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

                                    Form 10-K

              ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
                         SECURITIES EXCHANGE ACT OF 1934

                   For the fiscal year ended December 31, 2002

                         Commission File Number: 1-13245

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

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

5205 N. O'Connor Blvd., Suite 1400, Irving, Texas                75039
    (Address of principal executive offices)                   (Zip Code)

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

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

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

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

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

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

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

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

Aggregate market value of the voting common equity held by
non-affiliates of the Registrant computed by reference  to
the price at which the common equity was last sold, 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 .............................    $3,011,384,455

Number of shares of Common Stock outstanding as of
 February 17, 2003 ..........................................       117,299,334

                      Documents Incorporated by Reference:

(1)  Proxy  Statement for Annual Meeting of Shareholders to be held May 15, 2003
     - Referenced in Part III of this report.









                                TABLE OF CONTENTS



                                                                           Page

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

                                     PART I

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

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

Item 2.     Properties...................................................   13

            Proved Reserves..............................................   14
            Finding Cost and Reserve Replacement.........................   14
            Description of Properties....................................   15
            Selected Oil and Gas Information.............................   19

Item 3.     Legal Proceedings............................................   22

Item 4.     Submission of Matters to a Vote of Security Holders..........   22

                                     PART II

Item 5.     Market for Registrant's Common Stock and Related
             Stockholder Matters.........................................   22

Item 6.     Selected Financial Data......................................   23

Item 7.     Management's Discussion and Analysis of Financial
             Condition and Results of Operations.........................   24

            2002 Financial and Operating Performance.....................   24
            2003 Outlook.................................................   25
            Critical Accounting Estimates................................   26
            New Accounting Pronouncements................................   27
            Results of Operations........................................   28
            Capital Commitments, Capital Resources and Liquidity.........   33


                                        2





                            TABLE OF CONTENTS


                                                                           Page

Item 7A.    Quantitative and Qualitative Disclosures About Market Risk...   36

            Quantitative Disclosures.....................................   36
            Qualitative Disclosures......................................   40

Item 8.     Financial Statements and Supplementary Data..................   41

            Index to Consolidated Financial Statements...................   41
            Independent Auditors' Report.................................   42
            Consolidated Financial Statements............................   43
            Notes to Consolidated Financial Statements...................   48
            Unaudited Supplementary Information..........................   81

Item 9.     Changes in and Disagreements With Accountants on Accounting
             and Financial Disclosure....................................   87

                                PART III

Item 10.    Directors and Executive Officers of the Registrant...........   87

Item 11.    Executive Compensation.......................................   87

Item 12.    Security Ownership of Certain Beneficial Owners
             and Management..............................................   87

Item 13.    Certain Relations and Related Transactions...................   87

Item 14.    Controls and Procedures......................................   87

                                 PART IV

Item 15.    Exhibits, Financial Statement Schedules and Reports
             on Form 8-K.................................................   88

            Signatures...................................................   94

            Certifications...............................................   95

            Exhibit Index................................................   97



                                        3





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

Definitions of Oil and Gas Terms and Conventions Used Herein

       Within this Report,  the following oil and gas terms and conventions have
specific  meanings:  "Bbl" means a standard  barrel  containing 42 United States
gallons;  "Bcf"  means  one  billion  cubic  feet;  "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;  "Btu" means  British  thermal unit and is a
measure of the amount of energy  required to raise the  temperature of one pound
of water one degree  Fahrenheit;  "LIBOR" means London  Interbank  Offered Rate,
which is a market rate of  interest;  "MMBtu"  means one million  Btu's;  "MBbl"
means one  thousand  Bbls;  "MBOE"  means one thousand  BOE;  "MMBOE"  means one
million BOE; "Mcf" means one thousand cubic feet and is a measure of natural gas
volume;  "MMcf" means one million  cubic feet;  "NGL" means  natural gas liquid;
"NYMEX"  means The New York  Mercantile  Exchange;  "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.

       "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 United States  Securities and Exchange  Commission  (the
"SEC"),  using prices and costs in effect at the specified date and a 10 percent
discount rate; "acquisition and finding cost per BOE" means total costs incurred
divided  by the  summation  of proved  reserves  attributable  to  revisions  of
previous  estimates,  purchases  of  minerals in place and new  discoveries  and
extensions;   and  "reserve  replacement   percentage"  means,  expressed  as  a
percentage,   the  summation  of  annual  proved  reserves,   on  a  BOE  basis,
attributable to revisions of previous estimates,  purchases of minerals in place
and new discoveries and extensions divided by annual production of oil, NGLs and
gas, on a BOE basis.

       Gas equivalents  are determined under the  relative energy content method
by using the ratio of 6.0 Mcf of gas to 1.0 Bbl of oil or NGL.

       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 Pioneer Natural
Resources 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;  and, all
currency amounts are expressed in U.S. dollars.

                                        4





                                     PART I


ITEM 1.     BUSINESS

General

       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.  Pioneer is an oil and gas  exploration  and production  company
with ownership interests in oil and gas properties located in the United States,
Argentina, Canada, Gabon, South Africa and Tunisia.

       The Company's  executive offices  are located at  5205 N. O'Connor Blvd.,
Suite  1400,  Irving,  Texas  75039.  The  Company's  telephone  number is (972)
444-9001.  The Company maintains other offices in Midland,  Texas; Buenos Aires,
Argentina;  Calgary,  Canada;  Capetown,  South Africa; and Tunis,  Tunisia.  At
December 31, 2002, the Company had 979  employees,  491 of whom were employed in
field and plant operations.

