.87
Third-party transportation charges......... .18 5.02 -- 1.54 .44
Taxes:
Ad valorem............................... .99 -- -- -- .82
Production............................... 1.33 -- -- -- 1.10
Workover................................... .42 .87 -- -- .39
-------- -------- -------- -------- --------
Total...................................... $ 6.24 $ 10.79 $ 8.31 $ 3.58 $ 6.62
======== ======== ======== ======== ========
Depletion expense............................ $ 5.34 $ 12.93 $ 12.86 $ 4.43 $ 6.46
======== ======== ======== ======== ========

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,
2006, 2005 and 2004:

PRODUCTIVE WELLS (a)

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

As of December 31, 2006:
United States.................. 4,605 4,180 8,785 3,821 3,906 7,727
Argentina...................... -- -- -- -- -- --
Canada......................... 48 832 880 31 699 730
South Africa................... 4 2 6 2 1 3
Tunisia........................ 10 -- 10 2 -- 2
------- ------- ------- ------- ------- -------
Total.......................... 4,667 5,014 9,681 3,856 4,606 8,462
======= ======= ======= ======= ======= =======
As of December 31, 2005:
United States.................. 4,300 3,955 8,255 3,531 3,669 7,200
Argentina...................... 821 261 1,082 684 202 886
Canada......................... 65 675 740 30 511 541
South Africa................... 8 -- 8 2 -- 2
Tunisia........................ 4 -- 4 2 -- 2
------- ------- ------- ------- ------- -------
Total.......................... 5,198 4,891 10,089 4,249 4,382 8,631
======= ======= ======= ======= ======= =======
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
South Africa................... 5 -- 5 2 -- 2
Tunisia........................ 4 -- 4 1 -- 1
------- ------- ------- ------- ------- -------
Total.......................... 4,790 4,705 9,495 3,923 4,089 8,012
======= ======= ======= ======= ======= =======

----------

(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, 2006, the Company owned interests in 208 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, 2006:

LEASEHOLD ACREAGE

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

United States:
Onshore.............. 1,374,610 1,203,463 2,897,525 1,306,252 291,987
Offshore............. 59,340 21,007 235,126 185,197 10,500
---------- ---------- ---------- ---------- ---------
1,433,950 1,224,470 3,132,651 1,491,449 302,487
Canada................. 266,000 194,000 547,000 488,000 23,000
South Africa........... 124,600 55,590 3,503,400 1,576,530 --
Tunisia................ 212,420 42,484 3,812,253 2,581,278 --
West Africa............ -- -- 1,297,951 495,476 --
---------- ---------- ---------- ---------- ---------
Total................ 2,036,970 1,516,544 12,293,255 6,632,733 325,487
========== ========== ========== ========== =========

The following table sets forth the expiration dates of the leases on the
Company's gross and net undeveloped acres as of December 31, 2006:

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

2007 (b)......................... 7,580,318 4,380,838
2008............................. 585,640 349,826
2009............................. 1,045,412 528,766
2010............................. 380,582 317,256
2011............................. 281,594 177,313
Thereafter....................... 2,419,709 878,734
---------- ---------
Total.......................... 12,293,255 6,632,733
========== =========

----------

(a) Acres expiring are based on contractual lease maturities.

(b) Acres subject to expiration during 2007 include 3.5 million gross acres
(1.6 million net acres) in South Africa, 3.8 million gross acres (2.6
million net acres) in Tunisia and 264,665 gross acres (223,030 net acres)
in North America. The acreage in South Africa relates to areas where the
Company has no intention to drill, has no cost basis in the acreage and
intends to let the acreage expire. In Tunisia, the Company either has
received extensions, plans to make the necessary expenditures to extend the
acreage or intends to seek extensions on the 2007 expirations. As to the
remaining acreage the Company may extend the leases prior to their
expiration based upon 2007 planned activities or for other business
reasons. In certain leases, the extension is only subject to the Company's
election to extend and the fulfillment of certain capital expenditures
commitments. In other cases, the extensions are subject to the consent of
third parties, and no assurance can be given that the requested extensions
will be granted. 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 2006, 2005 and 2004. 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,
------------------------------ ------------------------------
2006 2005 2004 2006 2005 2004
------ ------ ------ ------ ------ ------

United States:
Productive wells:
Development............ 662 537 268 619 505 243
Exploratory............ 52 40 8 42 37 5
Dry holes:
Development............ 8 7 3 7 7 3
Exploratory............ 8 7 6 6 5 3
----- ----- ----- ----- ----- -----
730 591 285 674 554 254
----- ----- ----- ----- ----- -----
Argentina:
Productive wells:
Development............ 14 65 43 14 64 42
Exploratory............ 4 19 21 4 18 21
Dry holes:
Development............ 1 4 1 1 4 1
Exploratory............ 2 14 10 2 14 10
----- ----- ----- ----- ----- -----
21 102 75 21 100 74
----- ----- ----- ----- ----- -----
Canada:
Productive wells:
Development............ 2 27 3 2 26 3
Exploratory............ 326 87 27 297 72 25
Dry holes:
Development............ -- -- -- -- -- --
Exploratory............ 16 7 24 15 7 23
----- ----- ----- ----- ----- -----
344 121 54 314 105 51
----- ----- ----- ----- ----- -----
South Africa:
Productive wells:
Development............ 2 -- -- 1 -- --
Exploratory............ -- 1 -- -- -- --
Dry holes:
Development............ -- -- -- -- -- --
Exploratory............ 1 -- -- 1 -- --
----- ----- ----- ----- ----- -----
Total................... 3 1 -- 2 -- --
----- ----- ----- ----- ----- -----
Tunisia:
Productive wells:
Development............ -- -- 2 -- -- 1
Exploratory............ 2 2 1 1 1 --
Dry holes:
Development............ -- -- -- -- -- --
Exploratory............ 2 2 -- -- 1 --
----- ----- ----- ----- ----- -----
Total................... 4 4 3 1 2 1
----- ----- ----- ----- ----- -----
West Africa:
Productive wells:
Development............ -- -- -- -- -- --
Exploratory............ -- -- 1 -- -- 1
Dry holes:
Development............ -- -- -- -- -- --
Exploratory............ 1 1 5 -- -- 4
----- ----- ----- ----- ----- -----
1 1 6 -- -- 5
----- ----- ----- ----- ----- -----
Total................... 1,103 820 423 1,012 761 385
===== ===== ===== ===== ===== =====
Success ratio (a).......... 96% 95% 88% 97% 95% 89%

----------

(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.

The following table sets forth information about the Company's wells upon
which drilling was in progress as of December 31, 2006:

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

United States:
Development..................... 18 17
Exploratory..................... 21 14
---- ----
39 31
---- ----
Canada:
Development..................... 3 2
Exploratory..................... 16 12
---- ----
19 14
---- ----
South Africa:
Development..................... 2 1
Exploratory..................... -- --
---- ----
2 1
---- ----
Tunisia:
Development..................... -- --
Exploratory..................... 5 3
---- ----
5 3
---- ----
Total........................... 65 49
==== ====

ITEM 3. LEGAL PROCEEDINGS

The Company is party to the legal proceedings that are described under
"Legal actions" in Note I of Notes to Consolidated Financial Statements included
in "Item 8. Financial Statements and Supplementary Data". The Company is also
party to other proceedings and claims incidental to its business. While many of
these matters involve inherent uncertainty, the Company believes that the amount
of the liability, if any, ultimately incurred with respect to such other
proceedings and claims will not have a material adverse effect on the Company's
consolidated financial position as a whole or on its liquidity, capital
resources or future annual results of operations.

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 2006.

PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, 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 Board declared dividends to the holders of the Company's
common stock of $.25 per share and $.22 per share during each of the years ended
December 31, 2006 and 2005, respectively.

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, 2006 and 2005:

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

Year ended December 31, 2006:
Fourth quarter....................... $ 44.46 $ 36.48 $ --
Third quarter........................ $ 46.68 $ 37.07 $ .13
Second quarter....................... $ 46.75 $ 36.43 $ --
First quarter........................ $ 54.46 $ 37.98 $ .12
Year ended December 31, 2005:
Fourth quarter....................... $ 55.98 $ 45.39 $ --
Third quarter........................ $ 56.35 $ 39.66 $ .12
Second quarter....................... $ 45.24 $ 36.67 $ --
First quarter........................ $ 44.82 $ 32.91 $ .10

On February 13, 2007, the last reported sales price of the Company's common
stock, as reported in the NYSE composite transactions, was $40.34 per share.

As of February 13, 2007, the Company's common stock was held by
approximately 26,534 holders of record.

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, 2006:

Total Number of Shares Approximate Dollar
(or Units) Purchased Amount of Shares
Total Number of Average Price as Part of Publicly that May Yet Be
Period Shares (or Units) Paid per Share Announced Plans Purchased under
Purchased (a) (or Unit) or Programs Plans or Programs
----------------- -------------- ---------------------- ------------------

October 2006......... 1,347,746 $ 37.92 1,343,100
November 2006........ 4,700 $ 40.02 4,700
December 2006........ 46 $ 43.00 -
------------ -----------
Total............... 1,352,492 $ 37.93 1,347,800 $ 13,988,043
============ =========== ==============

----------

(a) Amounts include shares withheld to fund tax withholding on employees' stock
awards for which restrictions have lapsed.

During August 2005, the Board approved a share repurchase program
authorizing the purchase of up to $1 billion of the Company's common stock,
$345.3 million and $640.7 million of which were completed in 2006 and 2005,
respectively. In February 2007, the Board approved a new share repurchase
program authorizing the purchase of up to $300 million of the Company's common
stock.

ITEM 6. SELECTED FINANCIAL DATA

The following selected consolidated financial data as of and for each of
the five years ended December 31, 2006 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, (a)
-------------------------------------------------------------
2006 2005 2004 2003 2002
--------- --------- --------- --------- ---------
(in millions, except per share data)

Statements of Operations Data:
Revenues and other income:
Oil and gas.................................. $ 1,582.0 $ 1,453.2 $ 1,012.6 $ 725.8 $ 551.9
Interest and other (b )...................... 58.7 31.6 2.2 7.8 7.6
Gain (loss) on disposition of assets, net.... (7.9) 59.8 -- 1.4 4.2
--------- --------- --------- --------- ---------
1,632.8 1,544.6 1,014.8 735.0 563.7
--------- --------- --------- --------- ---------
Costs and expenses:
Oil and gas production....................... 398.3 346.4 224.9 162.4 152.2
Depletion, depreciation and amortization..... 359.5 299.9 231.6 170.3 154.7
Impairment of long-lived assets (c).......... -- .6 39.7 -- --
Exploration and abandonments................. 264.1 163.3 113.3 93.9 47.9
General and administrative................... 121.8 114.3 73.2 54.4 43.4
Accretion of discount on asset retirement
obligations................................ 4.8 4.2 4.1 2.9 --
Interest..................................... 107.0 126.1 102.0 91.3 95.8
Hurricane activity, net (d).................. 32.0 39.8 -- -- --
Other (e).................................... 36.3 99.5 28.4 16.6 30.2
--------- --------- --------- --------- ---------
1,323.8 1,194.1 817.2 591.8 524.2
--------- --------- --------- --------- ---------
Income from continuing operations before
income taxes and cumulative effect of
changes in accounting principle............ 309.0 350.5 197.6 143.2 39.5
Income tax benefit (provision) (f)........... (136.7) (155.8) (63.1) 134.2 (.9)
--------- --------- --------- --------- ---------
Income from continuing operations before
cumulative effect of change in accounting
principle.................................. 172.3 194.7 134.5 277.4 38.6
Income from discontinued operations,
net of tax (a)............................. 567.4 339.9 178.4 117.8 (11.9)
--------- --------- --------- --------- ---------
Income (loss) before cumulative effect of
change in accounting principle............. 739.7 534.6 312.9 395.2 26.7
Cumulative effect of change in accounting
principle, net of tax (g).................. -- -- -- 15.4 --
--------- --------- --------- --------- ---------
Net income................................... $ 739.7 $ 534.6 $ 312.9 $ 410.6 $ 26.7
========= ========= ========= ========= =========
Income from continuing operations before
cumulative effect of change in accounting
principle per share:
Basic.................................... $ 1.39 $ 1.42 $ 1.07 $ 2.37 $ .34
========= ========= ========= ========= =========
Diluted.................................. $ 1.36 $ 1.40 $ 1.06 $ 2.34 $ .34
========= ========= ========= ========= =========
Net income per share:
Basic.................................... $ 5.95 $ 3.90 $ 2.50 $ 3.50 $ .24
========= ========= ========= ========= =========
Diluted.................................. $ 5.81 $ 3.80 $ 2.46 $ 3.46 $ .23
========= ========= ========= ========= =========
Weighted average shares outstanding:
Basic.................................... 124.4 137.1 125.2 117.2 112.5
========= ========= ========= ========= =========
Diluted.................................. 127.6 141.4 127.5 118.5 114.3
========= ========= ========= ========= =========
Dividends declared per share................. $ .25 $ .22 $ .20 $ -- $ --
========= ========= ========= ========= =========
Balance Sheet Data (as of December 31):
Total assets................................. $ 7,355.4 $ 7,329.2 $ 6,733.5 $ 3,951.6 $ 3,455.1
Long-term obligations and minority
interests.................................. $ 3,483.7 $ 4,078.8 $ 3,357.2 $ 1,762.0 $ 1,805.6
Total stockholders' equity................... $ 2,984.7 $ 2,217.1 $ 2,831.8 $ 1,759.8 $ 1,374.9

--------

(a) Certain amounts for periods prior to January 1, 2006 have been reclassified
(i) in accordance with Statement of Financial Accounting Standards ("SFAS")
No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets"
("SFAS 144") to reflect the results of operations of certain assets
disposed of during 2006 as discontinued operations, rather than as a
component of continuing operations (see Notes B and V of Notes to
Consolidated Financial Statements included in "Item 8. Financial Statements
and Supplementary Data" for additional discussion) and (ii) to conform with
the current year presentation.

(b) Interest and other income in 2006 and 2005 include $7.6 million and $14.2
million, respectively, of income associated with various business
interruption insurance claims. See Notes M and U of Notes to Consolidated
Financial Statements included in "Item 8. Financial Statements and
Supplementary Data".

(c) During 2005 and 2004, the Company recorded $.6 million and $39.7 million of
impairment charges for its Gabonese Olowi field because development of the
discovery was canceled due to significant increases in projected field
development costs. See Note S of Notes to Consolidated Financial Statements
included in "Item 8. Financial Statements and Supplementary Data".

(d) Hurricane activity, net, for 2006 and 2005 includes $75.0 million and $39.8
million, respectively, of charges to reclaim and abandon the East Cameron
facilities destroyed by Hurricane Rita. In 2006, the Company recorded $43.0
million of estimated insurance recoveries associated with debris removal.
See Note U of Notes to Consolidated Financial Statements included in "Item
8. Financial Statements and Supplementary Data".

(e) Other expense for 2006, 2005, 2003 and 2002 includes losses on the early
extinguishment of debt of $8.1 million, $26.0 million, $1.5 million and
$22.3 million, respectively. Other expense for 2006, 2005, 2004, 2003 and
2002 includes $(11.6) million, $44.2 million, $4.2 million, $2.8 million
and $1.7 million, respectively, of derivative ineffectiveness charges
(credits). See Note O of Notes to Consolidated Financial Statements
included in "Item 8. Financial Statements and Supplementary Data".

(f) Income tax benefit for 2003 includes a $197.7 million adjustment to reduce
United States deferred tax asset valuation allowances.

(g) Cumulative effect of change in accounting principle for 2003 relates to the
adoption of SFAS No. 143 "Accounting for Asset Retirement Obligations" on
January 1, 2003.

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

Strategic Initiatives and Goals

During 2006, the Company accomplished significant goals underlying the
strategic initiatives established in 2005 to enhance shareholder value and
investment returns. Together with other important accomplishments, the Company:

o Substantially completed a $1 billion share repurchase program, $640.7
million of which was completed during 2005 and $345.3 million of which
was completed during 2006

o Completed the divestiture of the Company's assets in Argentina for net
proceeds of $669.6 million, resulting in a gain of $10.9 million

o Completed the divestiture of the Company's assets in the deepwater
Gulf of Mexico for net proceeds of $1.2 billion, resulting in a gain
of $726.2 million

o Reduced higher-risk, higher-impact exploration spending to
approximately five percent of the total capital spent in 2006

o Focused capital spending on lower-risk North American onshore
development and extension drilling

o Produced 35.9 MMBOE in 2006 from continuing operations

o Increased the semi-annual dividend to shareholders to $0.13 per share

Financial and Operating Performance

Pioneer's financial and operating performance for 2006 included the
following highlights:

o Average daily sales volumes, on a BOE basis, decreased three percent
in 2006 as compared to 2005, primarily due to a 126 percent increase
in the delivery of VPP volumes. Excluding the delivery of the VPP
volumes in 2006 (5.6 MMBOE) and 2005 (2.5 MMBOE), the Company's North
American production increased approximately nine percent, which the
Company believes provides a better understanding of the actual results
of the Company's 2006 North American drilling program excluding the
increased VPP deliveries.

o Oil and gas revenues increased nine percent in 2006 as compared to
2005, primarily as a result of increases in worldwide oil and NGL
prices.

o Net income increased 38 percent to $739.7 million ($5.81 per diluted
share) in 2006 from $534.6 million ($3.80 per diluted share) in 2005,
primarily on the strength of higher oil and NGL prices and gains on
the sale of deepwater Gulf of Mexico and Argentine assets.

o Income from continuing operations decreased to $172.3 million ($1.36
per diluted share) for 2006, as compared to $194.7 million ($1.40 per
diluted share) for 2005, primarily due to higher exploration and
abandonment expenses in 2006.

o The Company recognized income from discontinued operations of $567.4
million ($4.45 per diluted share) during 2006, primarily attributable
to the sale of deepwater Gulf of Mexico and Argentine assets, as
compared to income from discontinued operations of $339.9 million
($2.40 per diluted share) during 2005.

o Outstanding debt decreased to $1.5 billion at December 31, 2006 as
compared to $2.1 billion at December 31, 2005, primarily due to the
application of sales proceeds from the Company's divestment of its
assets in Argentina and the deepwater Gulf of Mexico.

o The Company's debt-to-capitalization was 33 percent at December 31,
2006 as compared to 48 percent at December 31, 2005.

o Net cash provided by operating activities decreased by $522.3
million, or 41 percent as compared to that of 2005, primarily due to
the sale of deepwater Gulf of Mexico and Argentine assets during 2006
and Canadian and Gulf of Mexico shelf assets during 2005.

o The Company added 91 MMBOE of proved reserves during 2006, resulting
in total proved reserves of 904.9 MMBOE at December 31, 2006.

2007 Outlook and Activities

Commodity prices. Significant factors that may impact 2007 commodity prices
include developments in the issues currently impacting Iraq and Iran and the
Middle East in general; the extent to which members of the 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, including
the impact of increasing LNG deliveries to the United States. Although the
Company cannot predict the occurrence of events that may affect 2007 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. Pioneer will continue to
strategically hedge a portion of its oil and gas price risk to mitigate the
impact of price volatility on its oil, NGL and gas revenues. 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
commodity hedge positions at December 31, 2006. Also see "Item 7A. Quantitative
and Qualitative Disclosures About Market Risk" for disclosures about the
Company's commodity related derivative financial instruments.

Capital budget for 2007. The Company announced a 2007 capital budget of
$1.1 billion, excluding acquisitions, effects of asset retirement obligations,
capitalized interest and geological and geophysical administrative costs. The
2007 capital budget is allocated (i) 50 percent to low-risk development drilling
in onshore North American core areas, (ii) 25 percent to the development of the
South African South Coast Gas and Alaskan Oooguruk projects, (iii) 20 percent to
test and develop lower-risk resource plays in onshore North America and Tunisia
and (iv) 5 percent to high-impact exploration activities in the United States
and West Africa. The Company plans to drill and recomplete approximately 650 to
700 wells during 2007.

2007 Annual Production. The Company believes that the results from its 2006
drilling program and 2007 capital budget will allow the Company to realize
production growth during 2007 of 10 percent or more as compared to the Company's
2006 production.

First Quarter 2007 Outlook. Based on current estimates, the Company expects
that first quarter 2007 production will average 97,000 to 102,000 BOEPD. The
range reflects the typical variability in the timing of oil cargo shipments in
South Africa and Tunisia and the recent downtime related to severe winter
weather in the Company's Rockies and Mid-Continent areas, which is expected to
reduce first quarter production by approximately 3,000 BOEPD.

First quarter production costs (including production and ad valorem taxes
and transportation costs) are expected to average $11.25 to $12.25 per BOE based
on current NYMEX strip prices for oil and gas, reduced production due to weather
downtime and increased weather-related repair costs. Depletion, depreciation and
amortization ("DD&A") expense is expected to average $10.00 to $11.00 per BOE.

Total exploration and abandonment expense for the quarter is expected to be
$50 million to $90 million including (i) up to $25 million from high-impact
drilling on Alaska's North Slope, (ii) up to $30 million from activities in the
Company's resource plays in the Edwards Trend in South Texas, Uinta/Piceance in

the Rockies area, Canada and Tunisia, (iii) $30 million in seismic investments
and personnel costs, primarily related to the resource plays the Company is
currently progressing and (iv) $5 million related to acreage and other costs.
General and administrative expense is expected to be $30 million to $35 million.
Interest expense is expected to be $25 million to $28 million. Accretion of
discount on asset retirement obligations is expected to be $1 million to $2
million.

The Company's first quarter effective income tax rate is expected to range
from 37 percent to 45 percent based on current capital spending plans and higher
tax rates in certain foreign jurisdictions. Cash income taxes are expected to
range from $5 million to $15 million, principally related to Tunisian income
taxes.

Share repurchase programs. In February 2007, the Company announced that the
Board approved a new share repurchase program that authorizes the purchase of up
to $300 million of the Company's common stock. This share repurchase program
follows the Company's previous share repurchase programs of $1 billion and $300
million, which were essentially completed during 2006 and 2005, respectively.

Acquisitions

2006 acquisition expenditures. During 2006, the Company spent approximately
$223.2 million to acquire proved and unproved properties, which was comprised of
approximately $144.8 million of proved properties and $78.3 million of unproved
properties. The proved properties were primarily bolt-on and acreage
acquisitions in the Spraberry field and Edwards Trend area. In North America,
the acquisition of unproved properties is comprised of acreage acquisitions in
the Spraberry field, Edwards Trend area, Rockies area, Alaska and Canada. The
Company also acquired an additional interest in its Jenein Nord block in Tunisia
and recognized additional obligations associated with its Nigerian prospects
during 2006.

2005 acquisition expenditures. In July 2005, the Company completed the
acquisition of approximately 70 MMBOE of substantially proved undeveloped oil
reserves in the United States core areas of the Permian Basin and South Texas
for $176.9 million.

2004 Evergreen merger. On September 28, 2004, Pioneer completed a 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.

Divestitures

Argentina and Deepwater Gulf of Mexico. During March 2006, the Company sold
its interests in certain oil and gas properties in the deepwater Gulf of Mexico
for net proceeds of $1.2 billion, resulting in a gain of $726.2 million. During
April 2006, the Company sold its Argentine assets for net proceeds of $669.6
million, resulting in a gain of $10.9 million. The historic results of these
properties and the related gains on disposition are reported as discontinued
operations.

Volumetric production payments. During January 2005, the Company sold 20.5
MMBOE of proved reserves in the Hugoton and Spraberry fields, by means of two
VPPs for net proceeds of $592.3 million, including the assignment of the
Company's obligations under certain derivative hedge agreements.

During April 2005, the Company sold 7.3 MMBOE of proved reserves in the
Spraberry field, by means of a VPP for net proceeds of $300.3 million, including
the value attributable to certain derivative hedge agreements assigned to the
buyer of the April VPP.

The Company's 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 of the assets to the purchaser and (v)
allows the Company to retain the assets after the VPPs volumetric quantities
have been delivered.

Canada and Shelf Gulf of Mexico. During 2005, the Company sold its
interests in the Martin Creek and Conroy Black areas of northeast British
Columbia and the Lookout Butte area of southern Alberta for net proceeds of
$197.2 million, resulting in a gain of $138.3 million. During 2005, the Company
also sold all of its interests in certain oil and gas properties on the Gulf of
Mexico shelf for net proceeds of $59.2 million, resulting in a gain of $27.9
million. The historic results of these properties and the related gains on
disposition are reported as discontinued operations.

Gabon divestiture. In 2005, the Company closed the sale of the shares in a
Gabonese subsidiary that owns the interest in the Olowi block for $47.9 million
of net proceeds, resulting in a gain of $47.5 million with no associated income
tax effect either in Gabon or the United States. In addition, Pioneer retains
the potential, under certain circumstances, to receive additional payments for
production discovered from deeper reservoirs on the block, if any.

Results of Operations

Oil and gas revenues. Oil and gas revenues totaled $1.6 billion, $1.5
billion and $1.0 billion during 2006, 2005 and 2004, respectively. The revenue
increase during 2006, as compared to 2005, was due to a 69 percent increase in
reported oil prices, including the effects of commodity price hedges and VPP
deliveries, and an 11 percent increase in NGL prices. Partially offsetting the
effects of increased oil and NGL prices was an 11 percent decrease in reported
gas prices, including the effects of commodity price hedges and VPP deliveries,
and a three percent decrease in average daily sales volumes on a BOE basis. The
revenue increase during 2005, as compared to 2004, was due to a 19 percent
increase in reported oil prices, a 27 percent increase in NGL prices and a 42
percent increase in reported gas prices, including the effects of commodity
price hedges and VPP deliveries, along with increased production in 2005 on a
BOE basis.

A significant factor contributing to the increases in reported oil prices
and decreases in reported oil sales volumes in 2006 as compared to 2005 was the
initiation of first deliveries of oil volumes under the Company's VPP agreements
in January 2006. Similarly, reported gas prices and decreases in gas sales
volumes in 2006 and 2005 as compared to 2004 were impacted by the initiation of
first deliveries of gas volumes under the Company's VPP agreements during the
first half of 2005 offset by the decline in underlying gas prices. In accordance
with GAAP, VPP deliveries result in VPP deferred revenue amortization being
recognized in oil and gas revenues with no associated sales volumes being
recorded.

The following table provides average daily sales volumes from continuing
operations, including the effects of delivery of the VPP volumes, by geographic
area and in total, for 2006, 2005 and 2004:

Year Ended December 31,
-------------------------------
2006 2005 2004
-------- -------- --------

Oil (Bbls):
United States.................. 17,716 21,942 21,863
Canada......................... 311 210 72
South Africa................... 4,127 6,588 9,368
Tunisia........................ 2,386 3,477 2,308
-------- -------- -------
Worldwide...................... 24,540 32,217 33,611
======== ======== =======
NGLs (Bbls):
United States.................. 18,488 17,403 19,678
Canada......................... 463 503 425
-------- -------- -------
Worldwide...................... 18,951 17,906 20,103
======== ======== =======
Gas (Mcf):
United States.................. 284,732 271,033 209,371
Canada......................... 43,420 36,427 25,606
South Africa................... -- -- --
Tunisia........................ 1,195 -- --
-------- -------- -------
Worldwide...................... 329,347 307,460 234,977
======== ======== =======
Total (BOE):
United States.................. 83,659 84,517 76,437
Canada......................... 8,011 6,784 4,764
South Africa................... 4,127 6,588 9,368
Tunisia........................ 2,585 3,477 2,308
-------- -------- -------
Worldwide...................... 98,382 101,366 92,877
======== ======== =======

On a BOE basis, average daily production for 2006, as compared to 2005,
increased by 18 percent in Canada, while average daily production decreased by
one percent in the United States and by 33 percent in Africa. Average daily per
BOE production for 2005, as compared to 2004, increased by 11 percent and 42
percent in the United States and Canada, respectively, and decreased by 14
percent in Africa.

Average daily production in the United States was slightly lower during
2006, as compared to 2005, primarily due to a 126 percent increase in VPP oil
and gas deliveries on a BOE basis, partially offset by accelerated development
drilling in core areas. The increase in United States production volumes during
2005, as compared to 2004, was primarily due to production from properties
acquired in the Evergreen merger, partially offset by first deliveries of VPP
gas volumes during 2005.

Canadian average daily sales volumes increased during 2006, as compared to
2005, primarily due to the significant drilling activity in the CBM Horseshoe
Canyon area. The increase in Canadian production volumes during 2005, as
compared to 2004, was primarily due to new production from Canadian properties
acquired in the Evergreen merger and production from new wells drilled during
the 2004 - 2005 winter drilling program.

Production declined in Africa during 2006 and 2005 primarily due to (i)
normal production declines from producing properties in South Africa and
Tunisia, partially offset by drilling success in Tunisia and (ii) the Company's
interest in the Adam Concession in Tunisia being reduced in 2006 from 24 percent
to 20 percent in accordance with the terms of the concession agreement. In
Tunisia, the Company recorded gas sales volumes and revenue for the first time
after finalizing a gas sales arrangement during 2006.