Available Information

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

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

Mission and Strategies

       The Company's mission is to provide shareholders with superior investment
returns through strategies that maximize Pioneer's  long-term  profitability and
net asset value. The strategies  employed to achieve this mission are predicated
on  maintaining  financial   flexibility  and  capital  allocation   discipline.
Historically,  these  strategies have been anchored by the Company's  long-lived
Spraberry  oil field and Hugoton and West  Panhandle  gas fields'  reserves  and
production.  Underlying  these  fields  are  approximately  65  percent  of  the
Company's proved oil and gas reserves which have a remaining  productive life in
excess of 40 years. The stable base of oil and gas production from these fields,
combined  with:  (i)  production  from the Company's  Canyon Express gas project
which began  production in September 2002; (ii) the initial  production from the
Company's Falcon gas discovery in the deepwater Gulf of Mexico and the Sable oil
discovery in South Africa  expected during the second quarter of 2003; and (iii)
initial  production  from  the  Company's  Devils  Tower  oil  discovery  in the
deepwater  Gulf of Mexico  expected  during  the  first  quarter  of 2004,  will
generate  the  operating  cash flows that will provide  Pioneer  with  continued
financial flexibility.  These exploration successes represent the results of the
Company's ability to selectively reinvest capital from the long-lived Spraberry,
Hugoton and West Panhandle fields to areas offering superior investment returns.
Similarly, the Company will continue to: (a) selectively explore for and develop
proved  reserve  discoveries  in areas that offer  superior  reserve  growth and
profitability potential; (b) invest in the personnel and technology necessary to
maximize the Company's  exploration and development  successes;  and (c) enhance
liquidity,  allowing  the  Company  to take  advantage  of  future  exploration,
development  and  acquisition   opportunities.   The  Company  is  committed  to
continuing to enhance shareholder  investment returns through adherence to these
strategies.


                                        5





Business Activities

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

      Petroleum industry.  The  petroleum  industry  has  been  characterized by
fluctuating  oil, NGL and gas commodity  prices and relatively  stable  supplier
costs during the three years ended  December 31, 2002.  During and just prior to
2000, the  Organization of Petroleum  Exporting  Countries  ("OPEC") and certain
other oil exporting  nations reduced their oil export volumes.  Those reductions
in oil export volumes had a positive impact on world oil prices,  as did overall
gas supply and demand  fundamentals  on North American gas prices.  During 2001,
world oil and  North  American  gas  supply  and  demand  fundamentals  shifted,
primarily  as a result  of an  economic  recession  curtailing  demand,  causing
reductions in world oil and North  American gas prices.  During 2002,  world oil
prices increased in response to political  unrest and supply  disruptions in the
Middle East and Venezuela.  During the third and fourth quarters of 2002,  North
American gas prices improved as market fundamentals strengthened.  The Company's
outlook for 2003 commodity  prices is uncertain.  Significant  factors that will
impact 2003 commodity  prices include the final  resolution of issues  currently
impacting Iraq and Venezuela;  the extent to which members of OPEC and other oil
exporting  nations  are able to manage oil supply  through  export  quotas;  and
overall  North  American  gas supply and demand  fundamentals.  To mitigate  the
impact of volatile  commodity  prices on the Company's net asset value,  Pioneer
periodically  enters  into  commodity  hedge  contracts.  See 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  2002,  2001  and 2000  from the  Company's  hedging  activities  and the
Company's open hedge positions at December 31, 2002.

      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
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 Alaska,  the United States Gulf of Mexico
and onshore Gulf Coast areas, and internationally in Argentina,  Canada,  Gabon,
South Africa and Tunisia. Combined, these assets create a portfolio of resources
and  opportunities  that are well balanced among oil, NGLs and gas, and that are
also well balanced between long-lived, dependable production and exploration and
development  opportunities.  Additionally,  the Company has a team of  dedicated
employees that  represent the  professional  disciplines  and sciences that will
allow  Pioneer to  maximize  the  long-term  profitability  and net asset  value
inherent in its physical assets.

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

      Production. The Company focuses its efforts towards maximizing its average
daily production of oil, NGL and gas through  development  drilling,  production
enhancement activities and acquisitions of producing properties while minimizing
the controllable costs associated with the production  activities.  During 2002,
the Company's average daily oil, NGL and gas production  decreased primarily due
to normal production  declines,  reduced Argentine demand for gas, the Company's
curtailment of Argentine  drilling  activities during the first half of 2002 and
the December  2001 sale of the Company's  Rycroft/Spirit  River field in Canada.
During 2001 and 2000,  the Company's  average daily oil, NGL and gas  production
decreased  primarily as a result of oil and gas property  divestitures that were
supportive of the Company's  debt  reduction  goal.  Production,  price and cost
information with respect to the Company's  properties for each of 2002, 2001 and
2000 is set forth under "Item 2. Properties - Selected Oil and Gas Information -
Production, Price and Cost Data".