The following table provides average daily sales volumes from discontinued
operations during 2006, 2005 and 2004:

Year Ended December 31,
----------------------------------
2006 2005 2004
-------- -------- --------

Oil (Bbls):
United States..................... 2,400 5,280 4,774
Argentina......................... 2,515 7,869 8,534
Canada............................ -- 28 65
-------- -------- --------
Worldwide......................... 4,915 13,177 13,373
======== ======== ========
NGLs (Bbls):
United States..................... -- 65 60
Argentina......................... 421 1,824 1,546
Canada............................ -- 112 492
-------- -------- --------
Worldwide......................... 421 2,001 2,098
======== ======== ========
Gas (Mcf):
United States..................... 36,038 230,171 312,468
Argentina......................... 43,905 137,032 121,654
Canada............................ 14 6,489 16,261
-------- -------- --------
Worldwide......................... 79,957 373,692 450,383
======== ======== ========
Total (BOE):
United States..................... 8,406 43,707 56,912
Argentina......................... 10,253 32,531 30,356
Canada............................ 2 1,221 3,267
-------- -------- --------
Worldwide......................... 18,661 77,459 90,535
======== ======== ========

The following table provides average reported prices from continuing
operations, including the results of hedging activities and the amortization of
VPP deferred revenue, and average realized prices from continuing operations,
excluding the results of hedging activities and the amortization of VPP deferred
revenue, by geographic area and in total, for 2006, 2005 and 2004:

Year Ended December 31,
--------------------------------
2006 2005 2004
-------- -------- --------

Average reported prices:
Oil (per Bbl):
United States........................ $ 65.73 $ 32.01 $ 29.53
Canada............................... $ 65.57 $ 52.12 $ 48.37
South Africa......................... $ 65.92 $ 53.01 $ 37.87
Tunisia.............................. $ 63.16 $ 52.98 $ 39.14
Worldwide............................ $ 65.51 $ 38.70 $ 32.56
NGL (per Bbl):
United States........................ $ 35.24 $ 31.72 $ 25.05
Canada............................... $ 51.47 $ 45.79 $ 32.03
Worldwide............................ $ 35.64 $ 32.12 $ 25.20
Gas (per Mcf):
United States........................ $ 6.15 $ 6.94 $ 4.99
Canada............................... $ 6.75 $ 7.67 $ 4.72
Tunisia.............................. $ 5.97 $ -- $ --
Worldwide............................ $ 6.23 $ 7.02 $ 4.96
Average realized prices:
Oil (per Bbl):
United States........................ $ 62.92 $ 54.05 $ 39.22
Canada............................... $ 65.57 $ 52.12 $ 48.37
South Africa......................... $ 65.74 $ 53.01 $ 38.60
Tunisia.............................. $ 63.16 $ 52.98 $ 39.14
Worldwide............................ $ 63.45 $ 53.71 $ 39.06
NGL (per Bbl):
United States........................ $ 35.24 $ 31.72 $ 25.05
Canada............................... $ 51.47 $ 45.79 $ 32.03
Worldwide............................ $ 35.64 $ 32.12 $ 25.20
Gas (per Mcf):
United States........................ $ 5.96 $ 7.26 $ 5.46
Canada............................... $ 6.61 $ 7.67 $ 5.37
Tunisia.............................. $ 5.97 $ -- $ --
Worldwide............................ $ 6.04 $ 7.31 $ 5.45

Hedging activities. The Company, from time to time, 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. During 2006, 2005 and 2004, the
Company's commodity price hedges decreased oil and gas revenues from continuing
operations by $149.0 million, $284.9 million and $121.9 million, respectively.
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 J 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 2006, 2005 and 2004 from the Company's
hedging activities, the Company's open and terminated hedge positions at
December 31, 2006 and descriptions of the Company's commodity hedge derivatives.
Also see "Item 7A. Quantitative and Qualitative Disclosures About Market Risk"
for additional disclosures about the Company's commodity related derivative
financial instruments.

Subsequent to December 31, 2006, the Company reduced its oil hedge
positions by terminating certain oil swap contracts and increased its gas hedge
position by adding additional gas swap contracts. See Note J of Notes to

Consolidated Financial Statements included in "Item 8. Financial Statements and
Supplementary Data" for information concerning these changes in the oil and gas
hedge positions.

Deferred revenue. During 2006 and 2005, the Company's recognition of
previously deferred VPP revenue increased oil and gas revenues from continuing
operations by $190.3 million and $75.8 million, respectively. The Company's
amortization of deferred VPP revenue is scheduled to increase 2007 oil and gas
revenues by $181.2 million. See Note T of Notes to Consolidated Financial
Statements included in "Item 8. Financial Statements and Supplementary Data" for
specific information regarding the Company's VPPs.

Interest and other income. The Company's interest and other income totaled
$58.7 million, $31.5 million and $2.2 million during 2006, 2005 and 2004,
respectively. The $27.2 million increase during 2006, as compared to 2005, is
primarily attributable to (i) $13.8 million of hedge ineffectiveness gains
recorded during 2006, (ii) a $13.2 million increase in interest income primarily
attributable to the investing the proceeds from the Argentine and deepwater Gulf
of Mexico divestitures during 2006 and (iii) $5.6 million of Alaskan exploration
incentive credits received in 2006, offset by a $6.6 million decrease in
business interruption insurance claims primarily attributable to the 2005 Fain
plant fire in the West Panhandle field. The increase in interest and other
income during 2005, as compared to 2004, is primarily attributable to the
recognition of $14.2 million in business interruption insurance claims related
to the Fain plant fire. See Note M of Notes to Consolidated Financial Statements
included in "Item 8. Financial Statements and Supplementary Data" for additional
information regarding interest and other income.

Gain (loss) on disposition of assets. The Company recorded a net loss on
disposition of assets of $7.9 million in 2006, as compared to net gains of $59.8
million and $39,000 during 2005 and 2004, respectively.

In 2005, the gain was primarily related to (i) the sale of the stock of a
subsidiary that owned the interest in the Olowi block in Gabon, which resulted
in a $47.5 million gain and (ii) a $14 million insurance settlement on the
Company's East Cameron facility that was destroyed by Hurricane Rita, which
resulted in a $9.7 million gain.

During 2006, the Company recognized gains on the sale of its interest in
certain oil and gas properties in the deepwater Gulf of Mexico and its Argentina
assets of approximately $737.2 million. During 2005, the Company also recognized
gains on the sale of certain assets in Canada and the shelf of the Gulf of
Mexico of approximately $166.2 million. However, pursuant to SFAS 144, these
gains and the results of operations from the assets are presented as
discontinued operations.

The net cash proceeds from asset divestitures during 2006, 2005 and 2004
were used, together with net cash flows provided by operating activities, to
fund additions to oil and gas properties and stock repurchase programs, and to
reduce outstanding indebtedness. See Notes N and V 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's oil and gas production costs
totaled $398.3 million, $346.4 million and $224.9 million during 2006, 2005 and
2004, 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 2006 by 18 percent as compared to 2005 primarily due to (i) the impact of
a 126 percent increase in delivered volumes under VPP agreements, for which the
Company bears all associated production costs and records no associated sales
volumes (representing a per BOE production cost impact of approximately $1.50
during 2006 as compared to $.59 during 2005), (ii) general inflation of field
service and supply costs and (iii) increases in production and ad valorem taxes
and field utility costs due to increasing commodity and utility prices.

Total production costs per BOE increased during 2005 by 41 percent as
compared to 2004. The increase in total production costs per BOE during 2005 as
compared to 2004 was primarily attributable to (i) an increase in production and
ad valorem taxes as a result of higher commodity prices, (ii) higher Canadian
gas transportation fees, (iii) the retention of production costs related to VPP
volumes sold (approximately $.59 per BOE, during 2005), (iv) new production
added from the Evergreen merger, which are relatively higher per BOE operating
cost properties and (v) increases in field service and supply costs primarily
associated with rising commodity prices.

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 2006, 2005 and 2004:

Year Ended December 31,
----------------------------
2006 2005 2004
------ ------ ------

Lease operating expenses.................... $ 6.23 $ 5.06 $ 3.87
Third-party transportation charges.......... 1.22 1.03 .44
Taxes:
Ad valorem................................. 1.24 1.09 .82
Production................................. 1.69 1.61 1.10
Workover costs.............................. .71 .57 .39
------ ------ ------
Total production costs..................... $11.09 $ 9.36 $ 6.62
====== ====== ======

Year Ended December 31,
----------------------------
2006 2005 2004
------ ------ ------

United States............................... $10.62 $ 8.99 $ 6.24
Canada...................................... $16.82 $14.83 $10.79
South Africa................................ $14.47 $11.79 $ 8.31
Tunisia..................................... $ 3.41 $ 3.20 $ 3.58
Worldwide................................... $11.09 $ 9.36 $ 6.62

Depletion, depreciation and amortization expense. The Company's total DD&A
expense was $10.01, $8.11 and $6.81 per BOE for 2006, 2005 and 2004,
respectively. Depletion expense, the largest component of DD&A expense, was
$9.34, $7.56 and $6.46 per BOE during 2006, 2005 and 2004, respectively. During
2006, the increase in per BOE depletion expense was primarily due to (i) a
generally increasing trend in the Company's oil and gas properties' cost bases
per BOE of proved and proved developed reserves as a result of cost inflation in
drilling rig rates and drilling supplies, (ii) the aforementioned sale of proved
reserves under VPP agreements, for which the Company removed proved reserves
with no corresponding decrease in cost basis, (iii) a $.50 per BOE increase in
Tunisian depletion, primarily associated with 2006 and 2005 decreases in the
Company's interest in the Adam Concession, offset by (iv) a $3.91 per BOE
decrease in South Africa depletion, primarily associated with 2006 and 2005
positive revisions to proved reserves based on well performance.

During 2005, the increase in per BOE depletion expense was due to
relatively higher per BOE cost basis Rocky Mountains area production acquired in
the Evergreen merger and a higher depletion rate for the Hugoton and Spraberry
fields as a result of the VPP volumes sold.

The following table provides depletion expense per BOE from continuing
operations by geographic area for 2006, 2005 and 2004:

Year Ended December 31,
----------------------------
2006 2005 2004
------ ------ ------

United States............................... $ 9.07 $ 7.10 $ 5.34
Canada...................................... $15.39 $12.71 $12.93
South Africa................................ $ 6.28 $10.19 $12.86
Tunisia..................................... $ 4.25 $ 3.75 $ 4.43
Worldwide................................... $ 9.34 $ 7.56 $ 6.46

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 2005 and 2004, the Company recognized noncash impairment
charges of $644 thousand and $39.7 million, respectively, to reduce the carrying
value of its Gabonese Olowi field assets as development of the discovery was
canceled. See "Critical Accounting Estimates" below and Notes B and S 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.

Exploration, abandonments, geological and geophysical costs. 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 2006, 2005 and 2004:

United South
States Canada Africa Tunisia Other Total
--------- -------- -------- --------- --------- ---------

Year ended December 31, 2006:
Geological and geophysical....... $ 79,141 $ 5,287 $ 288 $ 8,402 $ 21,536 $ 114,654
Exploratory dry holes............ 80,024 6,438 7,227 6,214 15,845 115,748
Leasehold abandonments and other. 13,696 2,223 -- -- 17,824 33,743
--------- -------- -------- --------- --------- ---------
$ 172,861 $ 13,948 $ 7,515 $ 14,616 $ 55,205 $ 264,145
========= ======== ======== ========= ========= =========

Year ended December 31, 2005:
Geological and geophysical....... $ 63,707 $ 4,452 $ 283 $ -- $ 34,070 $ 102,512
Exploratory dry holes............ 24,462 3,468 804 9,041 9,136 46,911
Leasehold abandonments and other. 8,957 1,625 125 -- 3,193 13,900
--------- -------- -------- --------- --------- ---------
$ 97,126 $ 9,545 $ 1,212 $ 9,041 $ 46,399 $ 163,323
========= ======== ======== ========= ========= =========

Year ended December 31, 2004:
Geological and geophysical....... $ 49,722 $ 4,047 $ 868 $ -- $ 13,965 $ 68,602
Exploratory dry holes............ 1,151 11,131 (338) -- 24,798 36,742
Leasehold abandonments and other. 4,138 3,883 -- -- 6 8,027
--------- -------- -------- --------- --------- ---------
$ 55,011 $ 19,061 $ 530 $ -- $ 38,769 $ 113,371
========= ======== ======== ========= ========= =========

During 2006, significant components of the Company's dry hole provisions
and leasehold abandonments expense included (i) $34.0 million of costs
associated with the Company's unsuccessful exploratory well on its Block 256
prospect offshore Nigeria, including $17.8 million of associated unproved
leasehold impairment, (ii) $21.6 million of dry hole provisions recorded for the
Company's unsuccessful Cronus, Storms and Antigua prospects in the North Slope
area of Alaska, (iii) $18.4 million of dry hole provisions and abandonment costs
recognized on prospects drilled in prior periods that were being evaluated for
commerciality, including $7.2 million of costs associated with the Company's
Boomslang prospect offshore South Africa, $7.0 million of costs associated with
two discoveries on the Gulf of Mexico shelf in 2005 and $4.2 million of costs
associated with the Company's Anaguid permit in Tunisia, (iv) $16.0 million of
dry hole provision and unproved property impairment recognized on the Company's
unsuccessful Norphlet prospect in Mississippi, (v) a $14.3 million unsuccessful
well on the Company's Flying Cloud prospect in the Gulf of Mexico and (vi) $6.4
million of unsuccessful exploratory wells in Canada. During 2006, the Company
completed and evaluated 414 exploration/extension wells, 384 of which were
successfully completed as discoveries.

Significant components of the Company's dry hole expense during 2005
included (i) $21.2 million related to Alaskan well costs, (ii) $9.5 million
associated with an unsuccessful Nigerian well, (iii) $3.5 million attributable
to an unsuccessful suspended well in the Company's El Hamra permit in Tunisia,
(iv) $5.1 million attributable to an unsuccessful suspended well in the
Company's Anaguid permit in Tunisia and (v) various other exploratory wells.
During 2005, the Company completed and evaluated 180 exploratory/extension
wells, 149 of which were successfully completed as discoveries.

Significant components of the Company's dry hole expense during 2004
included (i) $19.0 million on the Company's Gabonese Olowi prospect and (ii)
$5.8 million associated with the Company's Bravo prospect offshore Equatorial
Guinea. During 2004, the Company completed and evaluated 103
exploratory/extension wells, 58 of which were successfully completed as
discoveries.

General and administrative expense. General and administrative expense
totaled $121.8 million, $114.2 million and $73.2 million during 2006, 2005 and
2004, respectively. The increase in general and administrative expense during
2006, as compared to 2005, was primarily due to a full year effect of the 2005
staff increases associated with the Evergreen acquisition. The Company continues
to review its general and administrative expenses and remains focused on
initiatives to control its expenditures.

The increase in general and administrative expense during 2005, as compared
to 2004, 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 2005.

Interest expense. Interest expense was $107.0 million, $126.1 million and
$102.0 million during 2006, 2005 and 2004, respectively. The weighted average
interest rate on the Company's indebtedness for the year ended December 31, 2006
was 6.7 percent, as compared to 6.5 percent and 5.4 percent for the years ended
December 31, 2005 and 2004, respectively, including the effects of interest rate
derivatives. The decrease in interest expense for 2006 as compared to 2005 was
primarily due to the repayment of portions of the Company's outstanding
borrowings under the Company's credit facility with proceeds from the
divestiture of the deepwater Gulf of Mexico and Argentine assets and an $11.1
million increase in interest capitalized on the Company's Oooguruk development
project in Alaska and the South Coast Gas project in South Africa, partially
offset by a $4.1 million decrease in the amortization of interest rate hedge
gains.

The increase in interest expense for 2005 as compared to 2004 was primarily
due to increased average borrowings under the Company's lines of credit,
primarily as a result of the cash portion of the consideration paid in the
Evergreen merger and $949.3 million of stock repurchases completed during 2005,
a $15.2 million decrease in the amortization of interest rate hedge gains, the
assumption of $300 million of notes in connection with the Evergreen merger and
higher interest rates in 2005.

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 and interest expense.

Hurricane activity, net. The Company recorded net hurricane related
activity expenses of $32.0 million and $39.8 million during 2006 and 2005,
respectively, associated with the Company's East Cameron platform facility,
located on the Gulf of Mexico shelf, that was destroyed during 2005 by Hurricane
Rita.

The Company does not plan to rebuild the facility based on the economics of
the field. During the fourth quarter of 2006, the Company's application to "reef
in-place" a substantial portion of the East Cameron debris was denied. As a
result, the Company currently estimates that it will cost approximately $119
million to reclaim and abandon the East Cameron facility. The estimate to
reclaim and abandon the East Cameron facility is based upon an analysis and fee
proposal prepared by a third-party engineering firm for the majority of the work
and an estimate by the Company for the remainder. During 2006 and 2005, the
Company recorded additional abandonment obligation charges of $75 million and
$39.8 million, respectively. The operations to reclaim and abandon the East
Cameron facilities began in January 2007 and the Company expects to incur a
substantial portion of the costs in 2007. The Company expects that a substantial
portion of the total estimated cost to reclaim and abandon the facility will be
covered by insurance, including 100 percent of the debris removal costs.
Consequently, the Company has recorded a $43.0 million insurance recovery
receivable corresponding to the estimated debris removal costs.

Other expenses. Other expenses were $36.3 million during 2006, as compared
to $99.4 million during 2005 and $28.4 million during 2004. The $63.1 million
decrease in other expenses during 2006, as compared to 2005, is primarily
attributable to (i) a $53.2 million decrease in hedge ineffectiveness charges
and other derivative losses and (ii) a $17.9 million decrease in loss on early
extinguishment of portions of the Company's senior notes.

The increase in other expenses during 2005, as compared to 2004, is
primarily attributable to (i) a $43.9 million increase in hedge ineffectiveness
and other derivative losses and (ii) a $26.0 million loss on the redemption and
tender of portions of the Company's senior notes. See Note O 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.

Income tax provision. The Company recognized income tax provisions on
continuing operations of $136.7 million, $155.8 million and $63.1 million during
2006, 2005 and 2004, respectively. The Company's effective tax rates for 2006,
2005 and 2004 were 44.2 percent, 44.5 percent and 31.9 percent, respectively, as
compared to the combined United States federal and state statutory rates of
approximately 36.5 percent. The effective tax rates of 2006 and 2005 differ from
the combined United States federal and state statutory rates primarily due to:

o foreign tax rates,
o adjustments to the deferred tax liability for changes in enacted tax laws
and rates, as discussed below,
o statutes in foreign jurisdictions that differ from those in the United
States,
o recognition of $8.4 million of deferred tax benefit during 2006 as a
result of the conversion of senior convertible notes prior to the
Company's repayment of the debt principal,
o recognition of $7.2 million of taxes during 2005 associated with the
repatriation of foreign earnings pursuant to the American Jobs Creation
Act of 2004 and
o expenses for unsuccessful well costs and associated acreage costs in
foreign locations where the Company does not expect to receive income tax
benefits.

During May 2006, the State of Texas enacted legislation that changed the
existing Texas franchise tax from a tax based on net income or taxable capital
to an income tax based on a defined calculation of gross margin (the "Texas
margin tax"). Also, during 2006, the Canadian federal and provincial governments
enacted tax rate reductions that will be phased in over several years. SFAS No.
109, "Accounting for Income Taxes" requires that deferred tax balances be
adjusted to reflect tax rate changes during the periods in which the tax rate
changes are enacted. The adjustment due to the enactment of the Texas margin tax
and the Canadian tax rate changes resulted in a $13.5 million United States tax
expense and a $10.2 million Canadian tax benefit during the year ended December
31, 2006, respectively.

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

Discontinued operations. During 2005 and 2006, the Company sold its
interests in the following oil and gas asset groups:

Country Description of Asset Groups Date Divested
------- --------------------------- -------------

Canada Martin Creek, Conroy Black and
Lookout Butte fields May 2005

United States Two Gulf of Mexico shelf fields August 2005

United States Deepwater Gulf of Mexico fields March 2006

Argentina Argentine assets April 2006

The Company recognized income from discontinued operations of $567.4
million during 2006, as compared to $339.9 million during 2005 and $178.4
million during 2004. Pursuant to SFAS 144, the results of operations of these
properties and the related gains on disposition are reported as discontinued
operations. See Note V of Notes to Consolidated Financial Statements in "Item 8.
Financial Statements and Supplementary Data" for additional data on discontinued
operations.

Capital Commitments, Capital Resources and Liquidity

Capital commitments. The Company's primary needs for cash are for
exploration, development and acquisition of oil and gas properties, repayment of
contractual obligations and working capital obligations. Funding for
exploration, development and acquisition 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 nonstrategic

assets or alternative financing sources as discussed in "Capital resources" and
"Financing activities" below. Generally, funding for the Company's working
capital obligations is provided by internally-generated cash flows.

Payments for acquisitions, net of cash acquired. In 2004, the Company paid
$880.4 million of cash, net of $12.1 million of cash acquired, and issued shares
of the Company's common stock to complete the Evergreen merger. 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 Note C of Notes to
Consolidated Financial Statements included in "Item 8. Financial Statements and
Supplementary Data", the Company financed the cash costs utilizing credit
facilities.

Oil and gas properties. The Company's cash expenditures for additions to
oil and gas properties during 2006, 2005 and 2004 totaled $1.4 billion, $1.1
billion and $562.9 million, respectively. The Company's 2006 expenditures for
additions to oil and gas properties were funded by $754.8 million of net cash
provided by operating activities and by a portion of the net proceeds from the
disposition of deepwater Gulf of Mexico and Argentine assets. The Company's 2005
and 2004 expenditures for additions to oil and gas properties were internally
funded by $1.3 billion and $1.1 billion, respectively, of net cash provided by
operating activities.

The Company strives to maintain its indebtedness at levels which will
provide sufficient financial flexibility to take advantage of future
opportunities. The Company's capital budget for 2007 is approximately $1.1
billion. The Company believes that Credit Agreement borrowings and net cash
provided by operating activities during 2007, based on the current price
environment, will be sufficient to fund the 2007 capital expenditures budget.

Off-balance sheet arrangements. 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, 2006, the
material off-balance sheet arrangements and transactions that the Company has
entered into include (i) undrawn letters of credit, (ii) operating lease
agreements, (iii) drilling commitments, (iv) VPP obligations (to physically
deliver volumes and pay related lease operating expenses in the future) and (v)
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. Other than the
off-balance sheet arrangements described above, the Company has no transactions,
arrangements or other relationships with unconsolidated entities or other
persons that are reasonably likely to materially affect the Company's liquidity
or availability of or requirements for capital resources. See "Contractual
obligations" below for more information regarding the Company's off-balance
sheet arrangements.

Contractual obligations. The Company's contractual obligations include
long-term debt, operating leases, drilling commitments (including commitments to
pay day rates for drilling rigs), derivative obligations, other liabilities,
transportation commitments and VPP obligations.

The following table summarizes by period the payments due by the Company
for contractual obligations estimated as of December 31, 2006:

Payments Due by Year
--------------------------------------------------
2008 and 2010 and
2007 2009 2011 Thereafter
---------- ---------- ---------- -----------
(in thousands)

Long-term debt (a)................. $ 32,075 $ 3,777 $ 328,000 $1,232,985
Operating leases (b)............... 29,065 27,906 7,429 --
Drilling commitments (c)........... 330,381 307,265 -- --
Derivative obligations (d)......... 78,233 121,126 -- --
Other liabilities (e).............. 170,156 70,932 25,750 108,660
Transportation commitments (f)..... 68,630 137,396 130,992 170,546
VPP obligations (g)................ 181,232 306,044 135,166 42,069
---------- ---------- ---------- ----------
$ 889,772 $ 974,446 $ 627,337 $1,554,260
========== ========== ========== ==========

----------

(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 I of Notes to Consolidated Financial Statements included in "Item
8. Financial Statements and Supplementary Data".

(c) Drilling commitments represent future minimum expenditure commitments for
drilling rig services and well commitments under contracts to which the
Company was a party on December 31, 2006.

(d) Derivative obligations represent net liabilities for oil and gas commodity
derivatives that were valued as of December 31, 2006. These liabilities
include $131.1 million of 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 J 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, I and L 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 I of Notes to Consolidated Financial
Statements included in "Item 8. Financial Statements and Supplementary
Data" for additional information regarding the Company's transportation
commitments.

(g) These amounts represent the amortization of the deferred revenue associated
with the VPPs. The Company's ongoing obligation is to deliver the specified
volumes sold under the VPPs free and clear of all associated production
costs and capital expenditures. See Note T of Notes to Consolidated
Financial Statements included in "Item 8. Financial Statements and
Supplementary Data".

Environmental contingency. A subsidiary of the Company has been notified by
a letter from the Texas Commission on Environmental Quality ("TCEQ") dated
August 24, 2005 that the TCEQ considers the subsidiary to be a potentially
responsible party with respect to the Dorchester Refining Company State
Superfund Site located in Mount Pleasant, Texas. In connection with the
acquisition of oil and gas assets in 1991, the Company acquired a group of
companies, one of which was an entity that had owned a refinery located at the
Mount Pleasant site from 1977 until 1984. According to the TCEQ, this refinery
was responsible for releases of hazardous substances into the environment.
Pursuant to applicable Texas law, the Company's subsidiary, which does not own
any material assets or conduct any material operations, may be subject to
strict, joint and several liability for the costs of conducting a study to
evaluate potential remedial options and for the costs of performing any
remediation ultimately required by the TCEQ. The Company does not know the
nature and extent of the alleged contamination, the potential costs of
remediation or the portion, if any, of such costs that may be allocable to the
Company's subsidiary; however, the Company has noted that there appear to be
other operators or owners who may share responsibility for these costs and 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,
financial position or future annual results of operations. See Note I of Notes
to Consolidated Financial Statements included in "Item 8. Financial Statements
and Supplementary Data" for additional information regarding this matter as well
as other environmental and legal contingencies involving the Company.

Capital resources. The Company's primary capital resources are net cash
provided by operating activities, proceeds from financing activities and
proceeds from sales of nonstrategic assets. The Company expects that these
resources will be sufficient to fund its capital commitments during 2007 and for
the foreseeable future.

Asset divestitures. During March 2006, the Company sold all of its
interests in certain oil and gas properties in the deepwater Gulf of Mexico for
net proceeds of $1.2 billion, resulting in a gain of $726.2 million. During
April 2006, the Company sold its Argentine assets for net proceeds of $669.6
million, resulting in a gain of $10.9 million. The results of operations for
these divestitures are included in the Company's discontinued operations. The
net cash proceeds from these divestitures were used to reduce outstanding
indebtedness under the Credit Agreement, to fund a portion of additions to oil
and gas properties, for stock repurchases and for general corporate purposes.

During May 2005, the Company sold all of its interests in the Martin Creek,
Conroy Black and Lookout Butte oil and gas properties in Canada for net proceeds
of $197.2 million, resulting in a gain of $138.3 million. During August 2005,
the Company sold all of its interests in certain oil and gas properties on the
Gulf of Mexico shelf for net proceeds of $59.2 million, resulting in a gain of
$27.9 million. During October 2005, the Company sold all of its shares in a
subsidiary that owns the interest in the Olowi block in Gabon for net proceeds
of $47.9 million, resulting in a gain of $47.5 million. The net cash proceeds
from the 2005 divestitures were used to reduce outstanding indebtedness.

During January 2005, the Company sold 20.5 MMBOE of proved reserves, by
means of two VPPs for net proceeds of $592.3 million, including the assignment
of the Company's obligations under certain derivative hedge agreements. Proceeds
from the VPPs were used to reduce outstanding indebtedness.

During April 2005, the Company sold 7.3 MMBOE of proved reserves, by means
of another VPP for net proceeds of $300.3 million, including the assignment of
the Company's obligations under certain derivative hedge agreements. Proceeds
from the VPP were used to reduce outstanding indebtedness.

See Note T of Notes to Consolidated Financial Statements included in "Item
8. Financial Statements and Supplementary Data" for additional information
regarding the Company's VPPs.

Operating activities. Net cash provided by operating activities during
2006, 2005 and 2004 was $754.8 million, $1.3 billion and $1.1 billion,
respectively. The decrease in net cash provided by operating activities in 2006,
as compared to that of 2005, was primarily due to the loss of cash flow from the
aforementioned asset divestitures. The increase in net cash provided by
operating activities in 2005, as compared to that of 2004, was primarily due to
higher commodity prices and the operations acquired in the Evergreen merger.