       Drilling  activities.  The Company  seeks to  increase  its  oil  and gas
reserves,  production and cash flow through exploratory and development drilling
and  by  conducting  other  production  enhancement  activities,  such  as  well
recompletions.  During the five years  ended  December  31,  2002,  the  Company
drilled 1,810 gross (1,279.7 net) wells, 88.5 percent of which were successfully
completed  as productive wells,  at a total drilling cost  (net to the Company's


                                        6





interest) of $1.6  billion.  During 2002,  the Company  drilled 229 gross (153.2
net) wells.  Drilling and facility costs (net to the Company's interest) totaled
$439.3  million  during  2002,  79  percent  of which was  spent on  development
activities  including  $221.6 million  towards  completing  the Canyon  Express,
Falcon and Devils Tower  deepwater Gulf of Mexico projects and the Sable project
offshore South Africa. The Company's current 2003 capital  expenditure budget is
expected to range from $450 million to $550  million.  Excluding the 2002 Falcon
field  and  West  Panhandle  field  acquisitions,  the  Company's  2003  capital
expenditure  budget  is  comparable  to  2002  costs  incurred  for  oil and gas
producing  activities.  Development  expenditures to complete the Falcon, Devils
Tower and Sable projects will decline to approximately  $35 million during 2003,
while aggressive  development  drilling programs in the Company's core Spraberry
oil field,  Hugoton and West Panhandle gas fields, the United States Gulf Coast,
Argentina  and  Canada  will  resume  with  approximately  twice  as many  wells
anticipated  in 2003 versus 2002.  The Company has  allocated  the budgeted 2003
capital expenditures as follows: 65 percent to development drilling and facility
activities and 35 percent to exploration activities.

      The Company believes that its current property base provides a substantial
inventory of prospects for future reserve,  production and cash flow growth. The
Company's  proved  reserves as of December 31, 2002 include  proved  undeveloped
reserves and proved  developed  reserves  that are behind pipe of 154.2  million
Bbls of oil and NGLs and 647.7 Bcf of gas.  Development  of those  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 undeveloped prospects provides attractive
development  and exploration  opportunities  for at least the next three to five
years.

      Exploratory activities.  Since  1998,  the Company has devoted significant
efforts and  resources  on hiring and  developing a highly  skilled  exploration
staff  as  well  as  acquiring   and   drilling  a  portfolio   of   exploration
opportunities.   The  Company's   commitment  to  exploration  has  resulted  in
significant  discoveries  during  this time  period,  such as the 1998 Sable oil
field  discovery in South Africa;  the 1999 Aconcagua,  2000 Devils Tower,  2001
Falcon and 2003 Harrier  discoveries in the deepwater  Gulf of Mexico;  the 2001
Olowi permit discovery located in the Southern Gabon basin; and the 2002 Borj El
Khadra permit  discovery in the Ghadames  basin onshore  Southern  Tunisia.  The
Company  currently  anticipates  that  its  2003  exploration  efforts  will  be
approximately  35 percent of total 2003  expenditures  and will be  concentrated
domestically  in Alaska and the Gulf of Mexico,  and  internationally  in Gabon,
South Africa and Tunisia.  Exploratory  drilling  involves  greater risks of dry
holes or failure to find commercial  quantities of hydrocarbons than development
drilling  or  enhanced  recovery  activities.  See  "Item  1.  Business  - Risks
Associated with Business Activities - Drilling activities" below.

      Asset divestitures.  The Company regularly  reviews its asset base for the
purpose of identifying  non-core 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 financial  flexibility through reduced
debt levels.

      During 2002, 2001 and 2000,  the Company's  divestitures  consisted of the
early  termination  of derivative  hedge  contracts and the sales of oil and gas
properties and other assets for net proceeds of $118.9  million,  $113.5 million
and $102.7  million,  respectively,  which  resulted in 2002,  2001 and 2000 net
divestiture gains of $4.4 million, $7.7 million and $34.2 million, respectively.
The Company's 2002 net proceeds from asset  divestitures  were primarily derived
from the early termination of interest rate and commodity hedges and the sale of
certain gas  properties  in  Oklahoma.  The  Company's  2001  divestitures  were
primarily  derived from the early  termination  of interest  rate and  commodity
hedges, the sale of the Company's remaining  investment in the common stock of a
non-affiliated  entity and the sale of certain  oil  properties  in Canada.  The
assets that the Company  divested  during 2000 were  primarily  comprised  of an
investment in a non-affiliated  entity and  non-strategic  United States oil and
gas  properties  located in  Oklahoma,  New Mexico and  Louisiana.  The net cash
proceeds from the 2002, 2001 and 2000 asset  dispositions were primarily used to
fund additions to oil and gas properties or to reduce the Company's  outstanding
indebtedness.  See Note M of Notes to Consolidated Financial Statements included
in  "Item  8.  Financial   Statements  and  Supplementary   Data"  for  specific
information regarding the Company's asset divestitures.

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



                                        7





      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  2002,  the  Company
expended $195.5 million of acquisition capital to purchase additional  interests
in, and other assets  associated with, its Falcon field  development  project in
the  deepwater  Gulf of Mexico  and its West  Panhandle  gas field and  unproved
property  interests in the Gulf of Mexico,  the Alaskan North Slope, the Borj El
Khadra  permit in Tunisia and other areas.  The Company  purchased,  through two
transactions,  an  additional  30 percent  working  interest in the Falcon field
development  and a 25 percent  working  interest  in  associated  acreage in the
deepwater Gulf of Mexico for a combined  purchase  price of $61.1 million.  As a
result of these transactions, the Company owns a 75 percent working interest and
operates the Falcon field development and related exploration blocks.

      The Company also completed the purchase of the remaining 23 percent of the
rights that the Company did not already own in its core area West  Panhandle gas
field,  100 percent of the West Panhandle  reserves  attributable to field fuel,
100 percent of the related West Panhandle field gathering  system and ten blocks
surrounding  the  Company's  deepwater  Gulf  of  Mexico  Falcon  discovery.  In
connection  with these  transactions,  the  Company  recorded  a $100.4  million
increase to proved oil and gas properties,  a $3.8 million  increase to unproved
oil and gas  properties  and $1.9  million of assets held for resale;  retired a
capital cost obligation for $60.8 million; settled a $20.9 million gas balancing
receivable;  assumed  trade  and  environmental  obligations  amounting  to $5.8
million in the aggregate; and paid $140.2 million of cash.

      During 2001,  the Company  expended  $170.8 million  of capital to acquire
proved and unproved oil and gas  properties.  Excluding  cash and other  working
capital acquired, the Company paid $92.9 million, through the issuance of common
stock,  to complete  the  agreement  and plan of merger among  Pioneer,  Pioneer
Natural   Resources   USA,   Inc.  and  42  affiliated   limited   partnerships.
Additionally,  $77.9 million was spent during 2001 to acquire additional working
interests  in the  deepwater  Gulf of Mexico  Aconcagua  discovery,  the related
Canyon Express gathering system and the Devils Tower project;  21 deepwater Gulf
of Mexico blocks; 250,000 acres in the Anticlinal  Campamento,  Dos Hermanas and
La Calera areas of the Neuquen Basin in Argentina;  and a 30 percent interest in
the Anaguid permit in the Ghadames basin onshore Southern Tunisia.

      During 2000,  the  Company  expended  $67.2  million to acquire proved and
unproved oil and gas properties.  Strategic  acquisitions  of proved  properties
during 2000 included  incremental  working  interests in the  deepwater  Gulf of
Mexico discovery at Devils Tower and the Company's Canadian Chinchaga gas field.
The Company  also  acquired an interest in the Camden  Hills  deepwater  Gulf of
Mexico discovery and the related Canyon Express gathering system during 2000.

      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 acquisitions.

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

Operations by Geographic Area

      The Company operates in one industry segment.  During 2002, 2001 and 2000,
the Company had oil and gas producing activities in the United States, Argentina
and Canada,  and had  exploration  and/or  development  activities in the United
States Gulf Coast area,  the Gulf of Mexico,  Argentina,  Canada,  Gabon,  South
Africa and Tunisia.  See Note P 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.


                                        8





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 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.

      Significant purchasers.  During 2002,  the Company's primary purchasers of
oil were ExxonMobil Corporation ("ExxonMobil") and Plains Marketing LP
("Plains"), the Company's primary purchaser of NGLs was Williams Energy Services
("Williams") and the Company's primary  purchaser of gas was Anadarko  Petroleum
Corporation  ("Anadarko").  Approximately  seven percent of the  Company's  2002
combined  oil,  NGL and gas  revenues  were  attributable  to  sales  to each of
ExxonMobil,  Plains,  Williams and Anadarko.  The Company is of the opinion that
the loss of any one purchaser would not have an adverse effect on its ability to
sell its oil, NGL and gas production.

      Hedging  activities.   The  Company  periodically  enters  into  commodity
derivative  contracts  (swaps and  collars) in order to (i) reduce the effect of
the  volatility of price  changes on the  commodities  the Company  produces and
sells, (ii) support the Company's annual capital budgeting and expenditure plans
and (iii) lock in prices to protect  the  economics  related to certain  capital
projects.  See  "Item 7.  Management's  Discussion  and  Analysis  of  Financial
Condition and Results of Operations" for a description of the Company's  hedging
activities,  "Item 7A.  Quantitative  and Qualitative  Disclosures  About Market
Risk" and Note 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 2002,  2001 and 2000 from the  Company's
commodity hedging activities and the Company's open commodity hedge positions at
December 31, 2002.

Competition, Markets and Regulation

      Competition.  The oil  and gas  industry is  highly  competitive.  A large
number  of  companies  and  individuals   engage  in  the  exploration  for  and
development of oil and gas properties, and there is a high degree of competition
for oil and gas properties suitable for development or exploration. Acquisitions
of oil and gas  properties  have  been an  important  element  of the  Company's
growth.  The Company  intends to continue to acquire oil and gas properties that
complement its operations, provide exploration and development opportunities and
potentially  provide  superior return on investment.  The principal  competitive
factors in the acquisition of oil and gas properties  include the staff and data
necessary  to  identify,  investigate  and  purchase  such  properties  and  the
financial resources necessary to acquire and develop them. 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  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 oil and gas
prices or the degree to which oil and gas prices  will be  affected,  the prices
for any oil or gas that the Company produces will generally  approximate current
market prices in the geographic region.

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

      Oil and gas  exploration  and  production  operations  are also subject to
various  types of  regulation  by local,  state,  federal and foreign  agencies.
Additionally,  the Company's  operations are subject to state  conservation laws
and regulations,  including provisions for the unitization or pooling of oil and
gas properties,  the establishment of maximum rates of production from wells and
the regulation of spacing, plugging and abandonment of wells. States and foreign
governments  generally  impose a  production  or  severance  tax with respect to



                                        9




production and sale of oil and gas within their  respective  jurisdictions.  The
regulatory  burden on the oil and gas industry  increases the Company's  cost of
doing business and, consequently, affects its profitability.