Investing activities. Net cash provided by investing activities during 2006
was $145.5 million, as compared to net cash provided by investing activities of
$84.7 million during 2005 and net cash used in investing activities of $1.5
billion during 2004. The increase in net cash provided by investing activities
during 2006, as compared to 2005, was primarily due to a $396.2 million increase
in proceeds from disposition of assets, partially offset by a $280.6 million
increase in additions to oil and gas properties. The decrease in net cash used
in investing activities during 2005, as compared to 2004, was primarily due to
(i) $1.2 billion in proceeds from asset divestitures in 2005, which included
$892.6 million of net proceeds received from VPPs sold during 2005 and (ii)
$880.4 million of cash consideration paid in 2004 in connection with the
Evergreen merger offset by an increase of $560.4 million in additions to oil and
gas properties. See "Results of Operations" above and Note N 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 used in financing activities was $913.5
million and $1.4 billion during 2006 and 2005, respectively. Net cash provided
by financing activities during 2004 was $414.3 million. During 2006, significant
components of financing activities included $554.7 million of net cash used to
repay long-term borrowings, $348.9 million of net cash used to purchase 8.9
million shares of stock and $31.7 million of dividend payments, partially offset
by $17.4 million of proceeds from the exercise of long-term incentive plan stock
options and employee stock purchases. During 2005, financing activities were
comprised of $353.6 million of net principal repayments on long-term debt, $60.1
million of payments of other noncurrent liabilities, primarily comprised of cash
settlements of acquired hedge obligations, $30.3 million of dividends paid and
$949.3 million of stock repurchases, partially offset by $41.6 million of
proceeds from the exercise of long-term incentive plan stock options and
employee stock purchases. 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, primarily comprised of settlements of
fair value and acquired hedge obligations and other financial obligations, $92.3
million of stock repurchases and $26.6 million of dividends paid, partially
offset by $35.1 million of proceeds from the exercise of long-term incentive
plan stock options and employee stock purchases.

During September 2005, the Company announced that the Board had approved a
share repurchase program authorizing the purchase of up to $1 billion of the
Company's common stock. During 2006 and 2005, the Company expended a total of
$348.9 million to acquire 8.9 million shares of stock and $949.3 million to
acquire 20.0 million shares of stock, respectively, of which $345.3 million and
$940.3 million, respectively, were repurchased pursuant to the repurchase
programs. In February 2007, the Board approved a new share repurchase program
authorizing the purchase of up to $300 million of the Company's common stock.

During May 2006, the Company issued $450 million of 6.875% Notes for net
proceeds of $447.4 million. The Company used the net proceeds, in part, from the
6.875% Notes to repurchase $346.2 million of its 6.50% Notes and for general
corporate purposes.

During 2006, holders of all of the $100 million of 4 3/4% Senior
Convertible Notes due 2021 exercised their conversion rights. Associated
therewith, the Company paid $79.9 million in cash, issued 2.3 million shares of
common stock and recorded a $22.0 million increase to stockholders' equity.

During September 2005, the Company entered into an amended credit facility
that provides for initial aggregate loan commitments of $1.5 billion and a
five-year term (the "Credit Agreement"). Effective September 2006, the
participating lenders extended the maturity on $1.395 billion of aggregate loan
commitments under the Credit Agreement to September 30, 2011.

During April 2005, $131.0 million of the Company's 8 7/8% senior notes due
2005 matured and were repaid. During 2005, the Company also redeemed the
remaining $64.0 million and $16.2 million, respectively, of aggregate principal
amount of its 9 5/8% senior notes due 2010 and its 7.50% senior notes due 2012.
During September 2005, the Company accepted tenders to purchase $188.4 million
in principal amount of the 5.875% senior notes due 2012 for $199.9 million. The
Company utilized unused borrowing capacity under its credit facility to fund
these financing activities.

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 Board.

Liquidity. The Company's principal source of short-term liquidity is the
Credit Agreement. There was $328.0 million of outstanding borrowings under the
Credit Agreement as of December 31, 2006. Including $150.2 million of undrawn
and outstanding letters of credit under the Credit Agreement, the Company had
$1.0 billion of unused borrowing capacity as of December 31, 2006.

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"), which are subject to regular reviews. During 2005, S&P lowered the
Company's corporate credit rating to BB+ with a stable outlook from BBB-. During
2006, Moody's cut the Company's corporate credit rating to Ba1 with a negative
outlook from Baa3. 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. As a result of the downgrades, the interest
rate and fees the Company pays on the Credit Agreement have increased and
additional debt covenant requirements under the Credit Agreement were triggered.
During 2006, as a result of the Company's downgrades by the rating agencies, the
Company issued additional letters of credits of approximately $79.1 million
pursuant to agreements that contain provisions with rating triggers. The
individual downgrades are not expected to materially affect the Company's
financial position or liquidity, but could negatively impact the Company's
ability to obtain additional financing or the interest rate, fees and other
terms associated with such additional financing.

Book capitalization and current ratio. The Company's book capitalization at
December 31, 2006 was $4.5 billion, consisting of debt of $1.5 billion and
stockholders' equity of $3.0 billion. Consequently, the Company's debt to book
capitalization decreased to 33 percent at December 31, 2006 from 48 percent at
December 31, 2005. The Company's ratio of current assets to current liabilities
was .60 to 1.00 at December 31, 2006, essentially unchanged from December 31,
2005.

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.

Asset retirement obligations. The Company has significant obligations to
remove tangible equipment and facilities and to restore land or seabed at the
end of oil and gas production operations. The Company's removal and restoration
obligations are primarily associated with plugging and abandoning wells and
removing and disposing of offshore oil and gas platforms. Estimating the future
restoration and removal costs is difficult and requires management to make
estimates and judgments because most of the removal obligations are many years
in the future and contracts and regulations often have vague descriptions of
what constitutes removal. Asset removal technologies and costs are constantly
changing, as are regulatory, political, environmental, safety and public
relations considerations.

Inherent in the present value calculation are numerous assumptions and
judgments including the ultimate settlement amounts, inflation factors, credit
adjusted discount rates, timing of settlement and changes in the legal,
regulatory, environmental and political environments. To the extent future
revisions to these assumptions impact the present value of the existing asset
retirement obligations, a corresponding adjustment is made to the oil and gas
property balance. See Notes B and L of Notes to Consolidated Financial
Statements included in "Item 8. Financial Statements and Supplementary Data" for
additional information regarding the Company's asset retirement obligations.

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 2006,
2005 and 2004, the Company recognized exploration, abandonment, geological and
geophysical expense from (i) continuing operations of $264.1 million, $163.3
million and $113.4 million, respectively, and (ii) discontinued operations of
$7.3 million, $63.9 million and $68.3 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:

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, 2006, 2005 and 2004 was prepared by the Company's engineers and
audited by independent petroleum engineers with respect to the Company's major
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 Standardized Measure included in this
Report as of December 31, 2006 is the current market value of the Company's
estimated proved reserves. In accordance with SEC requirements, the Company
based the Standardized Measure 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. See "Item 1A. Risk Factors" for
additional information regarding estimates of proved reserves.

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 proved properties and goodwill for impairment.

Impairment of proved oil and gas properties. The Company reviews its 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 impacts 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.

(ii) The Company is making sufficient progress assessing the reserves and
the economic and operating viability of the project.

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. In April 2006, the Company sold
its assets in Argentina for proceeds of $669.6 million, resulting in a gain of
$10.9 million. Prior to the divestiture, the accounting for and remeasurement of
the Company's Argentine balance sheets as of December 31, 2005 reflect
management's assumptions regarding some uncertainties unique to Argentina's
economic environment. 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, the
timing of repatriations of the sales proceeds and contingent liabilities
associated with the Company's retained obligations and its indemnifications
provided to the purchaser of the assets. 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
deferred tax asset valuation allowances in certain jurisdictions in a future
period. As of December 31, 2006, the Company does not believe there is
sufficient positive evidence to reverse its valuation allowances related to
certain foreign tax jurisdictions.

Goodwill impairment. The Company reviews 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 in the
estimation of proved reserves as described above. See Note B of Notes to
Consolidated Financial Statements included in "Item 8. Financial Statements and
Supplementary Data" for additional information.

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 and regulations, developing information 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 estimable. See Note I 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.

Valuations of defined benefit pension and postretirement plans. The Company
is the sponsor of certain defined benefit pension and postretirement plans. In
accordance with GAAP, the Company is required to estimate the present value of
its unfunded pension and accumulated postretirement benefit obligations. Based
on those values, the Company records the unfunded obligations of those plans and
records ongoing service costs and associated interest expense. The valuation of
the Company's pension and accumulated postretirement benefit obligations
requires management assumptions and judgments as to benefit cost inflation
factors, mortality rates and discount factors. Changes in these factors may
materially change future benefit costs and pension and accumulated
postretirement benefit obligations. See "New Accounting Pronouncements" below

and Note H of Notes to Consolidated Financial Statements included in "Item 8.
Consolidated Financial Statements and Supplementary Data" for additional
information regarding the Company's pension and accumulated postretirement
benefit obligations.

Valuation of stock-based compensation. The Company adopted the "modified
prospective" approach as prescribed under SFAS No. 123(R) on January 1, 2006.
Under this approach, the Company is required to expense all options and other
stock-based compensation that vested during the year of adoption based on the
fair value of the award on the grant date. The calculation of the fair value of
stock-based compensation requires the use of estimates to derive the various
inputs necessary for using the Black-Scholes valuation method elected by the
Company.

New Accounting Pronouncements

The following discussions provide information about new accounting
pronouncements that were issued by the Financial Accounting Standards Board
("FASB") during 2006:

FIN 48. In July 2006, the FASB issued Interpretation No. 48, "Accounting
for Uncertainty in Income Taxes" ("FIN No. 48"). The Interpretation clarifies
the accounting for income taxes by prescribing a minimum recognition threshold
that a tax position is required to meet before being recognized in the financial
statements. FIN No. 48 also provides guidance on measurement, classification,
interim accounting and disclosure. FIN No. 48 is effective for fiscal years
beginning after December 15, 2006. The Company is continuing to assess the
potential impacts of this Interpretation.

SFAS 157. In September 2006, the FASB issued SFAS No. 157, "Fair Value
Measures" ("SFAS 157"). SFAS 157 defines fair value, establishes a framework for
measuring fair value and enhances disclosures about fair value measures required
under other accounting pronouncements, but does not change existing guidance as
to whether or not an instrument is carried at fair value. SFAS 157 is effective
for fiscal years beginning after November 15, 2007. The Company is continuing to
assess the impact of SFAS 157.

SFAS 158. In September 2006, the FASB issued SFAS 158, "Employers'
Accounting for Defined Benefit Pension and other Postretirement Plans" ("SFAS
158"). Under SFAS 158, a business entity that sponsors one or more
single-employer defined benefit plans is required to:

o recognize the funded status of a benefit plan in its balance sheet,
measured as the difference between plan assets at fair value (with
limited exceptions) and the benefit obligation,
o recognize as a component of other comprehensive income, net of tax, the
gains or losses and prior service costs or credits that arise during the
period, but are not recognized as components of net periodic benefit
cost,
o measure defined benefit plan assets and obligations as of the date of
the employer's fiscal year-end statement of financial position and
o disclose in the notes to financial statements additional information
about certain effects on net periodic benefit cost for the next fiscal
year that arise from delayed recognition of the gains or losses, prior
service costs or credits, and transition assets or obligations.

An employer with publicly traded securities is required to initially
recognize the funded status of its defined benefit postretirement plans and to
provide the required disclosures as of the end of the first fiscal year ending
after December 15, 2006. The Company has adopted the provisions of SFAS 158
effective on December 31, 2006. The Company previously recognized the funded
status of its defined benefit postretirement plans and currently recognizes
periodic changes in its defined benefit postretirement plans as components of
service costs in the period of change as allowed by SFAS 158. Consequently, the
adoption of SFAS 158 did not have a material impact on the Company's liquidity,
financial position or future results of operations. See Note H of Notes to
Consolidated Financial Statements in "Item 8. Financial Statements and
Supplementary Data" for additional information regarding the Company's
postretirement plans.

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, 2006
and 2005, and from which the Company may incur future gains or losses from
changes in market interest rates, foreign exchange rates or commodity prices.
Although certain derivative contracts to which the Company has been a party 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 is determined based on
counterparties' estimates and valuation models. The Company did not change its
valuation method during 2006. During 2006, the Company was a party to commodity,
interest rate and foreign exchange rate swap contracts and commodity collar
contracts. 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 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 2006:

Derivative Contract Net Liabilities (a)
--------------------------------------------------
Foreign
Interest Exchange
Commodity Rate Rate Total
---------- -------- -------- ----------
(in thousands)

Fair value of contracts outstanding as of
December 31, 2005......................... $ (748,477) $ -- $ -- $ (748,477)
Changes in contract fair values (b).......... 187,895 1,349 (22) 189,222
Contract maturities.......................... 163,955 -- 22 163,977
Contract terminations........................ 328,399 (1,349) -- 327,050
---------- -------- ------- -----------
Fair value of contracts outstanding as
of December 31, 2006...................... $ (68,228) $ -- $ -- $ (68,228)
========== ======== ======= ===========

----------

(a) Represents the fair values of open derivative contracts subject to market
risk. The Company also had $131.1 million and $870 thousand of obligations
under terminated derivatives as of December 31, 2006 and 2005,
respectively, for which no market risk exists.
(b) At inception, new derivative contracts entered into by the Company have no
intrinsic value.

Quantitative Disclosures

Foreign exchange rate sensitivity. From time-to-time, the Company's
Canadian subsidiary enters into short-term forward currency agreements to
purchase Canadian dollars with U.S. dollar gas sales proceeds. The Company does
not designate these derivatives as hedges due to their short-term nature. There
were no outstanding forward currency agreements at December 31, 2006.

Interest rate sensitivity. The following tables provide information about
other financial instruments to which the Company was a party as of December 31,
2006 and 2005 that 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, 2006 and 2005. 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 February 19, 2007. As of
December 31, 2006, the Company was not a party to material derivatives that
would subject it to interest rate sensitivity.

Interest Rate Sensitivity
Debt Obligations as of December 31, 2006

Liability
Year Ending December 31, Fair Value at
---------------------------------------------------------------------- December 31,
2007 2008 2009 2010 2011 Thereafter Total 2006
-------- -------- -------- -------- -------- ---------- ---------- -------------
(in thousands, except interest rates)

Total Debt:
Fixed rate principal
maturities (a)............. $ 32,075 $ 3,777 $ -- $ -- $ -- $1,232,985 $1,268,837 $ 1,244,846
Weighted average interest
rate (%).................. 6.64 6.25 6.51 6.51 6.51 6.51
Variable rate maturities..... $ -- $ -- $ -- $ 22,960 $ 305,040 $ -- $ 328,000 $ 328,000
Average interest rate (%).. 6.23 5.87 5.88 5.96 6.28 --

----------

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

Interest Rate Sensitivity
Debt Obligations as of December 31, 2005

Liability
Year Ending December 31, Fair Value at
---------------------------------------------------------------------- December 31,
2006 2007 2008 2009 2010 Thereafter Total 2005
-------- -------- -------- -------- -------- ---------- ---------- -------------
(in thousands, except interest rates)

Total Debt:
Fixed rate principal
maturities (a).......... $ -- $ 32,075 $350,000 $ -- $ -- $ 882,985 $1,265,060 $ 1,369,404
Weighted average interest
rate (%)............... 6.31 6.29 6.16 6.16 6.16 6.16
Variable rate maturities.. $ -- $ -- $ -- $ -- $900,000 $ -- $ 900,000 $ 900,000
Average interest rate (%) 5.88 6.00 6.02 6.10 6.16 --

----------

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

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, 2006 and 2005. As of
December 31, 2006 and 2005, 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 J 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
or gas prices.

Oil Price Sensitivity
Derivative Financial Instruments as of December 31, 2006

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

Oil Hedge Derivatives:
Average daily notional Bbl volumes (a):
Swap contracts (b)............................ 4,512 6,500 -- $ 130,574
Weighted average fixed price per Bbl.......... $ 31.44 $ 31.19 $ --
Average forward NYMEX oil prices (c).......... $ 61.47 $ 63.93 $ 63.86

----------

(a) See Note J 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, 2006, the Company reduced its oil hedge
positions by terminating the following oil swap contracts which are
included in the table above: (i) 4,342 Bbls per day of 2007 swap contracts
with a fixed price of $31.47 per Bbl and (ii) 2,500 Bbls per day of 2008
swap contracts with a fixed price of $29.90 per Bbl.

Oil Price Sensitivity
Derivative Financial Instruments as of December 31, 2005

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

Oil Hedge Derivatives:
Average daily notional Bbl volumes:
Swap contracts............................... 10,000 13,000 17,000 $ 441,189
Weighted average fixed price per Bbl......... $ 31.69 $ 30.89 $ 29.21
Collar contracts............................. 9,129 4,500 -- $ 21,879
Weighted average ceiling price per Bbl....... $ 74.92 $ 90.43 $ --
Weighted average floor price per Bbl......... $ 44.25 $ 50.00 $ --
Average forward NYMEX oil prices (a)......... $ 62.72 $ 65.52 $ 64.84

----------

(a) The average forward NYMEX oil prices are based on February 15, 2006 market
quotes.

Gas Price Sensitivity
Derivative Financial Instruments as of December 31, 2006

Asset
Year Ending December 31, Fair Value at
------------------------ December 31,
2007 2008 2006
--------- --------- -------------
(in thousands)

Gas Hedge Derivatives (a) (b):
Average daily notional MMBtu volumes (c):
Swap contracts................................... 86,194 15,000 $ 54,835
Weighted average fixed price per MMBtu........... $ 8.13 $ 8.62
Collar contracts................................. 6,164 -- $ 7,511
Weighted average ceiling price per MMBtu......... $ 11.52 $ --
Weighted average floor price per MMBtu........... $ 9.00 $ --
Average forward NYMEX gas prices (d)............. $ 7.99 $ 8.29

----------

(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) Subsequent to December 31, 2006, the Company entered into additional gas
swap contracts of approximately 102,192 MMBtu per day at an average price
of $8.13 per MMBtu for the Company's 2007 production.

(c) See Note J 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.

(d) The average forward NYMEX gas prices are based on February 19, 2007 market
quotes.

Gas Price Sensitivity
Derivative Financial Instruments as of December 31, 2005

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

Gas Hedge Derivatives (a):
Average daily notional MMBtu volumes:
Swap contracts................................ 73,842 29,195 5,000 $ 213,543
Weighted average fixed price per MMBtu........ $ 4.30 $ 4.28 $ 5.38
Collar contracts.............................. 183,685 215,000 -- $ 71,866
Weighted average ceiling price per MMBtu...... $ 13.76 $ 11.84 $ --
Weighted average floor price per MMBtu........ $ 6.62 $ 6.57 $ --
Average forward NYMEX gas prices (b).......... $ 7.81 $ 8.99 $ 8.76

----------

(b) The average forward NYMEX gas prices are based on February 15, 2006 market
quotes.

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 Board. 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 and Canada, which together represented 18 percent of the Company's 2006
oil and gas revenues. Although Pioneer's primary focus is directed toward
onshore North American opportunities, Pioneer continues to identify and
selectively evaluate other international opportunities. As a result of such
foreign operations, Pioneer's financial results and international operations
could be affected by factors such as changes in foreign currency exchange rates,
changes in the legal or regulatory environment, weak economic conditions or
changes in political or economic climates 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 compliance with applicable U.S. law could be in conflict with the
Company's contractual obligations, the laws of foreign governments or
local customs,

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 to do so.

Argentina. During April 2006, the Company sold its Argentine assets for net
proceeds of $669.6 million, resulting in a gain of $10.9 million. The results of
operations from the Argentine operations are being presented as discontinued
operations.

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,
repeatedly incurring significant fiscal deficits such that by the end of 2001
Argentina had accumulated $130 billion of debt.

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.

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
impacted 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, the peso-to-U.S. dollar exchange rate had stabilized at
approximately 3.00:1.

As a result of the Argentine economic instability and government
regulation, the Company (i) received prices for the oil and gas it produced at
prices significantly below those received in its other operating areas, (ii)
curtailed the investment the Company made in Argentina and (iii) ultimately led
the Company to dispose of its Argentine assets. The Company is currently
winding-up the affairs associated with its remaining Argentine entity. The
Company is still exposed to the uncertainties surrounding the Argentine economic
and political situation until the Company completes (i) the distribution of its
remaining sales proceeds to the United States, (ii) the liquidation of its
remaining Argentine entity and (iii) its obligations under the indemnifications
and retained obligations related to the divestiture of the Argentine assets.

Africa. The Company's producing assets in Africa are in South Africa and
Tunisia. The Company views the operating environment in these African nations as
stable and the economic stability as good. The Company also has an exploration
program in the developing West African countries of Equatorial Guinea and
Nigeria. While the values of the various African nations' currencies 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.

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 fluctuates 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, 2006, 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 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, 2006.

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................. 64
Consolidated Balance Sheets as of December 31, 2006 and 2005............ 65
Consolidated Statements of Operations for the Years Ended
December 31, 2006, 2005 and 2004...................................... 66
Consolidated Statements of Stockholders' Equity for the Years Ended
December 31, 2006, 2005 and 2004...................................... 67
Consolidated Statements of Cash Flows for the Years Ended
December 31, 2006, 2005 and 2004...................................... 69
Consolidated Statements of Comprehensive Income for the Years Ended
December 31, 2006, 2005 and 2004...................................... 70
Notes to Consolidated Financial Statements.............................. 71
Unaudited Supplementary Information..................................... 109

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 (the "Company") as of December 31, 2006 and 2005, and
the related consolidated statements of operations, stockholders' equity, cash
flows and comprehensive income for each of the three years in the period ended
December 31, 2006. 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 at December 31, 2006 and 2005, and the consolidated results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2006, in conformity with U.S. generally accepted accounting
principles.

As discussed in Note B to the consolidated financial statements, in 2006
the Company adopted Statement of Financial Accounting Standards No. 123(R),
"Share-Based Payment" and No. 158 "Employers' Accounting for Defined Benefit
Pension and Postretirement Plans."

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, 2006,
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 19, 2007 expressed an unqualified opinion thereon.

Ernst & Young LLP

Dallas, Texas
February 19, 2007

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED BALANCE SHEETS
(in thousands, except share data)

December 31,
-----------------------------
2006 2005
------------ ------------
ASSETS

Current assets:
Cash and cash equivalents.............................................. $ 7,033 $ 18,802
Accounts receivable:
Trade, net of allowance for doubtful accounts of $6,999 and
$5,736 as of December 31, 2006 and 2005, respectively.............. 195,534 334,864
Due from affiliates.................................................. 3,837 1,596
Income taxes receivable................................................ 24,693 1,198
Inventories............................................................ 95,131 79,659
Prepaid expenses....................................................... 11,509 18,091
Deferred income taxes.................................................. 82,927 158,878
Other current assets:
Derivatives.......................................................... 63,665 1,246
Other, net of allowance for doubtful accounts of $6,425 as of
December 31, 2005.................................................. 52,229 9,470
------------ ------------
Total current assets.............................................. 536,558 623,804

Property, plant and equipment, at cost:
Oil and gas properties, using the successful efforts method of
accounting:
Proved properties.................................................. 7,967,708 8,499,253
Unproved properties................................................ 210,344 313,881
Accumulated depletion, depreciation and amortization................. (1,895,408) (2,577,946)
------------ ------------
Total property, plant and equipment................................ 6,282,644 6,235,188
------------ ------------
Deferred income taxes.................................................. 345 --
Goodwill............................................................... 309,908 311,651
Other property and equipment, net...................................... 131,840 90,010
Other assets:
Derivatives.......................................................... 4,333 1,048
Other, net of allowance for doubtful accounts of $4,045 and $92
as of December 31, 2006 and 2005, respectively..................... 89,771 67,533
------------ ------------
$ 7,355,399 $ 7,329,234
============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY

Current liabilities:
Accounts payable:
Trade................................................................ $ 332,795 $ 330,151
Due to affiliates.................................................... 17,025 15,053
Interest payable....................................................... 31,008 40,314
Income taxes payable................................................... 12,865 22,470
Other current liabilities:
Derivatives.......................................................... 141,898 320,098
Deferred revenue..................................................... 181,232 190,327
Other................................................................ 170,156 114,942
------------ -----------
Total current liabilities.......................................... 886,979 1,033,355
------------ -----------
Long-term debt........................................................... 1,497,162 2,058,412
Derivatives.............................................................. 125,459 431,543
Deferred income taxes.................................................... 1,172,507 767,329
Deferred revenue......................................................... 483,279 664,511
Other liabilities and minority interests................................. 205,342 156,982
Stockholders' equity:
Common stock, $.01 par value; 500,000,000 shares authorized;
122,686,073 and 145,200,293 shares issued at December 31, 2006
and 2005, respectively............................................... 1,227 1,452
Additional paid-in capital............................................. 2,654,047 3,775,812
Treasury stock, at cost: 1,183,090 and 18,368,109 shares at
December 31, 2006 and 2005, respectively............................. (53,274) (882,382)
Deferred compensation.................................................. -- (45,827)
Retained earnings (accumulated deficit)................................ 497,488 (184,320)
Accumulated other comprehensive income (loss):
Net deferred hedge losses, net of tax................................ (167,220) (506,636)
Cumulative translation adjustment.................................... 52,403 59,003
------------ -----------
Total stockholders' equity......................................... 2,984,671 2,217,102
Commitments and contingencies............................................
------------ -----------
$ 7,355,399 $ 7,329,234
============ ===========

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

PIONEER NATURAL RESOURCES COMPANY

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

Year Ended December 31,
------------------------------------
2006 2005 2004
---------- ---------- ----------

Revenues and other income:
Oil and gas........................................................ $1,582,049 $1,453,240 $1,012,608
Interest and other................................................. 58,723 31,531 2,157
Gain (loss) on disposition of assets, net.......................... (7,891) 59,827 39
---------- ---------- ----------
1,632,881 1,544,598 1,014,804
---------- ---------- ----------
Costs and expenses:
Oil and gas production............................................. 398,257 346,439 224,903
Depletion, depreciation and amortization........................... 359,523 299,944 231,598
Impairment of long-lived assets.................................... -- 644 39,684
Exploration and abandonments....................................... 264,145 163,323 113,371
General and administrative......................................... 121,830 114,237 73,192
Accretion of discount on asset retirement obligations.............. 4,826 4,209 4,130
Interest........................................................... 107,032 126,086 102,017
Hurricane activity, net............................................ 32,000 39,813 --
Other.............................................................. 36,280 99,437 28,398
---------- ---------- ----------
1,323,893 1,194,132 817,293
---------- ---------- ----------
Income from continuing operations before income taxes................ 308,988 350,466 197,511
Income tax provision................................................. (136,666) (155,832) (63,079)
---------- ---------- ----------
Income from continuing operations.................................... 172,322 194,634 134,432
Income from discontinued operations, net of tax...................... 567,409 339,934 178,422
---------- ---------- ----------
Net income........................................................... $ 739,731 $ 534,568 $ 312,854
========== ========== ==========

Basic earnings per share:
Income from continuing operations.................................. $ 1.39 $ 1.42 $ 1.07
Income from discontinued operations................................ 4.56 2.48 1.43
---------- ---------- ----------
Net income......................................................... $ 5.95 $ 3.90 $ 2.50
========== ========== ==========
Diluted earnings per share:
Income from continuing operations.................................. $ 1.36 $ 1.40 $ 1.06
Income from discontinued operations................................ 4.45 2.40 1.40
---------- ---------- ----------
Net income......................................................... $ 5.81 $ 3.80 $ 2.46
========== ========== ==========
Weighted average shares outstanding:
Basic.............................................................. 124,359 137,110 125,156
========== ========== ==========
Diluted............................................................ 127,608 141,417 127,488
========== ========== ==========

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

PIONEER NATURAL RESOURCES COMPANY

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

Accumulated Other
Comprehensive Income (Loss)
---------------------------
Net
Retained Deferred
Additional Earnings Hedge Gains Cumulative Total
Common Paid-in Treasury Deferred (Accumulated (Losses), Translation Stockholders'
Stock Capital Stock Compensation Deficit) Net of Tax Adjustment Equity
------ ---------- ----------- ------------ ----------- ----------- ----------- ------------

Balance as of January 1, 2004.... $1,179 $2,734,421 $ (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
Compensation costs:
Compensation awards............ 5 19,122 -- (19,127) -- -- -- --
Compensation costs included
in net income................ -- -- -- 12,503 -- -- -- 12,503
Net income....................... -- -- -- -- 312,854 -- -- 312,854
Other comprehensive income (loss):
Deferred hedging activity,
net of tax:
Net deferred hedge losses.... -- -- -- -- -- (291,642) -- (291,642)
Net hedge losses included
in continuing operations.... -- -- -- -- -- 79,962 -- 79,962
Net hedge losses included
in discontinued operations.. -- -- -- -- -- 74,460 -- 74,460
Translation adjustment......... -- -- -- -- -- -- 19,417 19,417
------ ---------- ---------- ---------- --------- ---------- -------- -----------
Balance as of December 31, 2004.. $1,438 $3,705,304 $ (27,793) $ (22,558) $(634,146) $ (241,350) $ 50,885 $ 2,831,780
------ ---------- ---------- ---------- --------- ---------- -------- -----------

Dividends declared ($.22 per
common share).................. -- -- -- -- (30,339) -- -- (30,339)
Exercise of long-term incentive
plan stock options and
employee stock purchases........ -- 1,310 94,670 -- (54,403) -- -- 41,577
Purchase of treasury stock....... -- -- (949,259) -- -- -- -- (949,259)
Tax benefits related to
stock-based compensation....... -- 18,752 -- -- -- -- -- 18,752
Compensation costs:
Compensation awards............ 14 56,146 -- (56,160) -- -- -- --
Compensation costs included
in net income................ -- -- -- 26,857 -- -- -- 26,857
Forfeiture of deferred
compensation................. -- (5,700) -- 6,034 -- -- -- 334
Net income....................... -- -- -- -- 534,568 -- -- 534,568
Other comprehensive income (loss):
Deferred hedging activity,
net of tax:
Net deferred hedge losses.... -- -- -- -- -- (539,384) -- (539,384)
Net hedge losses included
in continuing operations.... -- -- -- -- -- 180,981 -- 180,981
Net hedge losses included
in discontinued operations.. -- -- -- -- -- 93,117 -- 93,117
Translation adjustment......... -- -- -- -- -- -- 8,118 8,118
------ ---------- ---------- ---------- --------- ---------- -------- -----------
Balance as of December 31, 2005.. $1,452 $3,775,812 $ (882,382) $ (45,827) $(184,320) $ (506,636) $ 59,003 $ 2,217,102
------ ---------- ---------- --------- --------- ---------- -------- -----------

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

PIONEER NATURAL RESOURCES COMPANY

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

Accumulated Other
Comprehensive Income (Loss)
---------------------------
Net
Retained Deferred
Additional Earnings Hedge Gains Cumulative Total
Common Paid-in Treasury Deferred (Accumulated (Losses), Translation Stockholders'
Stock Capital Stock Compensation Deficit) Net of Tax Adjustment Equity
------ ----------- ----------- ------------ ----------- ----------- ----------- ------------

Dividends declared ($.25 per
share)......................... $ -- $ -- $ -- $ -- $ (31,726) $ -- $ -- $ (31,726)
Conversion of senior notes....... -- (85,023) 107,023 -- -- -- -- 22,000
Exercise of long-term incentive
plan stock options and
employee stock purchases....... -- 4,010 39,568 -- (26,197) -- -- 17,381
Purchase of treasury stock....... -- -- (348,945) -- -- -- -- (348,945)
Tax benefits related to
stock-based compensation....... -- 4,247 -- -- -- -- -- 4,247
Compensation costs:
Adoption of SFAS No. 123(R).... -- (45,827) -- 45,827 -- -- -- --
Compensation awards............ 4 (4) -- -- -- -- -- --
Compensation costs included
in net income................. -- 32,065 -- -- -- -- -- 32,065
Net income....................... -- -- -- -- 739,731 -- -- 739,731
Retirement of shares............. (229) (1,031,233) 1,031,462 -- -- -- -- --
Other comprehensive income (loss):
Deferred hedging activity,
net of tax:
Net deferred hedge gains..... -- -- -- -- -- 118,139 -- 118,139
Net hedge losses included
in continuing operations.... -- -- -- -- -- 95,005 -- 95,005
Net hedge losses included
in discontinued operations.. -- -- -- -- -- 126,272 -- 126,272
Translation adjustment......... -- -- -- -- -- -- (6,600) (6,600)
------ ----------- ---------- ---------- --------- ---------- -------- -----------
Balance as of December 31, 2006.. $1,227 $ 2,654,047 $ (53,274) $ -- $ 497,488 $ (167,220) $ 52,403 $ 2,984,671
====== =========== ========== ========== ========= ========== ======== ===========

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

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)

Year Ended December 31,
---------------------------------------
2006 2005 2004
----------- ----------- -----------

Cash flows from operating activities:
Net income.................................................. $ 739,731 $ 534,568 $ 312,854
Adjustments to reconcile net income to net cash provided
by operating activities:
Depletion, depreciation and amortization................ 359,523 299,944 231,598
Impairment of long-lived assets......................... -- 644 39,684
Exploration expenses, including dry holes............... 148,077 53,489 39,492
Hurricane activity...................................... 75,000 39,813 --
Deferred income taxes................................... 154,911 104,987 45,514
Loss (gain) on disposition of assets, net............... 7,891 (59,827) (39)
Loss (gain) on extinguishment of debt................... 8,076 25,975 (95)
Accretion of discount on asset retirement obligations... 4,826 4,209 4,130
Discontinued operations................................. (537,073) 376,952 500,458
Interest expense........................................ 11,042 4,399 (13,413)
Commodity hedge related activity........................ (11,498) 21,237 (45,102)
Amortization of stock-based compensation................ 32,065 26,857 12,503
Amortization of deferred revenue........................ (190,327) (75,773) --
Other noncash items..................................... 15,589 19,940 15,022
Change in operating assets and liabilities, net of effects
from acquisitions and dispositions:
Accounts receivable, net.................................. 121,360 (128,015) (73,376)
Income taxes receivable................................... (23,495) (1,198) --
Inventories............................................... (48,060) (36,948) (14,025)
Prepaid expenses.......................................... 4,808 (7,504) 974
Other current assets, net................................. (42,484) 972 262
Accounts payable.......................................... (36,085) 83,960 250
Interest payable.......................................... (6,500) (7,115) 5,533
Income taxes payable...................................... (3,695) 8,950 3,372
Other current liabilities................................. (28,854) (13,362) (14,037)
----------- ----------- -----------
Net cash provided by operating activities............... 754,828 1,277,154 1,051,559
----------- ----------- -----------
Cash flows from investing activities:
Payments for acquisitions, net of cash acquired............. -- (965) (880,365)
Proceeds from dispositions of assets, net of cash sold...... 1,644,829 1,248,581 1,709
Additions to oil and gas properties......................... (1,403,879) (1,123,297) (562,907)
Additions to other assets and other property and
equipment, net............................................ (95,435) (39,585) (36,970)
----------- ----------- -----------
Net cash provided by (used in) investing activities..... 145,515 84,734 (1,478,533)
----------- ----------- -----------
Cash flows from financing activities:
Borrowings under long-term debt............................. 1,426,490 1,203,190 1,157,903
Principal payments on long-term debt........................ (1,981,164) (1,556,763) (604,475)
Borrowings (payments) of other liabilities, net............. 610 (60,129) (54,252)
Exercise of long-term incentive plan stock options and
employee stock purchases.................................. 17,381 41,577 35,068
Purchase of treasury stock.................................. (348,945) (949,259) (92,256)
Excess tax benefits from share-based payment arrangements... 5,989 -- --
Payment of financing fees................................... (2,178) (1,911) (1,173)
Dividends paid.............................................. (31,726) (30,339) (26,557)
----------- ----------- -----------
Net cash provided by (used in) financing activities..... (913,543) (1,353,634) 414,258
----------- ----------- -----------
Net increase (decrease) in cash and cash equivalents........... (13,200) 8,254 (12,716)
Effect of exchange rate changes on cash and cash equivalents... 1,431 3,291 674
Cash and cash equivalents, beginning of year................... 18,802 7,257 19,299
----------- ----------- -----------
Cash and cash equivalents, end of year......................... $ 7,033 $ 18,802 $ 7,257
=========== =========== ===========

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

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(in thousands)

Year Ended December 31,
---------------------------------------
2006 2005 2004
----------- ----------- ------------

Net income.................................................... $ 739,731 $ 534,568 $ 312,854
Other comprehensive loss:
Net deferred hedge gains (losses), net of tax:
Net deferred hedge gains (losses)......................... 118,139 (539,384) (291,642)
Net hedge losses included in continuing operations........ 95,005 180,981 79,962
Net hedge losses included in discontinued operations...... 126,272 93,117 74,460
Translation adjustment...................................... (6,600) 8,118 19,417
----------- ----------- -----------
Other comprehensive income (loss)......................... 332,816 (257,168) (117,803)
----------- ----------- -----------
Comprehensive income.......................................... $ 1,072,547 $ 277,400 $ 195,051
=========== =========== ===========

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

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2006, 2005 and 2004

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 current operations in the United States, Canada,
Equatorial Guinea, Nigeria, South Africa and Tunisia.

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. The Company proportionately consolidates
less than 100 percent-owned affiliate partnerships, for which certain of its
wholly-owned subsidiaries serve as general partners, involved in oil and gas
producing activities in accordance with Emerging Issues Task Force ("EITF")
Abstract Issue No. 00-1, "Investor Balance Sheet and Income Statement Display
under the Equity Method for Investments in Certain Partnerships and Other
Ventures". The Company owns less than a 22 percent interest in the oil and gas
partnerships that it proportionately consolidates. All material intercompany
balances and transactions have been eliminated.

Minority interests in consolidated subsidiaries. The Company owns the
majority interests in certain subsidiaries with operations in the United States
and Nigeria. Associated therewith, the Company has recognized minority interests
in consolidated subsidiaries of $14.4 million and $9.3 million in other
liabilities and minority interests in the accompanying Consolidated Balance
Sheets as of December 31, 2006 and 2005, respectively.

Minority interests in the net losses of the Company's consolidated Nigerian
subsidiary totaled $4.9 million and $5.2 million for the years ended December
31, 2006 and 2005, respectively, and are included in interest and other income
in the accompanying Consolidated Statements of Operations. Minority interests in
the net income of the Company's consolidated United States subsidiaries totaled
$2.6 million, $3.5 million and $.9 million for the years ended December 31,
2006, 2005 and 2004, respectively, and are included in other expense in the
accompanying Consolidated Statements of Operations.

Discontinued operations. During 2005 and 2006, the Company sold its
interests in the following oil and gas asset groups:

Country Description of Asset Groups Date Divested
------- --------------------------- -------------

Canada Martin Creek, Conroy Black and
Lookout Butte fields May 2005

United States Two Gulf of Mexico shelf fields August 2005

United States Deepwater Gulf of Mexico fields March 2006

Argentina Argentine assets April 2006

In accordance with Statement of Financial Accounting Standards ("SFAS") No.
144, "Accounting for the Impairment or Disposal of Long-Lived Assets" ("SFAS
144"), the Company has reflected the results of operations of the above
divestitures as discontinued operations, rather than as a component of
continuing operations. See Note V for additional information regarding
discontinued operations.

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 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 and impairment

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2006, 2005 and 2004

of goodwill and oil and gas properties, in part, 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. In April 2006, the Company sold its Argentine assets and is
currently winding-up the affairs associated with its remaining Argentine entity.
As of December 31, 2006 and 2005, the Company used exchange rates of 3.06 pesos
to $1 and 3.03 pesos to $1, respectively, to remeasure the peso-denominated
monetary assets and liabilities of the Company's Argentine subsidiaries. The
Company remains exposed to uncertainties surrounding the Argentine economic and
political environment until the Company completes (i) the distribution of its
remaining sales proceeds to the United Sates, (ii) the liquidation of its
remaining Argentine entity and (iii) its obligations under the indemnifications
and retained obligations related to the divesture of the Argentine assets.

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

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 the near term; 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 income, 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. 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, 2006 or 2005.

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, 2006 or 2005.

Inventories. Inventories were comprised of $93.7 million and $77.3 million
of materials and supplies and $1.4 million and $2.4 million of commodities as of
December 31, 2006 and 2005, respectively. The Company's materials and supplies
inventory is primarily comprised of oil and gas drilling or repair items such as
tubing, casing, chemicals, operating supplies and ordinary maintenance materials
and parts. The materials and supplies inventory is primarily acquired for use in
future drilling operations or repair operations and is carried at the lower of
cost or market, on a weighted average cost basis. Commodities inventory is
carried at the lower of average cost or market, on a first-in, first-out basis.
Any impairments of inventory are reflected in gain (loss) on disposition of
assets in the Consolidated Statements of Operations. As of December 31, 2006 and
2005, the Company's materials and supplies inventory was net of $4.2 million and
$.2 million, respectively, of valuation reserve allowances.

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, generally when the underlying project is
sanctioned, until such projects are ready for their intended use.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2006, 2005 and 2004

(i) The well has found a sufficient quantity of reserves to justify its
completion as a producing well.

(ii) The Company is making sufficient progress assessing the reserves and
the economic and operating viability of the project.

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 project's 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 seven natural gas processing plants and seven
treating facilities. The Company operates five of the plants and all seven
treating facilities. The Company's ownership interests 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. Third party revenues
generated from the plant and treating facilities for the three years ended
December 31, 2006, 2005 and 2004 were $38.5 million, $39.2 million and $32.1
million, respectively. Third party expenses attributable to the plants and
treating facilities for the same respective periods were $6.4 million, $13.8
million and $11.8 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 depletion base.

In accordance with SFAS No. 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.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2006, 2005 and 2004

Goodwill. As described in Note C, the Company recorded $327.8 million of
goodwill associated with the merger with Evergreen Resources, Inc.
("Evergreen"). The goodwill was recorded to the Company's United States
reporting unit. In accordance with 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 has reduced goodwill by $18.0 million
since September 28, 2004 for tax benefits associated with the exercise of
fully-vested stock options assumed in conjunction with the Evergreen merger. In
accordance with SFAS 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. During the third quarter of 2006, the Company performed its
annual assessment of impairment of the goodwill and determined that there was no
impairment.

Other property, plant and equipment, net. Other property, plant and
equipment is stated at cost and primarily consists of items such as heavy
equipment and rigs, furniture and fixtures and leasehold improvements.
Depreciation is provided over the estimated useful life of the assets using the
straight-line method. At December 31, 2006 and 2005, other property, plant and
equipment was net of accumulated depreciation of $145.3 million and $131.5
million, respectively.

Asset retirement obligations. The Company accounts for asset retirement
obligations in accordance with SFAS No. 143, "Accounting for Asset Retirement
Obligations" ("SFAS 143"). SFAS 143 amended SFAS No. 19, "Financial Accounting
and Reporting by Oil and Gas Producing Companies" 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 generally
capitalized as part of the carrying value of the long-lived asset.

In March 2005, the FASB issued FASB Interpretation No. 47, "Accounting for
Conditional Asset Retirement Obligations, an interpretation of FASB Statement
No. 143" ("FIN 47"). FIN 47 clarifies that conditional asset retirement
obligations meet the definition of liabilities and should be recognized when
incurred if their fair values can be reasonably estimated. The interpretation
was adopted by the Company on December 31, 2005. The adoption of FIN 47 had no
impact on the Company's financial position or results of operations.

Derivatives and hedging. The Company follows the provisions of SFAS 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 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 ("AOCI - Hedging") in the stockholders' equity
section of the Company's Consolidated Balance Sheets until such time as the

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2006, 2005 and 2004

hedged items are recognized in net income. Ineffective portions of a derivative
instrument's change in fair value are immediately recognized in earnings.

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

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 is fixed or reliably determinable.

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. During 2006, the Company
retired 22.9 million treasury shares resulting in a reduction in treasury stock
of $1.0 billion.

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, natural gas
liquid ("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 material oil or NGL entitlement assets or liabilities as
of December 31, 2006 or 2005. The following table presents the Company's gas
entitlement assets and liabilities and their associated volumes as of December
31, 2006 and 2005:

December 31,
----------------------------------------
2006 2005
------------------ ------------------
Amount MMcf Amount MMcf
-------- ------ -------- ------
($ in millions)

Entitlement assets.............. $ 13.0 4,201 $ 12.1 4,007
Entitlement liabilities......... $ 3.9 1,082 $ 8.5 7,206

Stock-based compensation. On January 1, 2006, the Company adopted SFAS No.
123 (revised 2004), "Share-Based Payment" ("SFAS 123(R)") to account for
stock-based compensation. Among other items, SFAS 123(R) eliminates the use of
the Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to
Employees" ("APB 25"), intrinsic value method of accounting and requires
companies to recognize the cost of employee services received in exchange for
awards of equity instruments based on the grant date fair value of those awards
in the financial statements. The Company elected to use the modified prospective
method for adoption of SFAS 123(R), which requires compensation expense to be
recorded for all unvested stock options and other equity-based compensation
beginning in the first quarter of adoption. For all unvested stock options
outstanding as of January 1, 2006, the previously measured but unrecognized
compensation expense, based on the fair value on the date of grant, was
recognized in the Company's financial statements over their remaining vesting
periods, which ended in August 2006. For equity-based compensation awards
granted or modified subsequent to January 1, 2006, compensation expense, based
on the fair value on the date of grant, is being recognized in the Company's
financial statements over the vesting period. The Company utilizes the
Black-Scholes option pricing model to measure the fair value of stock options
and utilizes the stock price on the date of grant for the fair value of
restricted stock awards. Prior to the adoption of SFAS 123(R), the Company
followed the intrinsic value method in accordance with APB 25 to account for
stock options. Prior period financial statements have not been restated. The
modified prospective method requires the Company to estimate forfeitures in

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2006, 2005 and 2004

calculating the expense related to stock-based compensation as opposed to its
prior policy of recognizing forfeitures as they occurred. The Company recorded
no cumulative effect as a result of adopting SFAS 123(R).

Additionally, under the provisions of SFAS 123(R), deferred compensation
recorded under APB 25 related to equity-based awards should be eliminated
against the appropriate equity accounts. As a result, upon adoption of SFAS
123(R), the Company eliminated $45.8 million of deferred compensation cost in
stockholders' equity and reduced a like amount of additional paid-in capital in
the accompanying Consolidated Balance Sheets.

For the year ended December 31, 2006, the Company recorded $32.1 million of
compensation costs for all stock-based plans. The impact to net income of
adopting SFAS 123(R) was $1.6 million for the year ended December 31, 2006, or
less than $.02 per diluted share. For the year ended December 31, 2006, the
adoption impact is comprised of $959 thousand of compensation expense associated
with stock options and $669 thousand of compensation expense associated with the
Company's Employee Stock Purchase Plan (the "ESPP"), which is a compensatory
plan under the provisions of SFAS 123(R).

Pursuant to the provisions of SFAS 123(R), the Company's issued shares, as
reflected in the accompanying Consolidated Balance Sheets at December 31, 2006
and 2005, do not include 1,946,211 shares and 1,756,180 shares, respectively,
related to unvested restricted stock awards.

As of December 31, 2006, there was approximately $39.8 million of
unrecognized compensation expense related to unvested share-based compensation
plan awards, primarily related to restricted stock awards. This compensation
will be recognized on a straight-line basis over the remaining vesting periods
of the awards, which is a remaining period of less than three years.

The following table illustrates the pro forma effect on net income and net
income per share as if the Company had applied the fair value recognition
provisions of SFAS No. 123(R) to stock-based compensation during the years ended
December 31, 2005 and 2004:

Year Ended December 31,
------------------------
2005 2004
---------- ----------
(in thousands, except
per share amounts)

Net income, as reported..................................... $ 534,568 $ 312,854
Plus: Stock-based compensation expense included in net
income for all awards, net of tax (a)................... 17,054 7,939
Deduct: Stock-based compensation expense determined under
fair value based method for all awards, net of tax (a) (19,772) (13,985)
---------- ----------
Pro forma net income........................................ $ 531,850 $ 306,808
========== ==========
Net income per share:
Basic - as reported..................................... $ 3.90 $ 2.50
========== ==========
Basic - pro forma....................................... $ 3.88 $ 2.45
========== ==========
Diluted - as reported................................... $ 3.80 $ 2.46
========== ==========
Diluted - pro forma..................................... $ 3.78 $ 2.41
========== ==========

----------

(a) For the years ended December 31, 2005 and 2004, stock-based compensation
expense included in net income is net of tax benefits of $9.8 million and
$4.6 million, respectively. Similarly, stock-based compensation expense
determined under the fair value based method for the years ended December
31, 2005 and 2004 is net of tax benefits of $11.4 million and $8.0 million,
respectively. See Note P 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

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2006, 2005 and 2004

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 subsidiaries
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.

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, 2006, 2005 and 2004:

December 31,
--------------------------
2006 2005 2004
------ ------ ------

U.S. Dollar from Canadian Dollar - Balance Sheets.... .8577 .8606 .8320
U.S. Dollar from Canadian Dollar - Statements of
Operations........................................ .8817 .8279 .7699

Reclassifications. Certain reclassifications have been made to the 2005 and
2004 amounts in order to conform with the 2006 presentation. Specifically, the
Company reduced its exploration and abandonments expense by $39.8 million for
the year ended December 31, 2005, which represents reclassification of
abandonment costs for the Company's East Cameron facility destroyed by Hurricane
Rita to hurricane activity, net expense on the accompanying Consolidated
Statements of Operations and Consolidated Statements of Cash Flows.
Additionally, $18.2 million of unfunded check issuances were reclassified from
changes in accounts payable in operating cash flows to payment of other
liabilities in net cash flows from financing activities within the Consolidated
Statements of Cash Flows for the year ended December 31, 2005.

New accounting pronouncements. The following discussions provide
information about new accounting pronouncements that were issued by FASB during
2006:

FIN 48. In July 2006, the FASB issued Interpretation No. 48, "Accounting
for Uncertainty in Income Taxes" ("FIN 48"). The Interpretation clarifies the
accounting for income taxes by prescribing a minimum recognition threshold that
a tax position is required to meet before being recognized in the financial
statements. FIN 48 also provides guidance on measurement, classification,
interim accounting and disclosure. FIN 48 is effective for fiscal years
beginning after December 15, 2006. The Company is continuing to assess the
potential impacts of this Interpretation.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2006, 2005 and 2004

o recognize the funded status of a benefit plan in its balance sheet,
measured as the difference between plan assets at fair value (with limited
exceptions) and the benefit obligation,
o recognize as a component of other comprehensive income, net of tax, the
gains or losses and prior service costs or credits that arise during the
period, but are not recognized as components of net periodic benefit
cost,
o measure defined benefit plan assets and obligations as of the date of the
employer's balance sheet and
o disclose in the notes to financial statements additional information
about certain effects on net periodic benefit cost for the next fiscal
year that arise from delayed recognition of the gains or losses, prior
service costs or credits, and transition assets or obligations.

An employer with publicly traded securities is required to initially
recognize the funded status of its defined benefit postretirement plans and to
provide the required disclosures as of the end of the first fiscal year ending
after December 15, 2006. The Company adopted the provisions of SFAS 158
effective on December 31, 2006. The Company previously recognized the funded
status of its defined benefit postretirement plans and currently recognizes
periodic changes in its defined benefit postretirement plans as components of
service costs in the period of change as allowed by SFAS 158. Consequently, the
adoption of SFAS 158 did not have a material impact on the Company's liquidity,
financial position or future results of operations. See Note H of Notes to
Consolidated Financial Statements in "Item 8. Financial Statements and
Supplementary Data" for additional information regarding the Company's
postretirement plans.

NOTE C. Acquisitions

Evergreen merger. On September 28, 2004, Pioneer completed a merger with
Evergreen, with Pioneer being the surviving corporation for accounting purposes.
The transaction was accounted for as a purchase of Evergreen by Pioneer. As a
result, the financial statements for the Company prior to September 28, 2004 are
those of Pioneer only. 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 to Evergreen shareholders at closing, net of $12.1 million of acquired
cash. The cash consideration paid in the merger was financed through borrowings
on the Company's credit facilities.

The Company recorded $327.8 million of goodwill associated with the
Evergreen merger, which represented the excess of the purchase consideration
over the net fair value of the identifiable net assets acquired.

Permian Basin and Onshore Gulf Coast acquisitions. During 2006 and 2005,
the Company spent $71.2 million and $167.8 million, respectively, to acquire
various working interests primarily in the Spraberry and South Texas areas.

NOTE D. Exploratory Well Costs

The Company capitalizes exploratory well costs until a determination is
made that the well has either found proved reserves or that it is impaired. The
capitalized exploratory well costs are presented in proved properties in the
Consolidated Balance Sheets. If the exploratory well is determined to be
impaired, the well costs are charged to expense.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2006, 2005 and 2004

The following table reflects the Company's capitalized exploratory well
activity during each of the years ended December 31, 2006, 2005 and 2004:

Year Ended December 31,
--------------------------------------
2006 2005 2004
---------- ---------- ----------
(in thousands)

Beginning capitalized exploratory well costs... $ 198,291 $ 126,472 $ 108,986
Additions to exploratory well costs pending the
determination of proved reserves............. 451,109 243,272 156,937
Reclassifications due to determination of proved
reserves..................................... (193,480) (78,334) (56,639)
Disposition of wells sold...................... (52,628) -- --
Exploratory well costs charged to exploration
expense...................................... (138,239) (93,119) (82,812)
---------- ---------- ----------
Ending capitalized exploratory well costs...... $ 265,053 $ 198,291 $ 126,472
========== ========== ==========

The following table provides an aging as of December 31, 2006, 2005 and
2004 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:

Year Ended December 31,
--------------------------------------
2006 2005 2004
---------- ---------- ----------
(in thousands, except well counts)

Capitalized exploratory well costs capitalized:
One year or less................................. $ 126,749 $ 84,042 $ 35,046
More than one year.............................. 138,304 114,249 91,426
---------- ---------- ----------
$ 265,053 $ 198,291 $ 126,472
========== ========== ==========
Number of wells with exploratory well costs that
have been capitalized for a period greater than
one year......................................... 14 14 10
========== ========== ==========

The following table provides the capitalized costs of exploration projects
that have been suspended for more than one year as of December 31, 2006, 2005
and 2004:

December 31,
--------------------------------------
2006 2005 2004
---------- ---------- ----------
(in thousands)

United States:
Clipper (a).................................. $ 75,242 $ -- $ --
Ozona Deep................................... -- 19,423 19,462
Oooguruk..................................... 52,205 52,205 47,083
Thunder Hawk................................. -- 25,769 --
United States - other........................ 4,103 -- --
Canada - other................................. 1,695 805 1,214
South Africa................................... -- 7,227 14,895
Tunisia - Anaguid.............................. 5,059 8,820 8,772
---------- ---------- ----------
Total...................................... $ 138,304 $ 114,249 $ 91,426
========== ========== ==========

----------

(a) Includes $37.0 million of costs incurred in 2006.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2006, 2005 and 2004

The following discussion describes the history and status of each
significant suspended exploratory project:

Clipper. During 2005, the Company drilled its first exploratory well on the
Clipper prospect, which was a discovery. During 2006, the Company drilled
additional wells to determine the magnitude of the discovery. The Company is
currently evaluating the plans for development of the discovery, including
evaluating sub-sea tie-back options to third-party production and handling
facilities in the area.

Ozona Deep and Thunder Hawk. During March 2006, the Company sold its
interests in the Ozona Deep and Thunder Hawk properties as part of the Company's
deepwater Gulf of Mexico divestiture. See Note N for additional information
regarding the Company's divestiture of its deepwater Gulf of Mexico oil and gas
assets.

Oooguruk. 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 cost 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 improve the
Company's understanding of 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 and a front-end
engineering design study ("FEED study") for the area.

During the first quarter of 2006, the Company sanctioned the development of
the discovery and obtained the necessary regulatory approvals. The Company
installed an offshore gravel drilling and production site during the 2006 winter
construction season and completed armoring activities during the third quarter.
A sub-sea flowline and facilities will be installed during 2007 to carry
produced liquids to existing onshore processing facilities at the Kuparuk River
Unit. Pioneer plans to drill approximately 40 horizontal wells to develop the
discovery. Depending on weather conditions and facilities completion and
accessibility, drilling could begin as early as the fall of 2007. The Company
estimates first production will occur in 2008.

South Africa. During 2001, the Company drilled two South African discovery
wells that found quantities of gas and condensate believed to be commercial.
From 2002 to 2004, the Company actively reviewed the gas supply and demand
fundamentals in South Africa and had discussions with a gas-to-liquids ("GTL")
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 GTL plant operator
initiated purchase orders for long-lead time infrastructure components. In
December 2005, the Company announced the final approvals with its partner in the
South Coast gas project to commence the initial development of the project. As a
result, the Company added 11.4 million Bbls oil equivalent ("MMBOE") of proved
reserves in 2005 and reduced the suspended exploratory costs by $7.7 million.

During 2000, the Company drilled two South African exploratory wells in the
Company's Boomslang prospect. One well was unsuccessful, but the other well
found quantities of hydrocarbons believed to be commercial. The Boomslang
discovery was not included in the initial development phase of the South Coast
Gas project. Boomslang is an oil discovery with a significant gas cap. The
Company believes the Boomslang discovery may ultimately be developed as a gas
discovery, but commercialization plans have not progressed sufficiently to allow
the Company to continue to capitalize the exploratory costs related to the
discovery. Accordingly, the Company expensed the Boomslang discovery in the
fourth quarter of 2006.

Tunisia - Anaguid. 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.
During 2005, the project operator, along with the Company, conducted an extended
production test of one of the two existing exploration wells and drilled an
offset appraisal well to the other exploration well.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2006, 2005 and 2004

The results of the extended production test were unfavorable and the
Company expensed $5.1 million associated with this well in 2005. However, the
appraisal well offsetting the second discovery encountered gas and condensate in
a similar horizon to the initial well. The Company has concluded studies on the
appraisal well with unfavorable results and expensed $4.2 million in the fourth
quarter of 2006. Studies on the second discovery will continue to determine
whether development is economical.