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

      Environmental and health controls. The Company's operations are subject to
numerous  federal,  state,  local and foreign laws and  regulations  relating to
environmental and health protection.  These laws and regulations may require the
acquisition of a permit before drilling commences, restrict the type, quantities
and  concentration  of  various   substances  that  can  be  released  into  the
environment  in connection  with drilling and  production  activities,  limit or
prohibit drilling activities on certain lands lying within wilderness,  wetlands
and other  protected  areas and impose  substantial  liabilities  for  pollution
resulting  from oil and gas  operations.  These  laws and  regulations  may also
restrict  air  emissions or other  discharges  resulting  from the  operation of
natural gas processing  plants,  pipeline  systems and other facilities that the
Company owns.  Although the Company believes that compliance with  environmental
laws and regulations  will not have a material  adverse effect on its 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,  including potential criminal penalties, will
not be  incurred.  Moreover,  it is possible  that other  developments,  such as
stricter environmental laws and regulations or claims for damages to property or
persons  resulting  from the Company's  operations,  could result in substantial
costs and liabilities.

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

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

      The Company currently owns or leases, and has in the past owned or leased,
properties that for many years have been used for the exploration and production
of oil and gas.  Although the Company has used operating and disposal  practices
that were standard in the industry at the time, hydrocarbons or other wastes may
have been disposed of or released on or under the properties  owned or leased by
the Company or on or under other locations where such wastes have been taken for
disposal.  In addition,  some of these  properties  have been  operated by third
parties whose  treatment and disposal or release of hydrocarbons or other wastes
was not under the Company's  control.  These  properties and the wastes disposed
thereon may be subject to CERCLA,  RCRA and  analogous  state  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
Prevention Act of 1990 ("OPA")  amends  certain  provisions of the federal Water
Pollution  Control  Act of 1972,  commonly  referred  to as the Clean  Water Act
("CWA"), and other statutes as they pertain to the prevention of and response to
oil spills into  navigable  waters.  The OPA subjects  owners of  facilities  to
strict joint and several  liability  for all  containment  and cleanup costs and



                                       10




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 have recently begun to regulate
naturally  occurring  radioactive  materials  ("NORM")  and NORM wastes that are
generated in connection with oil and gas exploration and production  activities.
NORM wastes  typically  consist of very low-level  radioactive  substances  that
become concentrated in pipe scale and in production equipment. State regulations
may 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  that the growing  regulation of
NORM will have a minimal effect on the Company's  operations because the Company
generates only a very small quantity of NORM on an annual basis.

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

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

Risks Associated with Business Activities

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

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

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

      Unproved properties.  At December 31,  2002 and 2001,  the Company carried
unproved  property  costs of $219.1  million and $187.8  million,  respectively.
United  States  generally  accepted   accounting   principles  require  periodic
evaluation of these costs on a  project-by-project  basis in comparison to their
estimated  value.   These  evaluations  will  be  affected  by  the  results  of
exploration  activities,  commodity  price  outlooks,  planned  future  sales or



                                       11




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 properties on a profitable basis. The success of
any  acquisition  will depend on a number of factors,  including  the ability to
estimate  accurately  the  recoverable  volumes  of  reserves,  rates of  future
production  and future net revenues  attainable  from the reserves and to assess
possible  environmental  liabilities.  All of these  factors  affect  whether an
acquisition will ultimately generate cash flows sufficient to provide a suitable
return  on  investment.  Even  though  the  Company  performs  a  review  of the
properties  it seeks to acquire  that it believes is  consistent  with  industry
practices, such reviews are often limited in scope.

      Divestitures.  The  Company  regularly reviews its  property  base for the
purpose of  identifying  non-strategic  assets,  the  disposition of which would
increase   capital   resources   available  for  other   activities  and  create
organizational  and operational  efficiencies.  Various factors could materially
affect the ability of the Company to dispose of non-strategic assets,  including
the availability of purchasers  willing to purchase the non-strategic  assets at
prices acceptable to the Company.

      Operation of natural gas processing plants.  As of December 31,  2002, the
Company owns  interests in 11 natural gas  processing  plants and five  treating
facilities.  The  Company  operates  seven of the plants  and all five  treating
facilities. There are significant risks associated with the operation of natural
gas processing  plants.  Gas and NGLs are volatile and explosive and may include
carcinogens.  Damage to or  misoperation  of a natural gas  processing  plant or
facility  could result in an explosion  or the  discharge of toxic gases,  which
could result in significant  damage claims in addition to interrupting a revenue
source.

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

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

      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 or a material  increase in
the costs of  production,  development,  exploration  or processing or otherwise
adversely affect the Company's operations and financial condition. Pollution and
similar environmental risks generally are not fully insurable.

      Debt restrictions and availability.  The Company is a borrower under fixed
term senior notes and a corporate  credit  facility.  The terms of the Company's
borrowings  under the senior notes and the  corporate  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,  interest rates and competition for available debt financing.
See Note E of Notes  to Consolidated  Financial Statements included in  "Item 8.


                                       12





Financial  Statements  and  Supplementary  Data" for  information  regarding the
Company's outstanding debt and the terms associated therewith.

      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 Regulation".

      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 Regulation".

      International operations.  At December 31, 2002,  approximately 20 percent
of the Company's  proved  reserves of oil, NGLs and gas were located outside the
United States (16 percent in Argentina,  three percent in Canada and one percent
in South 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 export, excise and income taxes and United States taxes
on foreign  subsidiaries) and changes in the value of the U.S. dollar versus the
local  currencies in which oil and gas producing  activities may be denominated.
To the extent that the Company is involved in international activities,  changes
in  exchange  rates can  adversely  affect  the  Company's  future  consolidated
financial position, results of operations and liquidity. See Critical Accounting
Estimates included in "Item 7. Management's Discussion and Analysis of Financial
Condition  and  Results  of  Operations"  and Note B of  Notes  to  Consolidated
Financial Statements included in "Item 8. Financial Statements and Supplementary
Data" for information specific to Argentina's economic and political situation.

      Estimates of  reserves  and future  net revenues.  Numerous  uncertainties
exist in  estimating  quantities  of proved  reserves  and future  net  revenues
therefrom.  The estimates of proved reserves and related future net revenues set
forth in this  Report are based on  various  assumptions,  which may  ultimately
prove to be inaccurate.  Therefore,  such  estimates  should not be construed as
accurate estimates of the current market value of the Company's proved reserves.

ITEM 2.     PROPERTIES

      The information included in this  Report about the Company's oil,  NGL and
gas  reserves as of December  31, 2002 was based on reserve  reports  audited by
Netherland,  Sewell &  Associates,  Inc. for the Company's  major  properties in
Canada, South Africa and the United States,  reserve reports audited by Gaffney,
Cline &  Associates,  Inc. for the Company's  properties  located in the Neuquen
Basin in Argentina,  and reserve reports prepared by the Company's engineers for
all other  properties.  The reserve  audits  conducted by  Netherland,  Sewell &
Associates,   Inc.  and  Gaffney,  Cline  &  Associates,   Inc.,  in  aggregate,
represented 71 percent of the Company's  estimated proved quantities of reserves
as of December 31, 2002. The information in this Report about the Company's oil,
NGL and gas  reserves  as of  December  31,  2001 and 2000 was  based on  proved
reserves as determined by the Company's engineers.

      Numerous uncertainties exist  in estimating  quantities of proved reserves
and  in  projecting  future  rates  of  production  and  timing  of  development
expenditures,  including many factors beyond the Company's control.  This Report
contains  estimates of the Company's proved oil and gas reserves and the related
future net revenues,  which are based on various  assumptions,  including  those
prescribed by the SEC. Actual future production,  oil and gas prices,  revenues,
taxes, capital expenditures, operating expenses, geologic success and quantities
of recoverable oil and gas reserves may vary substantially from those assumed in
the estimates and could materially  affect the estimated  quantities and related
Standardized  Measure of proved reserves set forth in this Report.  In addition,
the Company's  reserves may be subject to downward or upward  revisions based on
production  performance,  purchases  or sales of  properties,  results of future
development,  prevailing  oil and  gas  prices  and  other  factors.  Therefore,
estimates of the Standardized Measure of proved reserves should not be construed
as  accurate  estimates  of the current  market  value of the  Company's  proved
reserves.

      Standardized Measure  is a  reporting  convention  that  provides a common
basis for comparing oil and gas companies  subject to the rules and  regulations
of the SEC. It requires the use of oil and gas spot prices  prevailing as of the
date of  computation.  Consequently,  it may not reflect  the prices  ordinarily
received  or that will be received  for oil and gas  because of  seasonal  price
fluctuations or other varying market conditions. Standardized Measures as of any



                                       13





date  are  not   necessarily   indicative  of  future   results  of  operations.
Accordingly,  estimates included herein of future net revenues may be materially
different from the net revenues that are ultimately received.

      The Company did not provide estimates of total proved oil and gas reserves
during 2002,  2001 or 2000 to any federal  authority  or agency,  other than the
SEC.

Proved Reserves

      The Company's proved reserves totaled  736.7 million  BOE at  December 31,
2002,  671.4  million BOE at December 31, 2001 and 628.2 million BOE at December
31,  2000,   representing   $4.1   billion,   $2.5  billion  and  $5.6  billion,
respectively,  of  Standardized  Measure or $5.1 billion,  $2.5 billion and $7.0
billion,  respectively,  on a pre-tax basis. The ten percent increase in reserve
volumes  and 65  percent  increase  in  Standardized  Measure  during  2002 were
attributable  to an increase in commodity  prices,  the purchase of  incremental
interests in two core assets and the Company's  successful capital  investments.
The seven percent  increase in proved reserve  volumes during 2001 was primarily
attributable  to the  Company's  successful  capital  investments,  while the 56
percent  decrease  in  Standardized  Measure  during 2001 was  primarily  due to
decreases in commodity prices.