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, 2006 and 2005:

December 31,
--------------------------------------------------------
2006 2005
-------------------------- --------------------------
Carrying Fair Carrying Fair
Value Value Value Value
----------- ----------- ----------- -----------
(in thousands)

Net derivative contract liabilities:
Commodity price hedges....................... $ (68,228) $ (68,228) $ (748,477) $ (748,477)
Terminated commodity price hedges............ $ (131,131) $ (131,131) $ (870) $ (870)
Financial assets:
Trading securities........................... $ 18,582 $ 18,582 $ 15,237 $ 15,237
Notes receivable due 2008 to 2011............ $ 23,607 $ 23,607 $ 1,429 $ 1,429
Financial liabilities - long-term debt:
Line of credit............................... $ (328,000) $ (328,000) $ (900,000) $ (900,000)
8 1/4 % senior notes due 2007................ $ (32,081) $ (32,511) $ (32,199) $ (33,477)
6 1/2 % senior notes due 2008................ $ (3,761) $ (3,798) $ (348,714) $ (356,965)
5 7/8% senior notes due 2012................. $ (6,235) $ (5,903) $ (6,255) $ (5,947)
5 7/8% senior notes due 2016................. $ (427,588) $ (497,054) $ (421,327) $ (506,590)
6 7/8% senior notes due 2018................. $ (449,579) $ (452,430) $ -- $ --
4 3/4 % senior convertible notes due 2021.... $ -- $ -- $ (100,000) $ (201,225)
7 1/5% senior notes due 2028................. $ (249,918) $ (253,150) $ (249,917) $ (265,200)

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 J 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
approximate fair value due to the short maturity of these instruments. The fair
value of the notes receivable approximates the carrying value at December 31,
2006 due to the proximity of the execution dates of the notes to December 31.
The current portion of the notes receivable, amounting to $5.1 million and $.4
million as of December 31, 2006 and 2005, respectively, is included in other
current assets, net in the Company's Consolidated Balance Sheets. The trading
securities and the noncurrent portions of the notes receivable are included in
other assets, net in the Company's Consolidated Balance Sheets.

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.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2006, 2005 and 2004

NOTE F. Long-term Debt

Long-term debt, including the effects of net deferred fair value hedges
losses and issuance discounts and premiums, consisted of the following
components at December 31, 2006 and 2005:

December 31,
-----------------------
2006 2005
---------- ----------
(in thousands)

Outstanding debt principal balances:
Line of credit.................................. $ 328,000 $ 900,000
8 1/4% senior notes due 2007.................... 32,075 32,075
6 1/2% senior notes due 2008.................... 3,777 350,000
5 7/8% senior notes due 2012.................... 6,110 6,110
5 7/8% senior notes due 2016.................... 526,875 526,875
6 7/8% senior notes due 2018.................... 450,000 --
4 3/4% senior convertible notes due 2021........ -- 100,000
7 1/5% senior notes due 2028.................... 250,000 250,000
---------- ----------
1,596,837 2,165,060
Issuance discounts and premiums, net.............. (96,284) (102,347)
Net deferred fair value hedge losses.............. (3,391) (4,301)
---------- ----------
Total long-term debt.............................. $1,497,162 $2,058,412
========== ==========

Lines of credit. The Company has an Amended and Restated 5-Year Revolving
Credit Agreement (the "Credit Agreement"), which originally had a maturity date
in September 2010 unless extended in accordance with the terms of the Credit
Agreement. The terms of the Credit Agreement provide for initial aggregate loan
commitments of $1.5 billion, which may be increased to a maximum aggregate
amount of $1.8 billion if the lenders increase their loan commitments or if loan
commitments of new financial institutions are added to the Credit Agreement.
Effective September 29, 2006, participating lenders extended the maturity date
on $1.395 billion of aggregate loan commitments under the Credit Agreement to
September 2011.

Borrowings under the Credit Agreement may be in the form of revolving loans
or swing line loans. Aggregate outstanding swing line loans may not exceed $100
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 (8.25 percent per annum at December 31, 2006) 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
(5.17 percent per annum at December 31, 2006) plus .5 percent or (b) a base
Eurodollar rate, substantially equal to LIBOR (5.33 percent per annum at
December 31, 2006), plus a margin (the "Applicable Margin") that is determined
by reference to a grid based on the Company's debt rating (.875 percent per
annum at December 31, 2006). The Applicable Margin is increased by .10 percent
to .125 percent per annum, depending on the Company's debt ratings, if total
borrowings under the Credit Agreement exceed 50 percent of the aggregate loan
commitments. 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 plus the Applicable Margin. The Company pays commitment fees on the
undrawn amounts under the Credit Agreement that are determined by reference to a
grid based on the Company's debt rating (.175 percent per annum at December 31,
2006).

As of December 31, 2006, the Company had $153.8 million of undrawn letters
of credit, of which $150.2 million were undrawn commitments under the Credit
Agreement. The letters of credit outstanding under the 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 (.875 percent at December 31, 2006) plus
..125 percent. As of December 31, 2006, the Company had unused borrowing capacity
of $1.0 billion under the Credit Agreement.

The Credit Agreement contains certain financial covenants, which include
the (i) 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; (ii) maintenance of a ratio of total debt to book capitalization

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2006, 2005 and 2004

less intangible assets, accumulated other comprehensive income and certain
noncash asset impairments not to exceed .60 to 1.0; and (iii) maintenance of an
annual ratio of the net present value of the Company's oil and gas properties to
total debt of at least 1.50 to 1.0 through March 2007 and 1.75 to 1.0
thereafter. The lenders may declare any outstanding obligations under the Credit
Agreement immediately due and payable upon the occurrence, and during the
continuance of, an event of default, which includes a defined change in control
of the Company. As of December 31, 2006, the Company was in compliance with all
of its debt covenants.

Senior notes. During May 2006, the Company issued $450 million of 6.875%
notes and received proceeds, net of issuance discount and underwriting cost, of
$447.4 million.

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.

Senior convertible notes. During 2006, holders of all of the $100 million
of 4 3/4% Senior Convertible Notes exercised their conversion rights. Associated
therewith, the Company paid $79.9 million in cash, issued 2.3 million shares of
common stock and recorded a $22 million increase to stockholders' equity.

Early extinguishment of debt. During 2006, the Company repurchased $346.2
million of its outstanding $350 million of 6.50% senior notes due 2008 (the
"6.50% Notes"). The Company recognized a charge of $8.1 million in the second
quarter of 2006 associated with the early extinguishment of the 6.50% Notes,
which is included in other expense in the accompanying Consolidated Statements
of Operations. During 2005, the Company (i) redeemed the remaining principal
amounts of its outstanding 9 5/8% senior notes due 2010 and its 7.50% senior
notes due 2012 of $64.0 million and $16.2 million, respectively, and (ii)
accepted tenders to purchase for cash $188.4 million in principal amount of its
5 7/8% senior notes due 2012. Consequently, the Company recognized a charge for
the early extinguishment of debt of $26.5 million included in other expense in
the accompanying Consolidated Statements of Operations on these redemptions and
tenders for 2005.

Principal maturities. Principal maturities of long-term debt at December
31, 2006 are as follows (in thousands):

2007....................................... $ 32,075
2008....................................... $ 3,777
2009....................................... $ --
2010....................................... $ 22,960
2011....................................... $ 305,040
Thereafter................................. $ 1,232,985

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2006, 2005 and 2004

Interest expenses. The following amounts have been incurred and charged to
interest expense for the years ended December 31, 2006, 2005 and 2004:

Year Ended December 31,
--------------------------------------
2006 2005 2004
---------- ---------- ----------
(in thousands)

Cash payments for interest......................... $ 114,727 $ 129,868 $ 109,970
Accretion/amortization of discounts or premiums
on loans........................................ 7,133 6,186 3,683
Accretion of discount on derivative obligations.... 2,529 -- --
Amortization of net deferred hedge (gains) losses
(see Note J)..................................... 14 (4,052) (19,220)
Amortization of capitalized loan fees.............. 1,366 2,265 2,059
Kansas ad valorem tax.............................. -- -- 65
Net changes in accruals............................ (6,571) (7,092) 7,476
---------- ---------- ----------
Interest incurred.................................. 119,198 127,175 104,033
Less capitalized interest.......................... (12,166) (1,089) (2,016)
---------- ---------- ----------
Total interest expense............................. $ 107,032 $ 126,086 $ 102,017
========== ========== ==========

NOTE G. Related Party Transactions

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, 2006, 2005
and 2004:

Year Ended December 31,
--------------------------------------
2006 2005 2004
---------- ---------- ----------
(in thousands)

Receipt of lease operating and supervision
charges in accordance with standard industry
operating agreements.......................... $ 1,551 $ 1,493 $ 1,458
Reimbursement of general and administrative
expenses...................................... $ 348 $ 348 $ 193

NOTE H. Incentive Plans

Retirement Plans

Deferred compensation retirement plan. In August 1997, the Compensation
Committee of the Board of Directors (the "Board") 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 $1.3 million, $1.2 million and $.9 million
for the years ended December 31, 2006, 2005 and 2004, respectively.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2006, 2005 and 2004

401(k) plan. The Pioneer Natural Resources USA, Inc. ("Pioneer USA") 401(k)
and Matching Plan (the "401(k) Plan") is a defined contribution plan established
under the Internal Revenue Code Section 401. 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 base compensation (the "Matching Contribution"). Each
participant's account is credited with the participant's contributions, 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, 2006,
2005 and 2004, the Company recognized compensation expense of $9.3 million, $8.0
million and $5.4 million, respectively, as a result of Matching Contributions.

Long-Term Incentive Plan

In May 2006, the Company's stockholders approved a new 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 4.6 million awards.

The following table shows the number of awards available under the
Company's Long-Term Incentive Plan at December 31, 2006:

Approved and authorized awards............... 4,600,000
Awards issued after May 3, 2006............ (74,549)
----------
Awards available for future grant............ 4,525,451
==========

For the 2006-2007 director year, the Company's non-employee directors were
offered a choice to receive their annual fee retainers (i) 100 percent in
restricted stock units, (ii) 100 percent in cash or (iii) a combination of 50/50
of cash and restricted stock units. All non-employee directors also received an
annual equity grant of restricted stock units.

Stock option awards. In accordance with the Evergreen 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 after 2003.

Restricted stock awards. During 2006, 2005 and 2004 the Company issued
736,642, 1,411,269 and 630,937, respectively, restricted shares of the Company's
common stock as compensation to directors, officers and employees of the
Company.

During 2004, the Company assumed 214,186 restricted stock units in exchange
for Evergreen restricted stock units outstanding on September 28, 2004. 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 was amortized as charges to compensation
expense over the periods in which the restrictions on the units lapsed.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2006, 2005 and 2004

Compensation costs. On January 1, 2006, the Company adopted SFAS 123(R), as
more fully described in Note B, and eliminated $45.8 million of deferred
compensation in stockholders' equity and reduced a like amount of additional
paid-in capital in the Consolidated Balance Sheets. Prior to adoption of SFAS
123(R), the Company recorded $56.2 million and $19.1 million of deferred
compensation associated with restricted stock awards in stockholders' equity
during 2005 and 2004, respectively. Such amounts will be amortized to
compensation expense over the vesting periods of the awards.

Adoption of SFAS 123(R), required the Company to prospectively (i)
recognize the value of the unvested stock options, which was approximately $959
thousand and (ii) recognize compensation expense associated with the Company's
ESPP. The Company's recognition of compensation of restricted stock did not
change upon adoption of SFAS 123(R).

During 2006, 2005 and 2004, the Company recognized compensation costs
associated with stock-based compensation of $32.1 million, $26.9 million and
$12.5 million, respectively. At December 31, 2006, the Company has unrecognized
unvested stock-based compensation costs of approximately $39.8 million, which
will amortize to earnings over the next three years.

The following table reflects the outstanding restricted stock awards as of
December 31, 2006, 2005 and 2004 and activity related thereto for the years then
ended:

Year Ended December 31,
-------------------------------------------------------------------------
2006 2005 2004
---------------------- ----------------------- -----------------------
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.... 1,966,223 $ 36.90 1,447,987 $ 28.46 676,973 $ 24.79
Evergreen awards assumed............ -- $ -- -- $ -- 214,186 $ 32.58
Shares granted...................... 736,642 $ 43.44 1,411,269 $ 39.79 630,937 $ 31.29
Shares forfeited.................... (190,538) $ 39.32 (174,046) $ 33.99 (32,174) $ 30.99
Lapse of restrictions............... (385,780) $ 34.84 (718,987) $ 26.26 (41,935) $ 31.09
---------- --------- ---------
Outstanding at end of year.......... 2,126,547 $ 39.32 1,966,223 $ 36.90 1,447,987 $ 28.46
========== ========= =========

A summary of the Company's stock option plans as of December 31, 2006,
2005 and 2004, and changes during the years then ended, are presented below:

Non-statutory stock options (a):
Outstanding at beginning of year.... 2,685,398 $ 20.32 5,180,584 $ 18.60 5,274,116 $ 20.13
Evergreen options assumed......... -- $ -- -- $ -- 2,384,657 $ 11.18
Options forfeited................. (267,851) $ 22.60 (65,190) $ 22.94 (102,890) $ 22.24
Options exercised................. (816,052) $ 19.22 (2,429,996) $ 15.95 (2,375,299) $ 14.39
--------- ---------- ----------
Outstanding at end of year.......... 1,601,495 $ 20.50 2,685,398 $ 20.32 5,180,584 $ 18.60
========= ========== ==========
Exercisable at end of year.......... 1,601,495 $ 20.50 2,382,714 $ 19.74 3,970,996 $ 17.08
========= ========== ==========

----------

(a) The Company did not grant any stock options during 2006, 2005 or 2004.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2006, 2005 and 2004

The following table summarizes information about the Company's stock
options outstanding and exercisable at December 31, 2006:

Options Outstanding and Exercisable
----------------------------------------------------------------
Number Weighted Weighted Intrinsic
Outstanding at Average Average Value at
Range of December 31, Remaining Exercise December 31,
Exercise Price 2006 Contractual Life Price 2006
-------------- -------------- ---------------- --------- -----------
(in thousands)

$5-$11 139,402 2.0 years $ 9.90 $ 4,153
$12-$18 691,611 2.1 years $ 17.50 15,347
$19-$26 755,483 3.2 years $ 24.81 11,242
$31-$43 14,999 0.1 years $ 40.31 --
---------- -----------
1,601,495 $ 30,742
========== ===========

Employee Stock Purchase Plan

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
eight-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, 2006 and 2005, the Company had recorded $19.8 million
and $18.6 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
acquired in prior years. These plans had no assets as of December 31, 2006 or
2005. Other than the Company's retirement plan, the participants of these plans
are not current employees of the Company.

As of December 31, 2006, the accumulated postretirement benefit obligations
pertaining to these plans were determined by independent actuaries for four
plans representing $15.7 million of unfunded accumulated postretirement benefit
obligations and by the Company for one plan representing $4.1 million of
unfunded accumulated postretirement benefit obligations. Interest costs at an
annual rate of 5.95 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 10 percent in 2007, declining to five percent in 2012 and thereafter,
and annual dental cost escalation trends of seven percent in 2007, declining to
five percent in 2011 and thereafter, were employed to estimate the accumulated
postretirement benefit obligations associated with the medical and dental cost
subsidies.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2006, 2005 and 2004

The following table reconciles changes in the Company's unfunded
accumulated postretirement benefit obligations during the years ended December
31, 2006, 2005 and 2004:

Year Ended December 31,
--------------------------------------
2006 2005 2004
---------- ---------- ----------
(in thousands)

Beginning accumulated postretirement benefit
obligations....................................... $ 18,576 $ 15,534 $ 15,556
Net benefit payments................................ (1,234) (1,393) (1,497)
Service costs....................................... 816 324 258
Net actuarial losses (gains)........................ 642 3,211 (32)
Accretion of interest............................... 1,037 900 909
Fair value of Evergreen obligations assumed......... -- -- 340
---------- ---------- -----------
Ending accumulated postretirement benefit
obligations....................................... $ 19,837 $ 18,576 $ 15,534
========== ========== ==========

Estimated benefit payments and service/interest costs associated with the
plans for the year ending December 31, 2007 are $1.5 million and $2.2 million,
respectively.

As discussed above in Note B, the Company has adopted the provisions of
SFAS 158 effective on December 31, 2006. The Company previously recognized the
funded status of its defined benefit postretirement plans and currently
recognizes periodic changes in its defined benefit postretirement plans as
components of service costs in the period of change as allowed by SFAS 158.
Consequently, the adoption of SFAS 158 did not have a material impact on the
Company's liquidity, financial position or future results of operations for the
year ended December 31, 2006.

NOTE I. Commitments and Contingencies

Severance agreements. The Company has entered into severance and change in
control agreements with its officers, subsidiary company officers and certain
key employees. The current annual salaries for the parent company officers, the
subsidiary company officers and key employees covered under such agreements
total $35.4 million.

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 the legal actions that are described
below. The Company is also party to other proceedings and claims incidental to
its business. While many of these matters involve inherent uncertainty, the
Company believes that the amount of the liability, if any, ultimately incurred
with respect to such other proceedings and claims will not have a material
adverse effect on the Company's consolidated financial position as a whole or on
its liquidity, capital resources or future annual 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 its
assessment of 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 plaintiffs in the case assert that they were
improperly charged expenses (primarily field compression), which plaintiffs
allege are a "cost of production," and for which the plaintiffs claim they, as
royalty owners, are not responsible. Plaintiffs also claim that they are
entitled to 50 percent of the value of the helium extracted at the Company's
Satanta gas plant.

During the third quarter of 2006, the Company reached an agreement to
settle the claims made in the lawsuit. Under the terms of the agreement, the
Company agreed to make cash payments to settle the plaintiffs' claims with
respect to production occurring on and before December 31, 2005. The Company's
portion of the cash payments is expected to be $32.7 million, of which
approximately $17.0 million was paid during the third quarter of 2006 and the

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2006, 2005 and 2004

remaining approximately $15.7 million will be paid in the third quarter of 2007.
The Company also agreed to adjust the manner in which royalty payments to the
class members will be calculated for production occurring on and after January
1, 2006, which change is not expected to have a material effect on the Company's
liquidity, financial position or future results of operations.

Final approval was received from the Court on February 9, 2007, and the
settlement is expected to be final within 60 days of final approval assuming no
appeals are filed. If no appeals are made or if any appeals made are resolved,
it is expected that the settlement will be final in the second quarter of 2007.

MOSH Holding. On April 11, 2005, the Company and its principal United
States subsidiary, Pioneer Natural Resources USA, Inc., were named as defendants
in MOSH Holding, L.P. v Pioneer Natural Resources Company; Pioneer Natural
Resources USA, Inc.; Woodside Energy (USA) Inc.; and JPMorgan Chase Bank, NA, as
Trustee of the Mesa Offshore Trust, which is before the Judicial District Court
of Harris County, Texas (334th Judicial District). On December 8, 2006,
Dagger-Spine Hedgehog Corporation ("Dagger-Spine") filed a Petition In
Intervention in the lawsuit to assert the same claims as MOSH Holding, L.P.
("MHLP"). MHLP and Dagger-Spine (collectively, "Plaintiffs") are unitholders in
the Trust, which was created in 1982 as the sole limited partner in a
partnership that holds an overriding royalty interest in certain oil and gas
leases offshore Louisiana and Texas. The Company owns the managing general
partner interest in the partnership. Plaintiffs allege that the Company,
together with Woodside Energy (USA) Inc. ("Woodside"), concealed the value of
the royalty interest and worked to terminate the Mesa Offshore Trust prematurely
and to capture for itself and Woodside profits that belong to the Mesa Offshore
Trust ("MOT"). Plaintiffs also allege breaches of fiduciary duty, misapplication
of trust property, common law fraud, gross negligence, and breach of the
conveyance agreement for the overriding royalty interest. The relief sought by
the plaintiffs includes monetary and punitive damages and certain equitable
relief, including an accounting of expenses, a setting aside of certain
farmouts, and a temporary and permanent injunction.

The Trustee and the Company have reached a conditional settlement of all
claims in the lawsuit that MOT has or might have against the Company. Plaintiffs
are not signatories to the settlement and they, or other unitholders of MOT, may
comment on or object to the settlement. The settlement is subject to certain
conditions and is not final until approved by the court and any appeals are
resolved. The court has set the settlement review hearing for May 21, 2007.

Dorchester Refining Company Site. A subsidiary of the Company has been
notified by a letter from the Texas Commission on Environmental Quality ("TCEQ")
dated August 24, 2005 that the TCEQ considers the subsidiary to be a potentially
responsible party with respect to the Dorchester Refining Company State
Superfund Site located in Mount Pleasant, Texas. In connection with the
acquisition of oil and gas assets in 1991, the Company acquired a group of
companies, one of which was an entity that had owned a refinery located at the
Mount Pleasant site from 1977 until 1984. According to the TCEQ, this refinery
was responsible for releases of hazardous substances into the environment.
Pursuant to applicable Texas law, the Company's subsidiary, which does not own
any material assets or conduct any material operations, may be subject to
strict, joint and several liability for the costs of conducting a study to
evaluate potential remedial options and for the costs of performing any
remediation ultimately required by the TCEQ. The Company does not know the
nature and extent of the alleged contamination, the potential costs of
remediation or the portion, if any, of such costs that may be allocable to the
Company's subsidiary; however, the Company has noted that there appear to be
other operators or owners who may share responsibility for these costs and 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,
financial position or future annual results of operations.

Environmental Protection Agency Investigation. On November 4, 2005, the
Company learned from the U.S. Environmental Protection Agency that the agency
was conducting a criminal investigation into a 2003 spill that occurred at a
Company-operated drilling rig located on an ice island offshore Harrison Bay,
Alaska. The investigation is being conducted in conjunction with the U.S.
Attorney's Office for the District of Alaska. The spill was previously
investigated by the Alaska Department of Environmental Conservation ("ADEC")
and, following completion of a clean up, the ADEC issued a letter stating its
determination that, at that time, the site did not pose a threat to human
health, safety or welfare, or the environment. The Company is fully cooperating
with the government's investigation.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2006, 2005 and 2004

Argentine obligations. The Company has provided the purchaser of its
Argentine assets certain indemnifications and remains responsible for certain
contingent liabilities, subject to defined limitations. The Company does not
currently believe that these obligations, which primarily pertain to matters of
litigation, environmental contingencies, royalty obligations and income taxes,
are probable of having a material impact on its liquidity, financial position or
future results of operations.

Lease agreements. The Company leases offshore production facilities,
drilling rigs, equipment and office facilities under noncancellable operating
leases. Rental expenses associated with these operating leases for the years
ended December 31, 2006, 2005 and 2004 were approximately $46.8 million, $64.5
million and $51.8 million, respectively, which includes $8.7 million, $26.0
million and $15.4 million, respectively, associated with discontinued
operations. Future minimum lease commitments under noncancellable operating
leases at December 31, 2006 are as follows (in thousands):

2007........................ $ 29,065
2008........................ $ 14,560
2009........................ $ 13,346
2010........................ $ 6,720
2011........................ $ 709
Thereafter.................. $ --

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. During 2006, the Company expanded these commitments to
support production increases, primarily in the Raton gas field. The
transportation commitments averaged approximately 190 million cubic feet
("MMcf") of gross gas sales volumes per day during 2006, including associated
fuel commitments. These commitments will average approximately 201 MMcf of gross
gas volumes per day during 2007, decrease to approximately 198 MMcf of gross gas
volumes per day during 2008, and decline thereafter to approximately 69 MMcf of
gross gas volumes per day during 2013, before terminating in January 2014.

The Company's Canadian subsidiaries are parties to pipeline transportation
service agreements, with aggregate remaining terms of approximately 10 years,
whereby they have committed to transport specified volumes of gas each year
principally from Canada to a point in Chicago, Illinois. Such gas volumes
totaled approximately 86 MMcf of gas per day during 2006 and 78 MMcf of gas per
day during 2005 and 2004, and 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 85 MMcf of gas per
day during 2007 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 $2.0 and
$4.1 million of gas marketing gains in other income during the years ended
December 31, 2006 and 2005, respectively, and $1.2 million of gas marketing
losses in other expense during the year ended December 31, 2004.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2006, 2005 and 2004

Future minimum transportation fees under the Company's gas transportation
commitments at December 31, 2006 are as follows (in thousands):

2007........................ $ 68,630
2008........................ $ 68,938
2009........................ $ 68,458
2010........................ $ 66,749
2011........................ $ 64,243
Thereafter.................. $ 170,546

NOTE J. Derivative Financial Instruments

The Company uses financial derivative contracts to manage exposures to
commodity price, interest rate and foreign currency fluctuations. The Company
generally does not enter into derivative financial instruments for speculative
or trading purposes. The Company also may enter physical delivery contracts to
effectively provide commodity price hedges. Because these contracts are not
expected to be net cash settled, they are considered to be normal sales
contracts and not derivatives. Therefore, these contracts are not recorded in
the financial statements.

All derivatives are recorded on the balance sheet at estimated fair value.
Fair value is generally determined based on the difference between the fixed
contract price and the underlying market price at the determination date, and/or
the value confirmed by the counterparty. Changes in the fair value of effective
cash flow hedges are recorded as a component of accumulated other comprehensive
income (loss), which is later transferred to earnings when the hedged
transaction occurs. Changes in the fair value of derivatives that are not
designated as hedges, as well as the ineffective portion of the hedge
derivatives, are recorded in earnings. The ineffective portion is calculated as
the difference between the change in fair value of the derivative and the
estimated change in cash flows from the item hedged.

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 reducing costs of capital. As
of December 31, 2006 and 2005, the Company was not a party to any open fair
value hedges.

As of December 31, 2006, the carrying value of the Company's long-term debt
in the accompanying Consolidated Balance Sheets included a $3.4 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 losses on terminated interest rate swaps
increased the Company's reported interest expense by $14 thousand during the
year ended December 31, 2006, as compared to deferred gains amortization, which
reduced the Company's reported interest expense by $4.1 million and $19.2
million during the years ended December 31, 2005 and 2004, respectively.

The following table sets forth, as of December 31, 2006, the scheduled
amortization of net deferred hedge losses on terminated interest rate hedges
(including terminated fair value and cash flow hedges) that will be recognized
as increases to the Company's future interest expense:

Net Deferred Interest Rate Hedge Losses
---------------------------------------
Fair Value Cash Flow Total
---------- ---------- -----------
(in thousands)

2007................ $ 231 $ 94 $ 325
2008................ $ 257 $ 114 $ 371
2009................ $ 281 $ 135 $ 416
2010................ $ 307 $ 159 $ 466
2011................ $ 337 $ 184 $ 521
Thereafter.......... $ 1,978 $ 1,032 $ 3,010

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2006, 2005 and 2004

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. As of December 31, 2006, all of the Company's open commodity
hedges are designated as hedges of Canadian and United States forecasted sales.
The Company also, from time to time, utilizes 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.

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. As of December 31, 2006, all of the Company's oil
hedges were designated as hedges of United States forecasted sales. 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, 2006:

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

Average daily oil production
hedged (a):
2007 - Swap Contracts
Volume (Bbl).............. 3,689 4,341 5,000 5,000 4,512
Price per Bbl............. $ 31.63 $ 31.47 $ 31.35 $ 31.35 $ 31.44
2008 - Swap Contracts
Volume (Bbl).............. 6,500 6,500 6,500 6,500 6,500
Price per Bbl............. $ 31.19 $ 31.19 $ 31.19 $ 31.19 $ 31.19

----------

(a) Subsequent to December 31, 2006, the Company reduced its oil hedge
positions by terminating the following oil swap contracts: (i) 4,342 Bbls
per day of 2007 swap contracts with a fixed price of $31.47 per Bbl; (ii)
2,500 Bbls per day of 2008 swap contracts with a fixed price of $29.90 per
Bbl.

The Company reports average oil prices per Bbl including the effects of oil
quality adjustments, amortization of deferred volumetric production payment
("VPP") revenue and the net effect of oil hedges. The following table sets forth
(i) the Company's oil prices from continuing operations, both reported
(including hedge results and amortization of deferred VPP revenue) and realized
(excluding hedge results and amortization of deferred VPP revenue), (ii)
amortization of deferred VPP revenue to oil revenue from continuing operations
and (iii) the net effect of settlements of oil price hedges on oil revenue from
continuing operations for the years ended December 31, 2006, 2005 and 2004:

Year Ended December 31,
--------------------------------------
2006 2005 2004
---------- ---------- ----------

Average price reported per Bbl..................... $ 65.51 $ 38.70 $ 32.56
Average price realized per Bbl..................... $ 63.45 $ 53.71 $ 39.06
VPP increase to oil revenue (in millions).......... $ 116.1 $ -- $ --
Reduction to oil revenue from hedging activity
(in millions) (a)................................ $ 97.6 $ 176.6 $ 80.0

----------

(a) Excludes hedge losses of $12.3 million, $52.0 million and $27.2 million
attributable to discontinued operations for the years ended December 31,
2006, 2005 and 2004, respectively.

Natural gas liquids prices. During the years ended December 31, 2006, 2005
and 2004, the Company did not enter into any NGL hedge contracts. There were no
outstanding NGL hedge contracts at December 31, 2006.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2006, 2005 and 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. As of December 31, 2006, all of the Company's gas hedges were designated
as hedges of United States and Canadian forecasted sales. The following table
sets forth the volumes hedged in million British thermal units ("MMBtu") under
outstanding gas hedge contracts and the weighted average index prices per MMBtu
for those contracts as of December 31, 2006:

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

Average daily gas production
hedged (a):
2007 - Swap Contracts
Volume (MMBtu)............. 89,841 85,000 85,000 85,000 86,194
Price per MMBtu............ $ 7.97 $ 8.18 $ 8.18 $ 8.18 $ 8.13
2007 - Collar Contracts
Volume (MMBtu)............. 25,000 -- -- -- 6,164
Price per MMBtu............ $9.00-$11.52 $ -- $ -- $ -- $9.00-$11.52
2008 - Swap Contracts
Volume (MMBtu)............. 15,000 15,000 15,000 15,000 15,000
Price per MMBtu............ $ 8.62 $ 8.62 $ 8.62 $ 8.62 $ 8.62

---------

(a) Subsequent to December 31, 2006, the Company entered into additional gas
swap contracts of approximately 102,192 MMBtu per day at an average price
of $8.13 per MMBtu for the Company's 2007 production.

The Company reports average gas prices per Mcf including the effects of Btu
content, gas processing, shrinkage adjustments, amortization of deferred VPP
revenue and the net effect of gas hedges. The following table sets forth (i) the
Company's gas prices from continuing operations, both reported (including hedge
results and amortization of deferred VPP revenue) and realized (excluding hedge
results and amortization of deferred VPP revenue), (ii) amortization of deferred
VPP revenue to gas revenue from continuing operations and (iii) the net effect
of settlements of gas price hedges on gas revenue from continuing operations for
the years ended December 31, 2006, 2005 and 2004:

Year Ended December 31,
--------------------------------------
2006 2005 2004
---------- ---------- ----------

Average price reported per Mcf...................... $ 6.23 $ 7.02 $ 4.96
Average price realized per Mcf...................... $ 6.04 $ 7.31 $ 5.45
VPP increase to gas revenue (in millions)........... $ 74.2 $ 75.8 $ --
Reduction to gas revenue from hedging activity
(in millions) (a)................................. $ 51.4 $ 108.3 $ 41.9

----------

(a) Excludes hedge losses of $3.4 million, $94.6 million and $83.8 million
attributable to discontinued operations for the year ended December 31,
2006, 2005 and 2004, respectively.

Interest rate. During April 2006, the Company entered into costless collar
contracts and designated the contracts as cash flow hedges of the forecasted
interest rate risk associated with the coupon rate on the Company's 6.875%
Notes, which were issued on May 1, 2006. The Company terminated these costless
collar contracts for a gain of $1.3 million, which was recorded in AOCI -
Hedging. The Company did not realize any ineffectiveness in connection with the
costless collar contracts during 2006. See Note F for information regarding the
6.875% Notes.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2006, 2005 and 2004

Hedge ineffectiveness. The Company recognized ineffectiveness amounts
related to (i) hedged volumes that exceeded revised forecasts of production
volumes due to delays in the start up of production in certain fields and (ii)
reduced correlations between the indexes of the financial hedge derivatives and
the indexes of the hedged forecasted production for certain fields.
Ineffectiveness can be associated with closed contracts (i.e. realized) or can
be associated with open positions (i.e. unrealized). The following table sets
forth the hedge ineffectiveness attributable to continuing operations recognized
in the Consolidated Statements of Operations for the years ended December 31,
2006, 2005 and 2004:

Year Ended December 31,
--------------------------------------
2006 2005 2004
---------- ---------- ----------
(in millions)

Interest and other income............. $ 13.8 $ -- $ --
Other expense......................... 11.6 (44.2) (4.2)
---------- ---------- ----------
Total ineffectiveness (a).......... $ 25.4 $ (44.2) $ (4.2)
========== ========== ==========

----------

(a) Hedge ineffectiveness attributable to discontinued operations was $8.2
million and $171 thousand during 2005 and 2004, respectively.

AOCI - Hedging. As of December 31, 2006 and 2005, AOCI - Hedging
represented net deferred losses of $167.2 and $506.6 million, respectively. The
AOCI - Hedging balance as of December 31, 2006 was comprised of $71.0 million of
net deferred losses on the effective portions of open cash flow hedges, $193.7
million of net deferred losses on terminated cash flow hedges (including $1.7
million of net deferred losses on terminated cash flow interest rate hedges) and
$97.5 million of associated net deferred tax benefits. The AOCI - Hedging
balance as of December 31, 2005 was comprised of $767.8 million of net deferred
losses on the effective portions of open cash flow hedges, $30.0 million of net
deferred losses on terminated cash flow hedges (including $3.2 million of net
deferred losses on terminated cash flow interest rate hedges) and $291.2 million
of associated net deferred tax benefits. The decrease in AOCI - Hedging during
the year ended December 31, 2006 was primarily attributable to the
reclassification of net deferred hedge losses to net income as derivatives
matured and, to a lesser extent, decreases in future commodity prices relative
to the commodity prices stipulated in the hedge contracts. 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 losses on
terminated cash flow hedges are fixed.

During the year ending December 31, 2007, based on current estimates of
future commodity prices, the Company expects to reclassify $5.3 million of net
deferred gains associated with open commodity hedges and $106.3 million of net
deferred losses on terminated commodity hedges from AOCI - Hedging to oil and
gas revenues. The Company also expects to reclassify approximately $38.7 million
of net deferred income tax benefits associated with commodity hedges during the
year ending December 31, 2007 from AOCI - Hedging to income tax benefit.

Terminated commodity hedges. At times, the Company terminates open
commodity hedge positions when the underlying commodity prices reach a point
that the Company believes will be the high or low price of the commodity prior
to the scheduled settlement of the open commodity position. This allows the
Company to maximize gains or minimize losses associated with the open hedge
positions. At the time of termination of the hedges, the amounts recorded in
AOCI - Hedging are maintained and amortized to earnings over the periods the
production was scheduled to occur.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2006, 2005 and 2004

The following table sets forth, as of December 31, 2006, the scheduled
amortization of net deferred losses on terminated commodity hedges that will be
recognized as decreases to the Company's future oil and gas revenues:

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

2007 net deferred hedge losses........ $ 29,619 $ 27,609 $ 25,153 $ 23,905 $ 106,286
2008 net deferred hedge losses........ $ 20,285 $ 17,541 $ 17,402 $ 17,718 72,946
2009 net deferred hedge losses........ $ 2,330 $ 232 $ 230 $ 822 3,614
2010 net deferred hedge losses........ $ 667 $ 620 $ 578 $ 539 2,404
2011 net deferred hedge losses........ $ 873 $ 889 $ 902 $ 907 3,571
2012 net deferred hedge losses........ $ 810 $ 791 $ 783 $ 773 3,157
---------
$ 191,978
=========

Non-hedge derivatives. During January and April 2005, the Company entered
into non-hedge interest rate swaps. The Company terminated the interest rate
swaps during January and April 2005 for an aggregate net loss of $1.5 million,
which amount is included in other expense in the Company's accompanying
Consolidated Statement of Operations for 2005.

NOTE K. 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 and, depending on facts and circumstances, may
require customers to provide collateral or otherwise secure their accounts. 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 United States customers individually accounted for ten
percent or more of the consolidated oil, NGL and gas revenues, including the
revenues from discontinued operations and the results of commodity hedges, in at
least one of the years, during the years ended December 31, 2006, 2005 and 2004:

Year Ended December 31,
--------------------------------------
2006 2005 2004
---------- ---------- ----------

Oneok Resources........................... 12% 6% 3%
Plains Marketing LP....................... 12% 7% 4%
Occidental Energy Marketing, Inc.......... 11% 9% 6%
Williams Power Company, Inc............... 4% 9% 14%

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, 2006, the Company had no derivative counterparties with significant
credit risks.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2006, 2005 and 2004

NOTE L. Asset Retirement Obligations

The Company's asset retirement obligations primarily relate to the future
plugging and abandonment of wells 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 retirement obligations.
The following table summarizes the Company's asset retirement obligation
transactions during the years ended December 31, 2006, 2005 and 2004:

Year Ended December 31,
---------------------------------
2006 2005 2004
--------- --------- ---------
(in thousands)

Beginning asset retirement obligations............. $ 157,035 $ 120,879 $ 105,036
New wells placed on production and changes in
estimates (a).................................... 122,685 57,404 4,591
Liabilities assumed in acquisitions................ 981 3,183 10,488
Disposition of wells............................... (44,042) (23,101) --
Liabilities settled................................ (16,219) (9,508) (8,562)
Accretion of discount on continuing operations..... 4,826 4,209 4,130
Accretion of discount on discontinued operations... 804 3,668 4,080
Currency translation............................... (157) 301 1,116
--------- --------- ---------
Ending asset retirement obligations................ $ 225,913 $ 157,035 $ 120,879
========= ========= =========

----------

(a) Includes, for the years ended December 31, 2006 and 2005, respectively, a
$75.0 million and a $39.8 million increase in the abandonment estimate of
the East Cameron facilities that were destroyed by Hurricane Rita, which is
reflected in hurricane activity, net in the Consolidated Statements of
Operations.

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 M. Interest and Other Income

The following table provides the components of the Company's interest and
other income during the years ended December 31, 2006, 2005 and 2004:

Year Ended December 31,
---------------------------------
2006 2005 2004
--------- --------- ---------
(in thousands)

Business interruption insurance claim
(see Note U)................................. $ 7,647 $ 14,200 $ --
Minority interest in subsidiary net loss
(see Note B)................................. 4,892 5,206 --
Canadian Alliance marketing gain (see Note I).. 2,021 4,127 --
Interest income................................ 15,366 2,177 328
Sales and other tax refunds.................... 645 1,792 --
Credit card rebate............................. 837 835 --
Seismic data sales............................. 620 723 172
Deferred compensation plan income.............. 879 500 202
Foreign currency remeasurement and exchange
gains (a).................................... 855 236 100
Derivative ineffectiveness (see Note J)........ 13,805 -- --
Exploration incentive tax credits.............. 5,570 -- --
Other income................................... 5,586 1,735 1,355
---------- --------- ---------
Total interest and other income................ $ 58,723 $ 31,531 $ 2,157
========== ========= =========

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2006, 2005 and 2004

---------

(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.

NOTE N. Asset Divestitures

During the years ended December 31, 2006, 2005 and 2004, the Company
completed asset divestitures for net proceeds of $1.8 billion, $1.2 billion and
$1.7 million, respectively. Associated therewith, the Company recorded gains
(losses) on disposition of assets in continuing operations of $(7.9) million,
$59.8 million and $39 thousand during the years ended December 31, 2006, 2005
and 2004, respectively, and gains of $733.3 million and $166.1 million in
discontinued operations in 2006 and 2005, respectively. The following represent
the significant divestitures:

Deepwater Gulf of Mexico and Argentine divestitures. During 2006, the
Company sold its interests in certain oil and gas properties in the deepwater
Gulf of Mexico for net proceeds of $1.2 billion, resulting in a gain of $726.2
million and its Argentine assets for net proceeds of $669.6 million, resulting
in a gain of $10.9 million. Pursuant to SFAS 144, the gain and the results of
operations from these assets have been reclassified to discontinued operations.
See Note V for additional information.

Volumetric production payments. During 2005, the Company sold three VPPs
for proceeds of $892.6 million. No gain or loss was recognized. See Note T for
additional information.

Canadian and Gulf of Mexico Shelf divestitures. During 2005, the Company
sold its interests in the Martin Creek, Conroy Black and Lookout Butte areas in
Canada for net proceeds of $197.2 million, resulting in a gain of $138.3 million
and certain assets on the Gulf of Mexico shelf for net proceeds of $59.2
million, resulting in a gain of $27.9 million. Pursuant to SFAS 144, the gain
and the results of operations from these assets have been reclassified to
discontinued operations. See Note V for additional information.

East Texas divestiture. During the year ended December 31, 2005, the
Company sold its interests in certain East Texas properties for $25.3 million of
net cash proceeds with no corresponding gain or loss recognized.

Gabon divestiture. In October 2005, the Company closed the sale of the
shares in a Gabonese subsidiary that owns the interest in the Olowi block for
$47.9 million of net proceeds. A gain was recognized during the fourth quarter
of 2005 of $47.5 million with no associated income tax effect either in Gabon or
the United States. In addition, Pioneer retains the potential, under certain
circumstances, to receive additional payments for production from deeper
reservoirs discovered on the block.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2006, 2005 and 2004

NOTE O. Other Expense

The following table provides the components of the Company's other
expense during the years ended December 31, 2006, 2005 and 2004:

Year Ended December 31,
--------------------------------------
2006 2005 2004
---------- ---------- ----------
(in thousands)

Derivative ineffectiveness (see Note J)................ $ (11,566) $ 44,246 $ 4,168
Loss on early extinguishment of debt (see Note F)...... 8,076 25,975 --
Contingency accrual adjustments (see Note I)........... 10,279 9,756 10,866
Foreign currency remeasurement and exchange losses (a). 580 3,644 1,870
Noncompete agreement amortization...................... 1,670 3,914 798
Minority interest in subsidiaries' net income
(see Note B)......................................... 2,629 3,482 896
Postretirement obligation revaluation.................. 642 3,211 --
Bad debt expense....................................... 4,733 452 3,674
Debt exchange offer costs (see Note F)................. -- -- 2,248
Canadian Alliance marketing losses (see Note I)........ -- -- 1,218
Non-hedge derivative losses............................ 6,517 3,860 --
Other charges.......................................... 12,720 897 2,660
---------- ---------- ----------
Total other expense............................. $ 36,280 $ 99,437 $ 28,398
========== ========== ==========

----------

NOTE P. Income Taxes

The Company accounts for income taxes in accordance with the provisions of
SFAS 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 $153.2 million, $41.4 million and $19.2 million were
made during the years ended December 31, 2006, 2005 and 2004, 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. Pioneer monitors
Company-specific, oil and gas industry and worldwide economic factors and
assesses the likelihood that the Company's net operating loss carryforwards
("NOLs") and other deferred tax attributes in the United States, state, local
and foreign tax jurisdictions will be utilized prior to their expiration. As of
December 31, 2006 and 2005, the Company's valuation allowances related to
foreign and domestic tax jurisdictions were $94.7 million and $95.8 million,
respectively.

The Company's effective tax rate on continuing operations of 44.2 percent
and 44.5 percent for the years ended December 31, 2006 and 2005, respectively,
differs from the combined United States federal and state statutory rate of
approximately 36.5 percent primarily due to:

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2006, 2005 and 2004

o recognition of $8.4 million of deferred tax benefit, during 2006, as a
result of conversion of senior convertible notes prior to the Company's
repayment of the debt principal (see Note F),
o recognition of $7.2 million of taxes during 2005 associated with the
repatriation of foreign earnings pursuant to the American Jobs Creation
Act of 2004 ("AJCA") and
o expenses for unsuccessful well costs and associated acreage costs in
foreign locations where the Company does not expect to receive income tax
benefits.

During May 2006, the State of Texas enacted legislation that changed the
existing Texas franchise tax from a tax based on net income or taxable capital
to an income tax based on a defined calculation of gross margin (the "Texas
margin tax"). Also, during 2006, the Canadian federal and provincial governments
enacted tax rate reductions that will be phased in over several years. SFAS 109
requires that deferred tax balances be adjusted to reflect tax rate changes
during the periods in which the tax rate changes are enacted. The adjustment due
to the enactment of the Texas margin tax and the Canadian tax rate changes
resulted in a $13.5 million United States tax expense and a $10.2 million
Canadian tax benefit during the year ended December 31, 2006, respectively.

In October 2004, the AJCA was signed into law. The AJCA includes a
deduction of 85 percent of qualified foreign earnings that are repatriated, as
defined in the AJCA. During 2005, the Company determined that it was
advantageous to apply the provisions of the AJCA to qualified foreign earnings
that could be repatriated. The Company formalized repatriation plans in 2005 and
repatriated $322.5 million from Canada, South Africa and Tunisia. Approximately
$177 million of the repatriated funds qualified for the dividend exclusion. The
Company is obligated by the provisions of the AJCA to invest the qualifying
dividends in the United States within a reasonable period of time.

Included in the Company's income tax provision from continuing operations
for the year ended December 31, 2005 is the reversal of a $26.9 million tax
benefit recorded in 2004 as a result of the cancellation of the development of
the Olowi block and the Company's decision to exit Gabon. Reversal of the tax
benefit was the result of signing an agreement in June 2005 to sell the
Company's shares in the subsidiary that owns the interest in the Olowi block to
an unaffiliated buyer, which made it more likely than not that the Company would
not realize the originally recorded tax benefit. The Company completed the sale
of the Gabonese subsidiary during 2005.

The Company's income tax provision (benefit) and amounts separately
allocated were attributable to the following items for the years ended December
31, 2006, 2005 and 2004:

Year Ended December 31,
--------------------------------------
2006 2005 2004
---------- ---------- ----------
(in thousands)

Income from continuing operations..................... $ 136,666 $ 155,832 $ 63,079
Income from discontinued operations................... 299,856 209,013 103,280
Changes in goodwill - tax benefits related to
stock-based compensation............................ (1,742) (7,255) (8,955)
Changes in stockholders' equity:
Net deferred hedge gains (losses)................... 193,719 (166,572) (73,340)
Tax benefits related to stock-based compensation.... (4,247) (18,752) (6,612)
Translation adjustment.............................. 8,421 3,685 (314)
---------- ---------- ----------
$ 632,673 $ 175,951 $ 77,138
========== ========== ==========

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2006, 2005 and 2004

The Company's income tax provision (benefit) attributable to income from
continuing operations consisted of the following for the years ended December
31, 2006, 2005 and 2004:

Year Ended December 31,
--------------------------------------
2006 2005 2004
---------- ---------- ----------
(in thousands)

Current:
U.S. federal................................... $ (54,004) $ 13,104 $ 2,500
U.S. state and local........................... (52) (254) 602
Foreign........................................ 35,811 37,995 14,463
--------- ---------- ----------
(18,245) 50,845 17,565
--------- ---------- ----------
Deferred:
U.S. federal................................... 126,223 90,944 45,479
U.S. state and local........................... 18,438 3,036 1,097
Foreign........................................ 10,250 11,007 (1,062)
---------- ---------- ----------
154,911 104,987 45,514
---------- ---------- ----------
$ 136,666 $ 155,832 $ 63,079
========== ========== ==========

Income from continuing operations before income taxes consists of the
following for the years ended December 31, 2006, 2005 and 2004:

Year Ended December 31,
--------------------------------------
2006 2005 2004
---------- ---------- ----------
(in thousands)

U.S. federal................................. $ 235,049 $ 194,993 $ 210,786
Foreign...................................... 73,939 155,473 (13,275)
---------- ---------- ----------
$ 308,988 $ 350,466 $ 197,511
========== ========== ==========

Reconciliations of the United States federal statutory tax rate to the
Company's effective tax rate for income from continuing operations are as
follows for the years ended December 31, 2006, 2005 and 2004:

Year Ended December 31,
--------------------------------------
2006 2005 2004
---------- ---------- ----------
(in percentages)

U.S. federal statutory tax rate................... 35.0 35.0 35.0
State income taxes (net of federal benefit)....... 1.7 1.1 1.2
U.S. valuation allowance changes.................. 0.3 0.2 --
Foreign valuation allowances...................... 8.8 0.3 7.8
Rate differential on foreign operations........... 0.5 2.6 14.3
Change in statutory rates......................... 1.0 0.1 --
Gabon investment deduction........................ -- 7.4 (13.1)
Gabon tax free book gain.......................... -- (4.7) --
Repatriation of foreign earnings.................. -- 2.0 --
Conversion of senior convertible notes............ (2.7) -- --
Other............................................. (0.4) 0.5 (13.3)
------- ------- -------
Consolidated effective tax rate................. 44.2 44.5 31.9
======= ======= =======

100

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2006, 2005 and 2004

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, 2006 and 2005:

December 31,
-------------------------
2006 2005
----------- ----------
(in thousands)

Deferred tax assets:
Net operating loss carryforwards................................... $ 102,251 $ 191,314
Alternative minimum tax credit carryforwards....................... -- 10,725
Net deferred hedge losses.......................................... 97,717 291,216
Asset retirement obligations....................................... 76,509 54,338
Other.............................................................. 99,330 95,073
----------- ----------
Total deferred tax assets........................................ 375,807 642,666
Valuation allowances............................................... (94,745) (95,750)
----------- ----------
Net deferred tax assets.......................................... 281,062 546,916
----------- ----------
Deferred tax liabilities:
Oil and gas properties, principally due to differences in basis,
depletion and the deduction of intangible drilling costs for tax
purposes......................................................... 1,232,025 1,053,989
Other.............................................................. 138,272 101,378
----------- ----------
Total deferred tax liabilities................................... 1,370,297 1,155,367
----------- ----------
Net deferred tax liability........................................... $(1,089,235) $( 608,451)
=========== ==========

At December 31, 2006, the Company had NOLs in the United States, Canada,
South Africa and other African countries for 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 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. South Other
-------------------- Canada Africa African
Expiration Date NOL AMT NOL NOL NOL NOLs (a)
--------------- --------- --------- --------- --------- ---------
(in thousands)

2009................... $ 29,999 $ 32,003 $ -- $ -- $ --
2010................... 49,858 47,854 -- -- --
2020................... 5,588 5,055 -- -- --
2021................... 53 -- -- -- --
2026................... -- -- 6,269 -- --
Indefinite............. -- -- -- 49,247 118,190
--------- --------- --------- --------- ---------
$ 85,498 $ 84,912 $ 6,269 $ 49,247 $ 118,190
========= ========= ========= ========= =========

----------

(a) The Company believes that it is more likely than not that these other
African NOLs will not offset future taxable income and has provided a
valuation allowance against these deferred tax assets.

The remaining $85 million of the U.S. NOLs and AMT NOLs are subject to
Section 382 of the Internal Revenue Code and will become available to offset
future regular or alternative minimum taxable income over the next four years.
During the years ended December 31, 2006, 2005 and 2004, the Company utilized
$409.8 million, $311.6 million and $151.1 million of NOLs, respectively.

101

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2006, 2005 and 2004

The Company's income tax provision (benefit) attributable to income from
discontinued operations consisted of the following for the years ended December
31, 2006, 2005 and 2004:

Year Ended December 31,
--------------------------------------
2006 2005 2004
---------- ---------- ----------
(in thousands)

Current:
U.S. federal................................. $ 145,622 $ 2,437 $ --
U.S. state and local......................... 1,421 104 --
Foreign...................................... 2,138 4,297 7,723
---------- --------- ----------
149,181 6,838 7,723
---------- --------- ----------
Deferred:
U.S. federal................................. 144,380 153,075 93,243
U.S. state and local......................... 6,449 6,560 3,996
Foreign...................................... (154) 42,540 (1,682)
---------- ---------- ----------
150,675 202,175 95,557
---------- ---------- ----------
$ 299,856 $ 209,013 $ 103,280
========== ========== ==========

NOTE Q. Income Per Share From Continuing Operations

Basic income per share from continuing operations is computed by dividing
income from continuing operations by the weighted average number of common
shares outstanding for the period. The computation of diluted income per share
from continuing operations reflects the potential dilution that could occur if
securities or other contracts to issue common stock that are dilutive to income
from continuing operations 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 income from continuing
operations to diluted income from continuing operations for the years ended
December 31, 2006, 2005 and 2004:

Year Ended December 31,
--------------------------------------
2006 2005 2004
---------- ---------- ----------
(in thousands)

Basic income from continuing operations............ $ 172,322 $ 194,634 $ 134,432
Interest expense on convertible notes, net of tax.. 1,903 3,207 802
---------- ---------- ----------
Diluted income from continuing operations.......... $ 174,225 $ 197,841 $ 135,234
========== ========== ==========

The following table is a reconciliation of the basic weighted average
common shares outstanding to diluted weighted average common shares outstanding
for the years ended December 31, 2006, 2005 and 2004:

Year Ended December 31,
--------------------------------------
2006 2005 2004
---------- ---------- ----------
(in thousands)

Weighted average common shares outstanding (a):
Basic.......................................... 124,359 137,110 125,156
Dilutive common stock options (b).............. 747 1,136 1,218
Restricted stock awards........................ 989 844 529
Convertible notes dilution (c)................. 1,513 2,327 585
--------- --------- ---------
Diluted........................................ 127,608 141,417 127,488
========= ========= =========

----------

(a) During 2005, the Board approved a share repurchase program authorizing the
purchase of up to $1 billion of the Company's common stock, $640.7 million
of which was completed in 2005 and $345.3 million of which was completed in
2006.

102

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2006, 2005 and 2004

(b) Common stock options to purchase 30,712 shares of common stock were
outstanding but not included in the computations of diluted income per
share from continuing operations for 2004 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 computation.

(c) During 2006, holders of all of the $100 million of 4 3/4% Senior
Convertible Notes exercised their conversion rights.

NOTE R. 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 continuing operations in the United States, Canada, South
Africa, Tunisia and Other. Other is primarily comprised of operations in
Equatorial Guinea, Gabon and Nigeria.

During 2006, the Company sold certain oil and gas properties in the
deepwater Gulf of Mexico and all of its Argentine assets, which had carrying
values of $430.6 million and $658.7 million, respectively, on their dates of
sale. During 2005, the Company sold certain Canadian and United States oil and
gas properties having carrying values of $58.9 million and $31.4 million,
respectively, on their dates of sale. The results of operations of those
properties have been reclassified as discontinued operations in accordance with
SFAS 144 and, aside from costs incurred for oil and gas activities are excluded
from the geographic operating segment information provided below. See Note V for
information regarding the Company's discontinued operations.

The following tables provide the Company's geographic operating segment
data required by SFAS 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 SFAS No. 69, "Disclosures about Oil and Gas Producing
Activities" as of and for the years ended December 31, 2006, 2005 and 2004.
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 income and expenses that are not routinely included in the
earnings measures internally reported to management on a geographic operating
segment basis.

103

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2006, 2005 and 2004

United South Consolidated
States Canada Africa Tunisia Other Headquarters Total
---------- --------- --------- -------- -------- ------------ ------------
(in thousands)

Year ended December 31, 2006:
Revenues and other income:
Oil and gas............................... $1,302,029 $ 123,109 $ 99,309 $ 57,602 $ -- $ -- $ 1,582,049
Interest and other........................ -- -- -- -- -- 58,723 58,723
Gain (loss) on disposition of assets,
net..................................... (451) 77 -- -- -- (7,517) (7,891)
---------- --------- --------- -------- -------- ----------- -----------
1,301,578 123,186 99,309 57,602 -- 51,206 1,632,881
---------- --------- --------- -------- -------- ----------- -----------
Costs and expenses:
Oil and gas production.................... 324,048 49,192 21,795 3,222 -- -- 398,257
Depletion, depreciation and amortization.. 276,921 44,990 9,455 4,007 -- 24,150 359,523
Exploration and abandonments.............. 172,860 13,948 7,516 14,616 55,205 -- 264,145
General and administrative................ -- -- -- -- -- 121,830 121,830
Accretion of discount on asset
retirement obligations.................. -- -- -- -- -- 4,826 4,826
Interest.................................. -- -- -- -- -- 107,032 107,032
Hurricane activity, net................... 32,000 -- -- -- -- -- 32,000
Other..................................... -- -- -- -- -- 36,280 36,280
---------- --------- --------- -------- -------- ----------- -----------
805,829 108,130 38,766 21,845 55,205 294,118 1,323,893
---------- --------- --------- -------- -------- ----------- -----------
Income (loss) from continuing operations
before income taxes....................... 495,749 15,056 60,543 35,757 (55,205) (242,912) 308,988
Income tax benefit (provision).............. (180,948) (4,920) (17,557) (22,450) -- 89,209 (136,666)
---------- --------- --------- -------- -------- ----------- -----------
Income (loss) from continuing operations.... $ 314,801 $ 10,136 $ 42,986 $ 13,307 $(55,205) $ (153,703) $ 172,322
========== ========= ========= ======== ======== =========== ===========
Costs incurred for oil and gas
activities (a)............................ $1,184,280 $ 228,664 $ 131,763 $ 46,149 $ 46,756 $ 35,767 $ 1,673,379
========== ========= ========= ======== ======== =========== ===========
Year ended December 31, 2005:
Revenues and other income:
Oil and gas............................... $1,144,163 $ 114,357 $ 127,470 $ 67,250 $ -- $ -- $ 1,453,240
Interest and other........................ -- -- -- -- -- 31,531 31,531
Gain (loss) on disposition of assets,
net..................................... 12,114 (221) -- -- 47,532 402 59,827
---------- --------- --------- -------- -------- ----------- -----------
1,156,277 114,136 127,470 67,250 47,532 31,933 1,544,598
---------- --------- --------- -------- -------- ----------- -----------
Costs and expenses:
Oil and gas production.................... 277,297 36,725 28,354 4,063 -- -- 346,439
Depletion, depreciation and amortization.. 219,045 31,469 24,494 4,758 -- 20,178 299,944
Impairment of long-lived assets........... -- -- -- -- 644 -- 644
Exploration and abandonments.............. 97,126 9,545 1,211 10,898 44,543 -- 163,323
General and administrative................ -- -- -- -- -- 114,237 114,237
Accretion of discount on asset
retirement obligations.................. -- -- -- -- -- 4,209 4,209
Interest.................................. -- -- -- -- -- 126,086 126,086
Hurricane activity, net................... 39,813 -- -- -- -- -- 39,813
Other..................................... -- -- -- -- -- 99,437 99,437
---------- --------- --------- -------- -------- ----------- -----------
633,281 77,739 54,059 19,719 45,187 364,147 1,194,132
---------- --------- --------- -------- -------- ----------- -----------
Income (loss) from continuing operations
before income taxes....................... 522,996 36,397 73,411 47,531 2,345 (332,214) 350,466
Income tax benefit (provision).............. (190,894) (13,285) (21,289) (32,422) -- 102,058 (155,832)
---------- --------- --------- -------- -------- ----------- -----------
Income (loss) from continuing operations.... $ 332,102 $ 23,112 $ 52,122 $ 15,109 $ 2,345 $ (230,156) $ 194,634
========== ========= ========= ======== ======== =========== ===========
Costs incurred for oil and gas
activities (a)............................ $ 903,390 $ 131,237 $ 18,541 $ 21,317 $ 75,411 $ 129,640 $ 1,279,536
========== ========= ========= ======== ======== =========== ===========

-----------

(a) Costs incurred for Headquarters represents Argentine cost incurred prior to
divestment.