      On a  BOE basis,  67  percent of the  Company's  total proved  reserves at
December 31, 2002 were proved developed  reserves.  Based on reserve information
as of December 31, 2002,  and using the  Company's  production  information  for
2002,  the  reserve-to-production  ratio  associated  with the Company's  proved
reserves was 18 years on a BOE basis.  The following table provides  information
regarding  the  Company's  proved  reserves  and  average  daily  production  by
geographic area as of and for the year ended December 31, 2002:

            PROVED OIL AND GAS RESERVES AND AVERAGE DAILY PRODUCTION


                                                                                        2002 Average
                               Proved Reserves as of December 31, 2002               Daily Production (a)
                         --------------------------------------------------    --------------------------------
                            Oil                                Standardized      Oil
                          & NGLs         Gas                      Measure       & NGLs       Gas
                          (MBbls)       (MMcf)       MBOE          (000)        (Bbls)      (Mcf)        BOE
                         ---------    ---------    --------    ------------    --------    --------    --------

                                                                                  
United States.........     337,631    1,483,971     584,960     $ 3,456,691      43,949     232,360      82,677
Argentina.............      31,532      532,081     120,211         340,106       8,680      78,220      21,716
Canada................       2,361      119,328      22,249         199,012       1,070      48,365       9,131
South Africa..........       8,475          -         8,475         121,363         -           -           -
Tunisia...............         845          -           845           9,380         -           -           -
                         ---------    ---------    --------      ----------    --------    --------    --------
Total.................     380,844    2,135,380     736,740     $ 4,126,552      53,699     358,945     113,524
                         =========    =========    ========      ==========    ========    ========    ========

- ----------------
(a)  The 2002 average daily  production was calculated  using a 365-day year and
     without making pro forma adjustments for any acquisitions,  divestitures or
     drilling activity that occurred during the year.