104

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2006, 2005 and 2004

United South Consolidated
States Canada Africa Tunisia Other Headquarters Total
---------- --------- --------- -------- -------- ------------ ------------
(in thousands)

Year ended December 31, 2004:
Revenues and other income:
Oil and gas............................... $ 799,241 $ 50,447 $ 129,856 $ 33,064 $ -- $ -- $ 1,012,608
Interest and other........................ -- -- -- -- -- 2,157 2,157
Gain (loss) on disposition of assets,
net..................................... 51 (252) -- -- -- 240 39
---------- --------- --------- --------- -------- ---------- -----------
799,292 50,195 129,856 33,064 -- 2,397 1,014,804
---------- --------- --------- --------- -------- ---------- -----------
Costs and expenses:
Oil and gas production.................... 174,583 18,810 28,478 3,032 -- -- 224,903
Depletion, depreciation and amortization.. 149,282 22,551 44,091 3,744 -- 11,930 231,598
Impairment of long-lived assets........... -- -- -- -- 39,684 -- 39,684
Exploration and abandonments.............. 55,010 19,062 530 2,042 36,727 -- 113,371
General and administrative................ -- -- -- -- -- 73,192 73,192
Accretion of discount on asset
retirement obligations.................. -- -- -- -- -- 4,130 4,130
Interest.................................. -- -- -- -- -- 102,017 102,017
Other..................................... -- -- -- -- -- 28,398 28,398
---------- --------- --------- --------- -------- ---------- -----------
378,875 60,423 73,099 8,818 76,411 219,667 817,293
---------- --------- --------- --------- -------- ---------- -----------
Income (loss) from continuing operations
before income taxes....................... 420,417 (10,228) 56,757 24,246 (76,411) (217,270) 197,511
Income tax benefit (provision).............. (153,452) 3,861 (17,027) (12,124) -- 115,663 (63,079)
---------- --------- --------- --------- -------- ---------- -----------
Income (loss) from continuing operations.... $ 266,965 $ (6,367) $ 39,730 $ 12,122 $(76,411) $ (101,607) $ 134,432
========== ========= ========= ========= ======== ========== ===========
Costs incurred for oil and gas
activities (a)............................ $2,876,185 $ 120,626 $ 9,473 $ 17,015 $ 48,418 $ 102,452 $ 3,174,169
========== ========= ========= ========= ======== ========== ===========

-----------

(a) Costs incurred for Headquarters represents Argentine cost incurred prior to
divestment.

December 31,
---------------------------------------
2006 2005 2004
----------- ----------- -----------
(in thousands)

Total Assets:
United States.............................. $ 6,395,046 $ 5,899,637 $ 5,460,708
Argentina.................................. 2,444 735,191 708,391
Canada..................................... 547,012 363,773 316,124
South Africa............................... 176,789 64,071 74,250
Tunisia.................................... 72,142 59,125 37,924
Other...................................... 41,238 47,288 10,899
Headquarters............................... 120,728 160,149 125,191
----------- ----------- -----------
Total consolidated assets.................... $ 7,355,399 $ 7,329,234 $ 6,733,487
=========== =========== ===========

NOTE S. Impairment of Oil and Gas Properties

During October 2004, the Company concluded that a $39.7 million 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 increases in steel costs,
the project did not offer competitive returns. The Olowi field was the Company's
only Gabonese investment. During 2005, the Company recorded an incremental
impairment charge of $644 thousand to eliminate the carrying value of the
Company's Gabonese Olowi field.

NOTE T. Volumetric Production Payments

During 2005, the Company sold 27.8 MMBOE of proved reserves by means of
three VPP agreements for net proceeds of $892.6 million, including the
assignment of the Company's obligations under certain derivative hedge

105

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2006, 2005 and 2004

agreements. Proceeds from the VPPs were initially used to reduce outstanding
indebtedness. The first VPP sold 58 Bcf of gas volumes over an expected
five-year term that began in February 2005. The second VPP sold 10.8 million
barrels of oil ("MMBbls") of oil volumes over an expected seven-year term that
began in January 2006. The third VPP sold 6.0 Bcf of gas volumes over an
expected 32-month term that began in May 2005 and 6.2 MMBbls of oil volumes over
an expected five-year term that began in January 2006.

The Company's 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) transfer title to the purchaser; and (v) allow the
Company to retain the assets after the VPPs volumetric quantities have been
delivered.

Under SFAS No. 19, "Financial Accounting and Reporting by Oil and Gas
Producing Companies," a VPP is considered a sale of proved reserves. As a
result, the Company (i) removed the proved reserves associated with the VPPs;
(ii) recognized the VPP proceeds as deferred revenue which are being amortized
on a unit-of-production basis to oil and gas revenues over the terms of the
VPPs; (iii) retained responsibility for 100 percent of the production costs and
capital costs related to VPP interests; and (iv) no longer recognizes production
associated with the VPP volumes.

The following table provides information about the deferred revenue
carrying values of the Company's VPPs:

Gas Oil Total
---------- ---------- ----------
(in thousands)

Deferred revenue at December 31, 2005.......... $ 249,323 $ 605,515 $ 854,838
Less 2006 amortization......................... (74,235) (116,092) (190,327)
---------- ---------- ----------
Deferred revenue at December 31, 2006........ $ 175,088 $ 489,423 $ 664,511
========== ========== ==========

The above deferred revenue amounts will be recognized in oil and gas
revenues in the Consolidated Statements of Operations as noted below, assuming
the related VPP production volumes are delivered as scheduled (in thousands):

2007........................ $ 181,232
2008........................ 158,138
2009........................ 147,906
2010........................ 90,215
2011........................ 44,951
2012........................ 42,069
----------
$ 664,511
==========

NOTE U. Insurance Claims

Hurricane Ivan. During September 2004, the Company sustained damages as a
result of Hurricane Ivan at its Devils Tower and Canyon Express platform
facilities in the deepwater Gulf of Mexico. The damages delayed scheduled well
completions and interrupted production during the second half of 2004 and during
the first half of 2005. The Company maintains business interruption insurance
coverage for such circumstances. During 2004 and 2005, the Company filed claims
with its insurance providers for its estimated losses associated with Hurricane
Ivan.

Based on a settlement agreement between the Company and the insurance
providers, the Company's recoverable business interruption loss related to
Hurricane Ivan was $67.0 million. The Company recorded $7.6 million and $59.4
million of the claims in 2004 and 2005, respectively, in income from
discontinued operations in the accompanying Consolidated Statements of
Operations.

106

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2006, 2005 and 2004

Fain Plant. During May 2005, the Company sustained damages as a result of a
fire at its Fain gas plant in the West Panhandle field. The damages interrupted
production from mid-May through mid-July of 2005. The Company maintained
business interruption and physical damage insurance coverage for such
circumstances. The Company recognized a total of $17.9 million in business
interruption recoveries and $4.4 million in physical damage recoveries
associated with the Fain gas plant fire. The Company recognized $14.2 million of
the business interruption recoveries in 2005 and the remaining $3.7 million in
2006, which is included in other income in the accompanying Consolidated
Statements of Operations.

Hurricanes Katrina and Rita. During August and September 2005, the Company
sustained damages as a result of Hurricanes Katrina and Rita at various
facilities in the Gulf of Mexico. Other than the East Cameron facility discussed
further below, the damages to the facilities were covered by physical damage
insurance.

The Company filed a business interruption claim with its insurance provider
related to its Devils Tower field resulting from its inability to sell
production as a result of damages to third-party facilities. During 2006, the
Company settled its business interruption claim with its insurance provider for
$18.5 million, which is included in income from discontinued operations in the
accompanying Consolidated Statements of Operations.

As a result of Hurricane Rita, the Company's East Cameron facility, located
in the Gulf of Mexico shelf, was destroyed and the Company does not plan to
rebuild the facility based on the economics of the field. During the fourth
quarter of 2006, the Company's application to "reef in-place" a substantial
portion of the East Cameron debris was denied. As a result, the Company
currently estimates that it will cost approximately $119 million to reclaim and
abandon the East Cameron facility. The estimate to reclaim and abandon the East
Cameron facility is based upon an analysis and fee proposal prepared by a
third-party engineering firm for the majority of the work and an estimate by the
Company for the remainder. During 2006 and 2005, the Company recorded additional
abandonment obligation charges of $75.0 million and $39.8 million, respectively,
which amounts are included in hurricane activity, net in the accompanying
Consolidated Statements of Operations. The operations to reclaim and abandon the
East Cameron facilities began in January 2007 and the Company expects to incur a
substantial portion of the costs in 2007.

The $119 million estimate to reclaim and abandon the East Cameron
facilities contains a number of assumptions that could cause the ultimate cost
to be higher or lower as there are many uncertainties when working offshore and
underwater with damaged equipment and wellbores. The Company currently believes
costs could range from $119 million to $175 million; however, at this point no
better estimate than any other amount within the range can be determined, thus
the Company has recorded the estimated provision of $119 million.

The Company has filed a claim with its insurance providers regarding the
loss at East Cameron. Under the Company's insurance policies, the East Cameron
facility had the following coverages: (a) $14 million of scheduled property
value for the platform, (b) $4 million of scheduled business interruption
insurance after a deductible waiting period, (c) $100 million of well
restoration and safety, in total, for all assets per occurrence and (d) $400
million for debris removal coverage for all assets per occurrence.

In December 2005, the Company received the $14 million of scheduled
property value for the East Cameron assets and recognized a gain of $9.7 million
associated therewith. The Company received the $4 million of business
interruption recoveries in 2006, which is reflected in interest and other income
in the accompanying Consolidated Statements of Operations. During the fourth
quarter of 2006, the Company recorded estimated insurance recoveries of $43
million, which is reflected in other current assets in the accompanying
Consolidated Balance Sheet and in hurricane activity, net in the accompanying
Consolidated Statements of Operations, related to the estimated costs for the
debris removal portion of the claim as the Company believes that it is probable
that it will be successful in asserting coverage under the debris removal part
of its insurance coverage. At the present, no recoveries have been reflected
related to the well restoration and safety coverages as the Company is working
to resolve coverage issues regarding coverage under this section of the
insurance policies. Overall, the Company ultimately expects a substantial
portion of the loss to be covered by insurance.

107

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2006, 2005 and 2004

NOTE V. Discontinued Operations

During 2005 and 2006, the Company sold its interests in the following
significant oil and gas assets:

Country Description of Assets Date Divested Net Proceeds Gain
------- --------------------- ------------- ------------ --------
(in millions)

Canada Martin Creek, Conroy Black
and Lookout Butte fields May 2005 $ 197.2 $ 138.3

United States Two Gulf of Mexico shelf August 2005 $ 59.2 $ 27.9
fields

United States Deepwater Gulf of Mexico March 2006 $ 1,156.9 (a) $ 726.2
fields

Argentina Argentine assets April 2006 $ 669.6 $ 10.9

-----------

(a) Net proceeds do not reflect the cash payment of $164.3 million for
terminated hedges associated with the deepwater Gulf of Mexico assets.

Pursuant to SFAS 144, the Company has reflected the results of operations
of the above divestitures as discontinued operations, rather than as a component
of continuing operations. The following table represents the components of the
Company's discontinued operations for the years ended December 31, 2006, 2005
and 2004:

Year Ended December 31,
---------------------------------------
2006 2005 2004
---------- ----------- ----------
(in thousands)

Revenues and other income:
Oil and gas........................................ $ 199,317 $ 806,347 $ 820,055
Interest and other................................. 23,217 65,519 11,918
Gain on disposition of assets (a).................. 733,259 166,088 --
---------- ----------- ----------
955,793 1,037,954 831,973
---------- ----------- ----------
Costs and expenses:
Oil and gas production............................. 31,323 116,638 120,601
Depletion, depreciation and amortization (a)....... 37,327 279,286 343,277
Exploration and abandonments (a)................... 7,327 63,855 68,318
General and administrative......................... 9,266 10,486 7,336
Accretion of discount on asset retirement
obligations (a).................................. 804 3,668 4,080
Interest........................................... 460 1,700 1,370
Other.............................................. 2,021 13,374 5,289
---------- ----------- ----------
88,528 489,007 550,271
---------- ----------- ----------
Income from discontinued operations before
income taxes....................................... 867,265 548,947 281,702
Income tax provision:
Current............................................ 149,181 6,838 7,723
Deferred (a)....................................... 150,675 202,175 95,557
---------- ----------- ----------
Income from discontinued operations.................. $ 567,409 $ 339,934 $ 178,422
========== =========== ==========

----------

(a) Represents the significant noncash components of discontinued operations
included in the Company's Consolidated Statements of Cash Flows.

108

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTARY INFORMATION
Years Ended December 31, 2006, 2005 and 2004

Capitalized Costs

December 31,
---------------------------
2006 2005
------------ ------------
(in thousands)

Oil and gas properties:
Proved........................................................ $ 7,967,708 $ 8,499,253
Unproved...................................................... 210,344 313,881
------------ ------------
Capitalized costs for oil and gas properties.................. 8,178,052 8,813,134
Less accumulated depletion, depreciation and amortization..... (1,895,408) (2,577,946)
------------ ------------
Net capitalized costs for oil and gas properties.............. $ 6,282,644 $ 6,235,188
============ ============

Costs Incurred for Oil and Gas Producing Activities (a)

Property
Acquisition Costs Total
-------------------- Exploration Development Costs
Proved Unproved Costs Costs Incurred
---------- --------- ----------- ----------- -----------
(in thousands)

Year Ended December 31, 2006:
United States........................... $ 78,318 $ 109,321 $ 296,301 $ 700,340 $ 1,184,280
Argentina............................... -- 2 10,223 25,542 35,767
Canada.................................. -- 19,932 103,245 105,487 228,664
South Africa............................ -- -- 288 131,475 131,763
Tunisia................................. -- 5,000 40,813 336 46,149
Other................................... -- 10,584 36,172 -- 46,756
---------- --------- ---------- ----------- -----------
Total................................... $ 78,318 $ 144,839 $ 487,042 $ 963,180 $ 1,673,379
========== ========= ========== =========== ===========
Year Ended December 31, 2005:
United States........................... $ 170,827 $ 60,731 $ 217,723 454,109 $ 903,390
Argentina............................... -- 512 36,878 92,250 129,640
Canada.................................. 2,593 7,344 43,437 77,863 131,237
South Africa............................ -- 259 755 17,527 18,541
Tunisia................................. -- -- 18,395 2,922 21,317
Other................................... -- 30,664 44,456 291 75,411
---------- --------- ---------- ----------- -----------
Total................................... $ 173,420 $ 99,510 $ 361,644 $ 644,962 $ 1,279,536
========== ========= ========== =========== ===========
Year Ended December 31, 2004:
United States........................... $2,220,813 $ 301,856 $ 127,338 $ 226,178 $ 2,876,185
Argentina............................... -- -- 49,745 52,707 102,452
Canada.................................. 50,542 20,921 33,406 15,757 120,626
South Africa............................ -- -- 737 8,736 9,473
Tunisia................................. -- 6,558 5,761 4,696 17,015
Other................................... -- 11,680 26,434 10,304 48,418
---------- --------- ---------- ----------- -----------
Total................................... $2,271,355 $ 341,015 $ 243,421 $ 318,378 $ 3,174,169
========== ========= ========== =========== ===========

----------

(a) The costs incurred for oil and gas producing activities includes the
following amounts of asset retirement obligations:

Year Ended December 31,
------------------------------------
2006 2005 2004
---------- ---------- ----------
(in thousands)

Proved property acquisition costs. $ 981 $ 3,183 $ 10,488
Exploration costs................. 3,376 -- --
Development costs................. 41,111 16,055 4,591
---------- ---------- ----------
Total........................ $ 45,468 $ 19,238 $ 15,079
========== ========== ==========

109

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTARY INFORMATION
Years Ended December 31, 2006, 2005 and 2004

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 R 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, 2006, 2005 and 2004, which are located in the United States, Argentina,
Canada, South Africa and Tunisia, were based on evaluations prepared by the
Company's engineers and 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, 2006, 2005 and 2004 utilized respective oil prices of $60.54, $59.62 and
$41.96 per Bbl (reflecting adjustments for oil quality), respective NGL prices
of $29.82, $36.34 and $29.12 per Bbl, and respective gas prices of $5.13, $6.36
and $4.76 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 proved 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.

The following table provides a rollforward of total proved reserves by
geographic area and in total for the years ended December 31, 2006, 2005 and
2004, 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 MBbls, gas volumes are expressed in MMcf and total volumes are expressed in
thousands of barrels of oil equivalent ("MBOE").

110

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTARY INFORMATION
Years Ended December 31, 2006, 2005 and 2004

Year Ended December 31,
---------------------------------------------------------------------------------------------------
2006 2005 2004
----------------------------- ------------------------------- ---------------------------------
Oil & Oil & Oil &
NGLs Gas NGLs Gas NGLs Gas
(MBbls) (MMcf)(a) MBOE (MBbls) (MMcf)(a) MBOE (MBbls) (MMcf)(a) MBOE
-------- --------- -------- ------- --------- --------- ------- ---------- ---------

Total Proved Reserves:
UNITED STATES
Balance, January 1.......... 385,771 2,750,856 844,247 363,257 3,000,335 863,313 362,751 1,553,976 621,747
Revisions of previous
estimates................... (7,467) (10,664) (9,244) (5,471) (141,473) (29,049) 4,671 25,764 8,965
Purchases of
minerals-in-place........... 41,825 52,308 50,543 65,800 83,179 79,663 11,803 1,571,053 273,646
Extensions and discoveries.. 11,948 136,712 34,733 225 103,616 17,494 1,017 56,690 10,465
Production (b).............. (14,091) (134,445) (36,499) (16,311) (197,391) (49,210) (16,974) (200,598) (50,407)
Sales of minerals-in-place.. (11,261) (108,806) (29,395) (21,729) (97,410) (37,964) (11) (6,550) (1,103)
------- --------- ------- ------- --------- --------- ------- --------- ----------
Balance, December 31........ 406,725 2,685,961 854,385 385,771 2,750,856 844,247 363,257 3,000,335 863,313
ARGENTINA
Balance, January 1.......... 34,024 404,323 101,411 33,168 560,374 126,564 33,469 549,856 125,112
Revisions of previous
estimates................... (306) (2,043) (646) 2,060 (137,640) (20,881) (3,040) (61,483) (13,287)
Extensions and discoveries.. 135 4,576 898 2,334 31,606 7,602 6,428 116,526 25,849
Production (b).............. (1,072) (16,025) (3,743) (3,538) (50,017) (11,874) (3,689) (44,525) (11,110)
Sales of minerals-in-place.. (32,781) (390,831) (97,920) -- -- -- -- -- --
------- --------- ------- ------- --------- --------- ------- --------- ---------
Balance, December 31........ -- -- -- 34,024 404,323 101,411 33,168 560,374 126,564
CANADA
Balance, January 1.......... 2,423 130,514 24,175 4,095 119,869 24,073 2,407 93,829 18,045
Revisions of previous
estimates................... (159) (7,953) (1,485) 434 15,887 3,082 710 8,580 2,140
Purchases of
minerals-in-place........... -- -- -- -- 292 49 823 22,127 4,511
Extensions and discoveries.. 217 66,801 11,351 652 55,130 9,840 541 10,656 2,317
Production (b).............. (282) (15,853) (2,924) (311) (15,665) (2,922) (386) (15,323) (2,940)
Sales of minerals-in-place.. -- -- -- (2,447) (44,999) (9,947) -- -- --
------- --------- ------- ------- --------- --------- ------- --------- ---------
Balance, December 31........ 2,199 173,509 31,117 2,423 130,514 24,175 4,095 119,869 24,073
SOUTH AFRICA
Balance, January 1.......... 3,055 60,395 13,121 3,419 -- 3,419 5,546 -- 5,546
Revisions of previous
estimates................... 1,521 116 1,541 694 -- 694 1,302 -- 1,302
Extensions and discoveries.. -- -- -- 1,347 60,395 11,413 -- -- --
Production (b).............. (1,506) -- (1,506) (2,405) -- (2,405) (3,429) -- (3,429)
------- --------- ------- ------- --------- --------- ------- --------- ---------
Balance, December 31........ 3,070 60,511 13,156 3,055 60,395 13,121 3,419 -- 3,419
TUNISIA
Balance, January 1.......... 3,769 -- 3,769 4,852 -- 4,852 2,018 -- 2,018
Revisions of previous
estimates................... 1,579 59 1,588 (510) -- (510) 3,177 -- 3,177
Extensions and discoveries.. 500 8,223 1,870 696 -- 696 502 -- 502
Production (b).............. (871) (436) (943) (1,269) -- (1,269) (845) -- (845)
------- --------- ------- ------- --------- --------- ------- --------- ---------
Balance, December 31........ 4,977 7,846 6,284 3,769 -- 3,769 4,852 -- 4,852
GABON
Balance, January 1.......... -- -- -- -- -- -- 16,590 -- 16,590
Revisions of previous
estimates................... -- -- -- -- -- -- (16,590) -- (16,590)
------- --------- ------- ------- --------- --------- ------- --------- ---------
Balance, December 31........ -- -- -- -- -- -- -- -- --
TOTAL
Balance, January 1.......... 429,042 3,346,088 986,723 408,791 3,680,578 1,022,221 422,781 2,197,661 789,058
Revisions of previous
estimates................... (4,832) (20,485) (8,246) (2,793) (263,226) (46,664) (9,770) (27,139) (14,293)
Purchases of
minerals-in-place........... 41,825 52,308 50,543 65,800 83,471 79,712 12,626 1,593,180 278,157
Extensions and discoveries.. 12,800 216,312 48,852 5,254 250,747 47,045 8,488 183,872 39,133
Production (b).............. (23,834) (263,073) (67,680) (260,446) (68,731)
(17,822) (166,759) (45,615) (25,323)
Sales of minerals-in-place.. (44,042) (499,637) (127,315) (24,176) (142,409) (47,911) (11) (6,550) (1,103)
------- --------- ------- ------- --------- --------- ------- --------- ---------
Balance, December 31........ 416,971 2,927,827 904,942 429,042 3,346,088 986,723 408,791 3,680,578 1,022,221
======= ========= ======= ======= ========= ========= ======= ========= =========

----------

(a) The proved gas reserves as of December 31, 2006, 2005 and 2004 include
316,528 MMcf, 306,303 MMcf and 271,667 MMcf, respectively, 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) Production for 2006, 2005 and 2004 includes approximately 17,364 MMcf,
14,452 MMcf and 9,605 MMcf of field fuel, respectively. Also, for 2006,
2005 and 2004, production includes 6,811 MBOE, 28,273 MBOE and 33,136 MBOE
of production associated with discontinued operations. See Note V for
additional information.

111

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTARY INFORMATION
Years Ended December 31, 2006, 2005 and 2004

Year Ended December 31,
-----------------------------------------------------------------------------------------------
2006 2005 2004
------------------------------ ----------------------------- ------------------------------
Oil & Oil & Oil &
NGLs Gas NGLs Gas NGLs Gas
(MBbls) (MMcf) MBOE (MBbls) (MMcf) MBOE (MBbls) (MMcf) MBOE
--------- --------- ------- ------- --------- ------- ------- --------- -------

Proved Developed Reserves:
United States................ 210,680 1,875,866 523,324 223,749 2,045,275 564,628 209,349 1,202,264 409,727
Argentina.................... 20,844 282,815 67,980 20,565 320,616 74,001 21,149 352,660 79,926
Canada....................... 2,202 99,025 18,706 3,849 107,547 21,773 2,312 86,500 16,728
South Africa................. 1,708 -- 1,708 3,419 -- 3,419 5,546 -- 5,546
Tunisia...................... 3,769 -- 3,769 4,852 -- 4,852 1,271 -- 1,271
------- --------- ------- ------- --------- ------- ------- --------- -------
Balance, January 1............ 239,203 2,257,706 615,487 256,434 2,473,438 668,673 239,627 1,641,424 513,198
======= ========= ======= ======= ========= ======= ======= ========= =======

United States................ 211,814 1,805,974 512,809 210,680 1,875,866 523,324 223,749 2,045,275 564,628
Argentina.................... -- -- -- 20,844 282,815 67,980 20,565 320,616 74,001
Canada....................... 2,053 117,672 21,665 2,202 99,025 18,706 3,849 107,547 21,773
South Africa................. 1,822 -- 1,822 1,708 -- 1,708 3,419 -- 3,419
Tunisia...................... 4,977 7,846 6,285 3,769 -- 3,769 4,852 -- 4,852
------- --------- ------- ------- --------- ------- ------- --------- -------
Balance, December 31.......... 220,666 1,931,492 542,581 239,203 2,257,706 615,487 256,434 2,473,438 668,673
======= ========= ======= ======= ========= ======= ======= ========= =======

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 ten 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, 2006 commodity prices held constant over each hedge contract's
term, the net present value of the Company's hedge obligations, less associated
estimated income taxes and discounted at ten percent, was a liability of
approximately $82 million at December 31, 2006.

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.

112

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTARY INFORMATION
Years Ended December 31, 2006, 2005 and 2004

The following tables provide the standardized measure of discounted future
cash flows by geographic area and in total for the years ended December 31,
2006, 2005 and 2004, as well as a roll forward in total for each respective
year:

December 31,
-----------------------------------------
2006 2005 2004
------------ ------------ -----------
(in thousands)

UNITED STATES
Oil and gas producing activities:
Future cash inflows.................................... $ 32,162,975 $ 37,171,750 $28,373,520
Future production costs................................ (10,605,170) (10,911,204) (8,232,530)
Future development costs............................... (3,746,920) (2,757,072) (1,829,937)
Future income tax expense.............................. (5,695,788) (7,552,644) (5,612,935)
------------ ------------ -----------
12,115,097 15,950,830 12,698,118
10% annual discount factor............................. (7,925,926) (9,872,066) (7,116,815)
------------ ------------ -----------
Standardized measure of discounted future cash flows.... $ 4,189,171 $ 6,078,764 $ 5,581,303
============ ============ ===========
ARGENTINA
Oil and gas producing activities:
Future cash inflows.................................... $ -- $ 2,256,468 $ 1,747,737
Future production costs................................ -- (366,362) (289,742)
Future development costs............................... -- (353,182) (234,309)
Future income tax expense.............................. -- (282,661) (221,733)
------------ ------------ -----------
-- 1,254,263 1,001,953
10% annual discount factor............................. -- (446,366) (354,661)
------------ ------------ -----------
Standardized measure of discounted future cash flows.... $ -- $ 807,897 $ 647,292
============ ============ ===========
CANADA
Oil and gas producing activities:
Future cash inflows.................................... $ 1,054,264 $ 1,062,258 $ 889,940
Future production costs................................ (399,248) (404,891) (286,197)
Future development costs............................... (115,721) (46,312) (40,023)
Future income tax expense.............................. (69,693) (166,333) (96,431)
------------ ------------ -----------
469,602 444,722 467,289
10% annual discount factor............................. (200,313) (190,655) (190,822)
------------ ------------ -----------
Standardized measure of discounted future cash flows.... $ 269,289 $ 254,067 $ 276,467
============ ============ ===========
SOUTH AFRICA
Oil and gas producing activities:
Future cash inflows.................................... $ 509,081 $ 503,499 $ 140,059
Future production costs................................ (82,989) (56,987) (61,845)
Future development costs............................... (165,318) (248,005) (13,252)
Future income tax expense.............................. (58,870) (18,510) --
------------ ------------ -----------
201,904 179,997 64,962
10% annual discount factor............................. (58,182) (70,453) (2,150)
------------ ------------ -----------
Standardized measure of discounted future cash flows.... $ 143,722 $ 109,544 $ 62,812
============ ============ ===========
TUNISIA
Oil and gas producing activities:
Future cash inflows.................................... $ 329,773 $ 214,982 $ 193,032
Future production costs................................ (47,116) (9,164) (13,536)
Future development costs............................... (16,265) (2,700) (1,245)
Future income tax expense.............................. (148,361) (121,675) (81,680)
------------ ------------ -----------
118,031 81,443 96,571
10% annual discount factor............................. (31,224) (34,818) (21,370)
------------ ------------ -----------
Standardized measure of discounted future cash flows.... $ 86,807 $ 46,625 $ 75,201
============ ============ ===========
TOTAL
Oil and gas producing activities:
Future cash inflows.................................... $ 34,056,093 $ 41,208,957 $31,344,288
Future production costs................................ (11,134,523) (11,748,608) (8,883,850)
Future development costs (a)........................... (4,044,224) (3,407,271) (2,118,766)
Future income tax expense.............................. (5,972,712) (8,141,823) (6,012,779)
------------ ------------ -----------
12,904,634 17,911,255 14,328,893
10% annual discount factor............................. (8,215,645) (10,614,358) (7,685,818)
------------ ------------ -----------
Standardized measure of discounted future cash flows.... $ 4,688,989 $ 7,296,897 $ 6,643,075
============ ============ ===========

---------

(a) Includes $324.1 million, $357.5 million and $258.1 million of undiscounted
future asset retirement expenditures estimated as of December 31, 2006,
2005 and 2004, respectively, using current estimates of future abandonment
costs. See Note L for corresponding information regarding the Company's
discounted asset retirement obligations.

113

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTARY INFORMATION
Years Ended December 31, 2006, 2005 and 2004

Changes in Standardized Measure of Discounted Future Net Cash Flows

Year Ended December 31,
------------------------------------------
2006 2005 2004
------------ ------------ ------------
(in thousands)

Oil and gas sales, net of production costs............. $ (1,516,503) $ (2,227,267) $ (1,719,990)
Net changes in prices and production costs............. (1,921,270) 3,932,683 2,082,706
Extensions and discoveries............................. 413,200 459,251 302,794
Development costs incurred during the period........... 672,572 446,978 249,890
Sales of minerals-in-place............................ (1,926,423) (1,492,864) (14,222)
Purchases of minerals-in-place......................... 280,475 645,315 2,058,195
Revisions of estimated future development costs........ (1,041,343) (907,229) (447,828)
Revisions of previous quantity estimates............... (38,837) (595,873) 140,950
Accretion of discount.................................. 895,455 908,047 644,238
Changes in production rates, timing and other.......... 486,328 78,880 (167,400)
------------ ------------ -------------
Change in present value of future net revenues......... (3,696,346) 1,247,921 3,129,333
Net change in present value of future income taxes..... 1,088,438 (594,099) (1,069,511)
------------ ------------ -------------
(2,607,908) 653,822 2,059,822
Balance, beginning of year............................. 7,296,897 6,643,075 4,583,253
------------ ------------ -------------
Balance, end of year................................... $ 4,688,989 $ 7,296,897 $ 6,643,075
============ ============ =============

Selected Quarterly Financial Results

The following table provides selected quarterly financial results for the
years ended December 31, 2006 and 2005:

Quarter
---------------------------------------------
First Second Third Fourth
--------- --------- --------- ---------
(in thousands, except per share data)

Year ended December 31, 2006:
Oil and gas revenues............................... $ 379,468 $ 407,570 $ 418,106 $ 376,905
Total revenues..................................... $ 396,506 $ 413,908 $ 432,627 $ 389,840
Total costs and expenses........................... $ 376,756 $ 297,815 $ 312,031 $ 337,291
Net income......................................... $ 543,207 $ 88,039 $ 80,799 $ 27,686
Net income per share:
Basic............................................. $ 4.28 $ .70 $ .65 $ .23
Diluted........................................... $ 4.28 $ .69 $ .64 $ .22
Year ended December 31, 2005:
Oil and gas revenues............................... $ 323,826 $ 320,337 $ 389,679 $ 419,398
Total revenues..................................... $ 327,988 $ 332,477 $ 397,938 $ 486,195
Total costs and expenses........................... $ 278,355 $ 256,363 $ 318,988 $ 340,426
Net income......................................... $ 84,657 $ 185,559 $ 123,573 $ 140,779
Net income per share:
Basic............................................. $ .59 $ 1.32 $ .90 $ 1.11
Diluted........................................... $ .58 $ 1.28 $ .88 $ 1.08

During March and April 2006, the Company sold all of its interests in
certain oil and gas properties in the deepwater Gulf of Mexico and its Argentine
assets, respectively. During May and August 2005, the Company sold certain
Canadian and United States Gulf of Mexico shelf assets, respectively. These
divestitures qualified as discontinued operations pursuant to SFAS 144. In
accordance with SFAS 144, the Company reclassified the results of operations and
gains on the sales of the divested assets from continuing operations to
discontinued operations in the Company's consolidated statements of operations.
See Note V of Notes to Consolidated Financial Statements for additional
information regarding these divestitures that gave rise to the adjustments in
the tables above.

114

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 management,
with the participation of its principal executive officer and principal
financial officer, have evaluated, as required by Rule 13a-15(b) under 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 Report.
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 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, 2006, 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, 2006, 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, 2006. 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, 2006, is included
in this Item under the heading "Report of Independent Registered Public
Accounting Firm on Internal Control Over Financial Reporting".

115

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, 2006, 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, 2006, 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, 2006, 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, 2006 and 2005 and the related consolidated statements
of operations, stockholders' equity, cash flows and comprehensive income for
each of the three years in the period ended December 31, 2006 of the Company and
our report dated February 19, 2007 expressed an unqualified opinion thereon.

Ernst & Young LLP

Dallas, Texas
February 19, 2007

116

ITEM 9B. OTHER INFORMATION

None

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The information required in response to this item will be set forth in the
Company's definitive proxy statement for the annual meeting of stockholders to
be held during May 2007 and is incorporated herein by reference.

ITEM 11. EXECUTIVE COMPENSATION

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
AND RELATED STOCKHOLDER MATTERS

Securities Authorized for Issuance under Equity Compensation Plans

The following table summarizes information about the Company's equity
compensation plans as of December 31, 2006:

Number of Securities
Remaining Available for
Future Issuance Under
Number of Securities to Equity Compensation Plans
be Issued Upon Exercise Weighted Average (Excluding Securities
of Outstanding Exercise Price of Reflected in First
Options (a) Outstanding Options Column) (b)
----------------------- ------------------- -------------------------

Equity compensation plans approved by
security holders (c):
Pioneer Natural Resources Company:
2006 Long-Term Incentive Plan....... -- $ -- 4,525,451
Long-Term Incentive Plan............ 1,464,609 $ 20.99 --
Employee Stock Purchase Plan........ -- $ -- 469,527
Predecessor plans..................... 136,886 $ 14.39 --
------------ ------------
1,601,495 4,994,978
============ ============

----------

(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 previous Long-Term Incentive
Plan and the 2006 Long-Term Incentive Plan (the "Plan").

(b) In May 2006, the stockholders of the Company approved the Plan, which
provides for the issuance of up to 4.6 million shares of common stock. No
additional awards may be made under the prior Long-Term Incentive Plan. 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 280,473 cumulative shares issued through
December 31, 2006. 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.

The remaining information required in response to this item will be set
forth in the Company's definitive proxy statement for the annual meeting of
stockholders to be held during May 2007 and is incorporated herein by reference.

117

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR
INDEPENDENCE

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

118

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, 2006 and 2005

Consolidated Statements of Operations for the Years Ended December 31, 2006,
2005 and 2004

Consolidated Statements of Stockholders' Equity for the Years Ended December 31,
2006, 2005 and 2004

Consolidated Statements of Cash Flows for the Years Ended December 31, 2006,
2005 and 2004

Consolidated Statements of Comprehensive Income for the Years Ended December 31,
2006, 2005 and 2004

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.

No financial statement schedules are required to be filed as part of this
Report or they are inapplicable.

119

Exhibits

Exhibit
Number Description
-------- ----------------------------------------------------------------
2.1 -- Purchase and Sale Agreement by and between Pioneer as Seller and
Marubeni Offshore Production (USA) Inc. as Purchaser
(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 February 28, 2006).
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 -- Amended and Restated Bylaws of the Company (incorporated by
reference to Exhibit 3.1 to the Company's Current Report on Form
8-K, dated November 17, 2006, File No. 1-13245).
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 -- Amendment No. 1 to Rights Agreement, dated as of May 22, 2006,
between the Company and Continental Stock Transfer & Trust
Company (incorporated by reference to Exhibit 4.2 to Amendment
No. 1 the Company's Registration Statement on Form 8-A/A, File
No. 1-13245, filed with the SEC on May 23, 2006).
4.4 -- 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).
4.5 -- 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).
4.6 -- 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 4.5 (incorporated by reference to Exhibit 10.5 to the
Company's Quarterly Report on Form 10-Q for the quarter ended
September 30, 1997, File No. 1-13245).
4.7 -- 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 4.5 (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).
4.8 -- 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 4.5
(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).
4.9 -- 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 4.5 (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).
4.10 -- 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).
4.11 -- 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 4.10 (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).
4.12 -- 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 4.10 (incorporated by reference to
Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for
the quarter ended March 31, 2000, File No. 1-13245).

120

4.13 -- 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 4.10 (incorporated by reference to
Exhibit 10.4 to the Company's Quarterly Report on Form 10-Q for
the quarter ended March 31, 2002, File No. 1-13245).
4.14 -- 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 4.10 (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).
4.15 -- 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 4.10 (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).
4.16 -- Sixth Supplemental Indenture, dated as of May 1, 2006, among the
Company, Pioneer Natural Resources USA, Inc. and The Bank of New
York Trust Company, N.A., as Trustee, with respect to the
indenture identified above as Exhibit 4.10 (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 May 4, 2006).
4.17 -- 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).
4.18 -- 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 4.17
(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).
4.19 -- 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 4.17 (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).
4.20 -- 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 4.17 (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).
4.21 -- 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 4.17 (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).
4.22 -- Fifth Supplemental Indenture, dated as of September 16, 2005,
among the Company, Pioneer USA, as Guarantor, and Wachovia Bank,
National Association, as Trustee, with respect to the indenture
identified above as Exhibit 4.17 (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 September 21, 2005).
10.1H -- 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).
10.2H -- 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).
10.3H -- 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
year ended December 31, 1999, File No. 1-13245).
10.4H -- 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
year ended December 31, 1999, File No. 1-13245).
10.5H -- 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
year ended December 31, 1999, File No. 1-13245).

121

10.6H -- Fourth Amendment to the Company's Long-Term Incentive Plan,
effective as of November 20, 2003 (incorporated by reference to
Exhibit 10.5 to the Company's Quarterly Report on Form 10-Q for
the quarter ended March 31, 2005, File No. 1-13245, filed with
the SEC on May 6, 2005).
10.7H -- Fifth Amendment to the Company's Long-Term Incentive Plan,
effective as of May 12, 2004 (incorporated by reference to
Exhibit 10.6 to the Company's Quarterly Report on Form 10-Q for
the quarter ended March 31, 2005, File No. 1-13245, filed with
the SEC on May 6, 2005).
10.8H -- Sixth Amendment to the Company's Long-Term Incentive Plan,
effective as of December 17, 2004 (incorporated by reference to
Exhibit 10.7 to the Company's Quarterly Report on Form 10-Q for
the quarter ended March 31, 2005, File No. 1-13245, filed with
the SEC on May 6, 2005).
10.9H -- Form of Restricted Stock Award Agreement with respect to grants
under the Company's Long-Term Incentive Plan (incorporated by
reference to Exhibit 10.16 to the Company's Quarterly Report on
Form 10-Q for the quarter ended March 31, 2005, File No. 1-13245,
filed with the SEC on May 6, 2005).
10.10H -- Form of Omnibus Nonstatutory Stock Option Agreement for Non-
employee Directors with respect to grants under the Company's
Long-Term Incentive Plan (incorporated by reference to Exhibit
10.17 to the Company's Quarterly Report on Form 10-Q for the
quarter ended March 31, 2005, File No. 1-13245, filed with the
SEC on May 6, 2005).
10.11H -- Form of Omnibus Nonstatutory Stock Option Agreement for Option
Award Participants with respect to grants under the Company's
Long-Term Incentive Plan (Group 1) (incorporated by reference to
Exhibit 10.20 to the Company's Quarterly Report on Form 10-Q for
the quarter ended March 31, 2005, File No. 1-13245, filed with
the SEC on May 6, 2005).
10.12H -- Form of Restricted Stock Unit Agreement for Non-employee
Directors with respect to grants under the Company's Long-Term
Incentive Plan (incorporated by reference to Exhibit 10.19 to the
Company's Annual Report on Form 10-K for the year ended December
31, 2005, File No. 1-13245).
10.13H -- Pioneer Natural Resources Company Employee Stock Purchase Plan,
as amended and restated effective December 9, 2005 (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 December 14,
2005).
10.14H -- The Company's Executive Deferred Compensation Plan, Amended and
Restated Effective as of August 1, 2002 (incorporated by
reference to Exhibit 10.15 to the Company's Quarterly Report on
Form 10-Q for the quarter ended March 31, 2005, File No. 1-13245,
filed with the SEC on May 6, 2005).
10.15G (a) -- Amendment No. 1 to the Company's Executive Deferred Compensation
Plan, effective as of January 1, 2007.
10.16H -- Pioneer USA 401(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).
10.17H -- First Amendment to the Company's Pioneer Natural Resources USA,
Inc. 401(k) and Matching Plan (Amended and Restated Effective as
of January 1, 2002), effective January 10, 2003 (incorporated by
reference to Exhibit 10.10 to the Company's Quarterly Report on
Form 10-Q for the quarter ended March 31, 2005, File No. 1-13245,
filed with the SEC on May 6, 2005).
10.18H -- Second Amendment to the Company's Pioneer Natural Resources USA,
Inc. 401(k) and Matching Plan (Amended and Restated Effective as
of January 1, 2002), effective April 16, 2003 (incorporated by
reference to Exhibit 10.11 to the Company's Quarterly Report on
Form 10-Q for the quarter ended March 31, 2005, File No. 1-13245,
filed with the SEC on May 6, 2005).
10.19H -- Third Amendment to the Company's Pioneer Natural Resources USA,
Inc. 401(k) and Matching Plan (Amended and Restated Effective as
of January 1, 2002), effective June 16, 2003 (incorporated by
reference to Exhibit 10.12 to the Company's Quarterly Report on
Form 10-Q for the quarter ended March 31, 2005, File No. 1-13245,
filed with the SEC on May 6, 2005).
10.20H -- Fourth Amendment to the Company's Pioneer Natural Resources USA,
Inc. 401(k) and Matching Plan (Amended and Restated Effective as
of January 1, 2002), effective December 24, 2003 (incorporated by
reference to Exhibit 10.13 to the Company's Quarterly Report on
Form 10-Q for the quarter ended March 31, 2005, File No. 1-13245,
filed with the SEC on May 6, 2005).
10.21H -- Fifth Amendment to the Company's Pioneer Natural Resources USA,
Inc. 401(k) and Matching Plan (Amended and Restated Effective as
of January 1, 2002), effective September 28, 2004 (incorporated
by reference to Exhibit 10.14 to the Company's Quarterly Report
on Form 10-Q for the quarter ended March 31, 2005, File No.
1-13245, filed with the SEC on May 6, 2005).

122

10.22 -- Amended and Restated 5-Year Revolving Credit Agreement dated as
of September 30, 2005 among the Company, as Borrower, JPMorgan
Chase Bank, N.A. as Administrative Agent 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 October 4, 2005).
10.23 -- 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).
10.24 -- 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).
10.25 -- 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).
10.26 -- Production Payment Purchase and Sale Agreement dated as of April
19, 2005 among the Company, as the Seller, and Wolfcamp Oil and
Gas Trust, as the Buyer (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 April 21, 2005).
10.27H -- 2000 Stock Incentive Plan of Evergreen (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).
10.28H -- Indemnification Agreement dated November 15, 2006, between the
Company and Scott D. Sheffield, together with a schedule
identifying other substantially identical agreements between the
Company and each of its non-employee directors and executive
officers identified on the schedule and identifying the material
differences between each of those agreements and the filed
Indemnification Agreement (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 17, 2006).
10.29H -- Severance Agreement dated August 16, 2005, between the Company
and Scott D. Sheffield, together with a schedule identifying
other substantially identical agreements between the Company and
each of its executive officers identified on the schedule and
identifying the material differences between each of those
agreements and the filed Severance Agreement (incorporated by
reference to Exhibit 10.2 to the Company's Current Report on Form
8-K, File No. 1-13245, filed with the SEC on August 17, 2005).
10.30H -- Severance Agreement dated December 12, 2005, between the Company
and William F. Hannes (incorporated by reference to Exhibit 10.2
to the Company's Current Report on Form 8-K, File No. 1-13245,
filed with the SEC on December 14, 2005).
10.31H -- Change in Control Agreement, dated August 16, 2005, between the
Company and Scott D. Sheffield, together with a schedule
identifying other substantially identical agreements between the
Company and each of its executive officers identified on the
schedule and identifying the material differences between each of
those agreements and the filed Change in Control Agreement
(incorporated by reference to Exhibit 10.3 to the Company's
Current Report on Form 8-K, File No. 1-13245, filed with the SEC
on August 17, 2005).
10.32H -- Change in Control Agreement, dated August 10, 2005, between the
Company and William F. Hannes (incorporated by reference to
Exhibit 10.38 to the Company's Annual Report on Form 10-K for the
year ended December 31, 2005, File No. 1-13245).
10.33 -- Pioneer Natural Resources Company 2006 Long-Term Incentive Plan
(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 May 9, 2006).
10.34 -- Form of restricted stock unit Award Agreement for non-employee
directors with respect to grants under the Company's 2006 Long-
Term Incentive Plan, together with a schedule identifying
substantially identical agreements between the Company and each
of its non-employee directors identified on the schedule and
identifying the material differences between each of those
agreements and the filed Award Agreement (incorporated by
reference to Exhibit 10.2 to the Company's Current Report on Form
8-K, File No. 1-13245, filed with the SEC on May 9, 2006).
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).

123

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 15(b).
G Executive Compensation Plan or Arrangement filed herewith pursuant to
Item 15(b).

124

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 19, 2007
By: /s/ Scott D. Sheffield
---------------------------------
Scott D. Sheffield,
Chairman of the Board and Chief
Executive Officer

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 and Chief February 19, 2007
--------------------------- Executive Officer
Scott D. Sheffield (principal executive officer)

/s/ Richard P. Dealy Executive Vice President and February 19, 2007
--------------------------- Chief Financial Officer
Richard P. Dealy (principal financial officer)

/s/ Darin G. Holderness Vice President and Chief February 19, 2007
--------------------------- Accounting Officer
Darin G. Holderness (principal accounting officer)

/s/ James R. Baroffio Director February 19, 2007
---------------------------
James R. Baroffio

/s/ Edison C. Buchanan Director February 19, 2007
---------------------------
Edison C. Buchanan

/s/ R. Hartwell Gardner Director February 19, 2007
---------------------------
R. Hartwell Gardner

/s/ Linda K. Lawson Director February 19, 2007
---------------------------
Linda K. Lawson

/s/ Andrew D. Lundquist Director February 19, 2007
---------------------------
Andrew D. Lundquist

/s/ Charles E. Ramsey, Jr. Director February 19, 2007
---------------------------
Charles E. Ramsey, Jr.

/s/ Frank A. Risch Director February 19, 2007
---------------------------
Frank A. Risch

Director
---------------------------
Mark S. Sexton

/s/ Robert A. Solberg Director February 19, 2007
---------------------------
Robert A. Solberg

/s/ Jim A. Watson Director February 19, 2007
---------------------------
Jim A. Watson

125

Exhibit Index
-------------

126

4.12 -- 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 4.10 (incorporated by reference to
Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for
the quarter ended March 31, 2000, File No. 1-13245).
4.13 -- 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 4.10 (incorporated by reference to
Exhibit 10.4 to the Company's Quarterly Report on Form 10-Q for
the quarter ended March 31, 2002, File No. 1-13245).
4.14 -- 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 4.10 (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).
4.15 -- 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 4.10 (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).
4.16 -- Sixth Supplemental Indenture, dated as of May 1, 2006, among the
Company, Pioneer Natural Resources USA, Inc. and The Bank of New
York Trust Company, N.A., as Trustee, with respect to the
indenture identified above as Exhibit 4.10 (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 May 4, 2006).
4.17 -- 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).
4.18 -- 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 4.17
(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).
4.19 -- 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 4.17 (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).
4.20 -- 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 4.17 (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).
4.21 -- 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 4.17 (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).
4.22 -- Fifth Supplemental Indenture, dated as of September 16, 2005,
among the Company, Pioneer USA, as Guarantor, and Wachovia Bank,
National Association, as Trustee, with respect to the indenture
identified above as Exhibit 4.17 (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 September 21, 2005).
10.1H -- 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).
10.2H -- 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).
10.3H -- 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
year ended December 31, 1999, File No. 1-13245).

127

10.4H -- 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
year ended December 31, 1999, File No. 1-13245).
10.5H -- 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
year ended December 31, 1999, File No. 1-13245).
10.6H -- Fourth Amendment to the Company's Long-Term Incentive Plan,
effective as of November 20, 2003 (incorporated by reference to
Exhibit 10.5 to the Company's Quarterly Report on Form 10-Q for
the quarter ended March 31, 2005, File No. 1-13245, filed with
the SEC on May 6, 2005).
10.7H -- Fifth Amendment to the Company's Long-Term Incentive Plan,
effective as of May 12, 2004 (incorporated by reference to
Exhibit 10.6 to the Company's Quarterly Report on Form 10-Q for
the quarter ended March 31, 2005, File No. 1-13245, filed with
the SEC on May 6, 2005).
10.8H -- Sixth Amendment to the Company's Long-Term Incentive Plan,
effective as of December 17, 2004 (incorporated by reference to
Exhibit 10.7 to the Company's Quarterly Report on Form 10-Q for
the quarter ended March 31, 2005, File No. 1-13245, filed with
the SEC on May 6, 2005).
10.9H -- Form of Restricted Stock Award Agreement with respect to grants
under the Company's Long-Term Incentive Plan (incorporated by
reference to Exhibit 10.16 to the Company's Quarterly Report on
Form 10-Q for the quarter ended March 31, 2005, File No. 1-13245,
filed with the SEC on May 6, 2005).
10.10H -- Form of Omnibus Nonstatutory Stock Option Agreement for Non-
employee Directors with respect to grants under the Company's
Long-Term Incentive Plan (incorporated by reference to Exhibit
10.17 to the Company's Quarterly Report on Form 10-Q for the
quarter ended March 31, 2005, File No. 1-13245, filed with the
SEC on May 6, 2005).
10.11H -- Form of Omnibus Nonstatutory Stock Option Agreement for Option
Award Participants with respect to grants under the Company's
Long-Term Incentive Plan (Group 1) (incorporated by reference to
Exhibit 10.20 to the Company's Quarterly Report on Form 10-Q for
the quarter ended March 31, 2005, File No. 1-13245, filed with
the SEC on May 6, 2005).
10.12H -- Form of Restricted Stock Unit Agreement for Non-employee
Directors with respect to grants under the Company's Long-Term
Incentive Plan (incorporated by reference to Exhibit 10.19 to the
Company's Annual Report on Form 10-K for the year ended December
31, 2005, File No. 1-13245).
10.13H -- Pioneer Natural Resources Company Employee Stock Purchase Plan,
as amended and restated effective December 9, 2005 (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 December 14,
2005).
10.14H -- The Company's Executive Deferred Compensation Plan, Amended and
Restated Effective as of August 1, 2002 (incorporated by
reference to Exhibit 10.15 to the Company's Quarterly Report on
Form 10-Q for the quarter ended March 31, 2005, File No. 1-13245,
filed with the SEC on May 6, 2005).
10.15G (a) -- Amendment No. 1 to the Company's Executive Deferred Compensation
Plan, effective as of January 1, 2007.
10.16H -- Pioneer USA 401(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).
10.17H -- First Amendment to the Company's Pioneer Natural Resources USA,
Inc. 401(k) and Matching Plan (Amended and Restated Effective as
of January 1, 2002), effective January 10, 2003 (incorporated by
reference to Exhibit 10.10 to the Company's Quarterly Report on
Form 10-Q for the quarter ended March 31, 2005, File No. 1-13245,
filed with the SEC on May 6, 2005).
10.18H -- Second Amendment to the Company's Pioneer Natural Resources USA,
Inc. 401(k) and Matching Plan (Amended and Restated Effective as
of January 1, 2002), effective April 16, 2003 (incorporated by
reference to Exhibit 10.11 to the Company's Quarterly Report on
Form 10-Q for the quarter ended March 31, 2005, File No. 1-13245,
filed with the SEC on May 6, 2005).
10.19H -- Third Amendment to the Company's Pioneer Natural Resources USA,
Inc. 401(k) and Matching Plan (Amended and Restated Effective as
of January 1, 2002), effective June 16, 2003 (incorporated by
reference to Exhibit 10.12 to the Company's Quarterly Report on
Form 10-Q for the quarter ended March 31, 2005, File No. 1-13245,
filed with the SEC on May 6, 2005).

128

10.20H -- Fourth Amendment to the Company's Pioneer Natural Resources USA,
Inc. 401(k) and Matching Plan (Amended and Restated Effective as
of January 1, 2002), effective December 24, 2003 (incorporated by
reference to Exhibit 10.13 to the Company's Quarterly Report on
Form 10-Q for the quarter ended March 31, 2005, File No. 1-13245,
filed with the SEC on May 6, 2005).
10.21H -- Fifth Amendment to the Company's Pioneer Natural Resources USA,
Inc. 401(k) and Matching Plan (Amended and Restated Effective as
of January 1, 2002), effective September 28, 2004 (incorporated
by reference to Exhibit 10.14 to the Company's Quarterly Report
on Form 10-Q for the quarter ended March 31, 2005, File No.
1-13245, filed with the SEC on May 6, 2005).
10.22 -- Amended and Restated 5-Year Revolving Credit Agreement dated as
of September 30, 2005 among the Company, as Borrower, JPMorgan
Chase Bank, N.A. as Administrative Agent 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 October 4, 2005).
10.23 -- 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).
10.24 -- 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).
10.25 -- 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).
10.26 -- Production Payment Purchase and Sale Agreement dated as of April
19, 2005 among the Company, as the Seller, and Wolfcamp Oil and
Gas Trust, as the Buyer (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 April 21, 2005).
10.27H -- 2000 Stock Incentive Plan of Evergreen (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).
10.28H -- Indemnification Agreement dated November 15, 2006, between the
Company and Scott D. Sheffield, together with a schedule
identifying other substantially identical agreements between the
Company and each of its non-employee directors and executive
officers identified on the schedule and identifying the material
differences between each of those agreements and the filed
Indemnification Agreement (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 17, 2006).
10.29H -- Severance Agreement dated August 16, 2005, between the Company
and Scott D. Sheffield, together with a schedule identifying
other substantially identical agreements between the Company and
each of its executive officers identified on the schedule and
identifying the material differences between each of those
agreements and the filed Severance Agreement (incorporated by
reference to Exhibit 10.2 to the Company's Current Report on Form
8-K, File No. 1-13245, filed with the SEC on August 17, 2005).
10.30H -- Severance Agreement dated December 12, 2005, between the Company
and William F. Hannes (incorporated by reference to Exhibit 10.2
to the Company's Current Report on Form 8-K, File No. 1-13245,
filed with the SEC on December 14, 2005).
10.31H -- Change in Control Agreement, dated August 16, 2005, between the
Company and Scott D. Sheffield, together with a schedule
identifying other substantially identical agreements between the
Company and each of its executive officers identified on the
schedule and identifying the material differences between each of
those agreements and the filed Change in Control Agreement
(incorporated by reference to Exhibit 10.3 to the Company's
Current Report on Form 8-K, File No. 1-13245, filed with the SEC
on August 17, 2005).
10.32H -- Change in Control Agreement, dated August 10, 2005, between the
Company and William F. Hannes (incorporated by reference to
Exhibit 10.38 to the Company's Annual Report on Form 10-K for the
year ended December 31, 2005, File No. 1-13245).

129

10.33 -- Pioneer Natural Resources Company 2006 Long-Term Incentive Plan
(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 May 9, 2006).
10.34 -- Form of restricted stock unit Award Agreement for non-employee
directors with respect to grants under the Company's 2006 Long-
Term Incentive Plan, together with a schedule identifying
substantially identical agreements between the Company and each
of its non-employee directors identified on the schedule and
identifying the material differences between each of those
agreements and the filed Award Agreement (incorporated by
reference to Exhibit 10.2 to the Company's Current Report on Form
8-K, File No. 1-13245, filed with the SEC on May 9, 2006).
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.
--------------

130