Finding Cost and Reserve Replacement The Company's acquisition and finding costs per BOE for 2002, 2001 and 2000 were $6.30, $7.49 and $4.66 per BOE, respectively. The average acquisition and finding cost for the three-year period from 2000 to 2002 was $6.24 per BOE, representing a 32 percent increase over the 2001 three-year average rate of $4.74 per BOE. This increase was largely attributable to the $221.6 million of development capital that the Company spent during 2002 to develop its Canyon Express, Falcon and Devils Tower development projects in the deepwater Gulf of Mexico and its Sable development project offshore South Africa. During 2002, the Company replaced 258 percent of its annual production on a BOE basis (384 percent for oil and NGLs and 144 percent for gas). During 2001, the Company replaced 208 percent of its annual production on a BOE basis (169 percent for oil and NGLs and 245 percent for gas). During 2000, the Company replaced 167 percent of its annual production on a BOE basis (196 percent for oil and NGLs and 140 percent for gas). The Company's 2002 reserve replacement percentage was the result of revisions of previous estimates and revisions related to changes in commodity prices, asset purchases and new discoveries and field extensions. The Company's 2001 reserve replacement percentage was 14 primarily impacted by asset purchases and new discoveries and field extensions while the 2000 reserve replacement percentage was primarily impacted by revisions related to changes in commodity prices. Description of Properties As of December 31, 2002, the Company has production and/or development and exploration operations in the United States, Argentina, Canada, South Africa and Tunisia, and exploration opportunities in Gabon. Domestic. The Company's domestic operations are located in the Permian Basin, Mid Continent, Gulf of Mexico and onshore Gulf Coast areas of the United States. The Company also has unproved properties in Alaska. Approximately 82 percent of the Company's domestic proved reserves are located in the Spraberry, Hugoton and West Panhandle fields. The mature Spraberry, Hugoton and West Panhandle fields generate substantial operating cash flow and have a portfolio of low risk infill drilling opportunities. The cash flows generated from these fields provide funding for the Company's other development and exploration activities both domestically and internationally. During 2002, the Company expended $533.6 million in domestic acquisition, exploration and development drilling activities. The Company has budgeted approximately $300 million for domestic acquisition, exploration and development drilling expenditures for 2003. 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 per Mcf. The oil and gas are produced from three formations, the upper and lower Spraberry and the Dean, at depths ranging from 6,700 feet to 9,200 feet. The center of the Spraberry field was unitized in the late 1950's and early 1960's by the major oil companies; however, until the late 1980's there was very limited development activity in the field. Since 1989, the Company has focused its development drilling activities in the unitized portion of the Spraberry field due to the dormant condition of the properties. The Company believes the area offers excellent opportunities to enhance oil and gas reserves because of the hundreds of undeveloped infill drilling locations, many of which are reflected in the Company's proved undeveloped reserves, and the ability to reduce operating expenses through economies of scale. During 2002, the Company placed 89 Spraberry wells on production, drilled one developmental dry hole and, at December 31, 2002, had two wells in progress. The Company plans to drill approximately 150 development wells in the Spraberry field during 2003. 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 Hugoton properties represent approximately 13 percent of the proved reserves in the field and are located on approximately 257,000 gross acres (237,000 net acres), covering approximately 400 square miles. The Company has working interests in approximately 1,200 wells in the Hugoton field, about 1,000 of which it operates, and partial royalty interests in approximately 500 wells. The Company owns substantially all of the gathering and processing facilities, primarily the Satanta plant, that service its production from the Hugoton field. Such ownership allows the Company to control the production, gathering, processing and sale of its gas and associated NGLs. The Company's Hugoton operated wells are capable of producing approximately 97 MMcf of wet gas per day (i.e., gas production at the wellhead before processing and before reduction for royalties), although actual production in the Hugoton field is limited by allowables set by state regulators. The Company estimates that it and other major producers in the Hugoton field produced at or near capacity in 2002. During 2002, the Company completed four development wells in the Hugoton field and plans for 2003 include approximately 30 wells to be drilled. The Company is continuing to evaluate the feasibility of infill drilling into the Council Grove Formation and may submit an application to the Kansas Corporation Commission to allow infill drilling. Such infill drilling may increase production from the Company's Hugoton properties. However, until an application has been approved, the Company will not reflect any of the infill drilling locations as proved undeveloped reserves. There can be no assurance that the application will be filed or approved, or as to the timing of such approval if granted. West Panhandle field. The West Panhandle properties are located in the panhandle region of Texas where initial production commenced in 1918. These stable, long-lived reserves are attributable to the Red Cave, Brown Dolomite, 15 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 per Mcf and is produced from approximately 600 wells on more than 241,000 acres covering over 375 square miles. The Company's wellhead gas produced from the West Panhandle field contains a high quantity of NGLs, yielding relatively greater NGL volumes than realized from the Company's 1,025 Btu per Mcf content wellhead gas in its Hugoton field. In 2002, the Company purchased the remaining rights it did not already own in the field as well as the gathering system. The Company now controls the wells, production equipment, gathering system and gas processing plant for the field. During 2002, the Company placed 40 new wells on production, drilled three developmental dry holes and had four wells in progress at December 31, 2002. The Company plans to drill approximately 100 wells in the West Panhandle field during 2003. Gulf of Mexico area. In the Gulf of Mexico, the Company is focused on reserve and production growth through a portfolio of shelf and deepwater development projects, high-impact, higher-risk deepwater exploration drilling, shelf exploration drilling and exploitation opportunities inherent in the properties the Company currently has producing on the shelf. To accomplish this, the Company has devoted most of its domestic exploration efforts to these two areas, as well as its investment in and utilization of 3-D seismic technology. During 2002, the Company successfully drilled six development and four exploratory wells in the deepwater Gulf of Mexico and one successful exploratory well and one successful development well on the shelf. The Company also drilled two exploratory dry holes in the deepwater Gulf of Mexico and one exploratory dry hole on the shelf during 2002. In the deepwater Gulf of Mexico, the Company has sanctioned three major development projects, one of which is now on production and two that were in progress at December 31, 2002: o Canyon Express - The TotalFinaElf-operated Aconcagua and the Marathon-operated Camden Hills discoveries in Mississippi Canyon were jointly developed as part of the Canyon Express gas project. Production start-up occurred in late September; however, several operational and mechanical difficulties were encountered which has resulted in the Company not reaching its estimated net production level of 110 to 120 MMcf of gas per day until late January 2003. o Devils Tower - At the Dominion-operated Devils Tower development project in Mississippi Canyon, the Company successfully drilled two wells to explore for new reserves in previously undrilled reservoirs and to further extend the previously tested zones and three development wells. During 2001, the project was sanctioned as a spar development project with the owners leasing a spar from a third party for the life of the field. Construction of the spar is in progress, the eight producing wells on Devils Tower have been drilled and are awaiting completion and production is anticipated to begin during the first quarter of 2004. The wells will be brought on sequentially with peak production expected to reach 12,000 to 15,000 BOEs per day net to the Company's 25 percent working interest. o Falcon - The Company-operated Falcon project is on pace to be on production in April 2003. Two development wells were drilled and completed during 2002 and the final stages of the facilities fabrication and installation are currently underway. Peak production from Falcon is anticipated at rates of approximately 130 MMcf of gas per day net to the Company's 75 percent working interest. During 2002, the Company also participated in two appraisal sidetrack wells on the Marathon-operated deepwater Gulf of Mexico Ozona Deep prospect, of which one was a discovery. The 2002 discovery sidetrack appraisal well further extended the 2001 Ozona Deep discovery that originally encountered approximately 345 feet of net oil pay in two intervals. The Company is currently evaluating possible tie-back opportunities to existing facilities in the area, the economics of which will determine future activities. The Company also successfully drilled its Dominion-operated Triton prospect near Devils Tower. Proved reserves were recorded for this prospect and it will be completed as a subsea tieback to Devils Tower. Exploration drilling near the Falcon discovery began in December 2002 with the Lightning prospect and in January 2003 on the H2.5 and Harrier prospects. The Lightning and H2.5 exploratory wells were unsuccessful; however, the Harrier prospect was announced as a discovery in late January 2003. It is anticipated that the Harrier well will be completed with a subsea tieback to Falcon within nine to 15 months. During 2003, the Company also plans to drill its Buff prospect, which is also near the Falcon discovery. 16 During January 2003, the Company announced a joint exploration agreement with Woodside Energy (USA) Inc. ("Woodside"), a subsidiary of Woodside Energy Ltd. of Australia, for a two-year drilling program over the shallow- water Texas shelf region of the Gulf of Mexico. Under the agreement, Woodside has taken a 50 percent working interest in 47 offshore exploration blocks operated by the Company. The agreement covers eight prospects and 19 leads and includes five exploratory wells to be drilled in 2003 and three in 2004. Most of the wells to be drilled under the agreement will target gas plays below 15,000 feet. The eight wells to be drilled by the parties in 2003 and 2004 are on prospects generated and leased by the Company since 1997. Additionally, the Company and Woodside will evaluate for potential inclusion in the drilling program shallower gas prospects on the Gulf of Mexico shelf on other blocks covered by the leases. Onshore Gulf Coast area. The Company has focused its drilling efforts in this area on the Pawnee field in the Edwards Reef trend in South Texas. The Company drilled six development wells at Pawnee during 2002, had one well in progress at year end and plans to drill seven wells in 2003. Alaska area. During the fourth quarter of 2002, the Company signed an agreement with Armstrong Resources LLC under which the Company was assigned a 70 percent working interest and operatorship in ten state leases on Alaska's North Slope. The leases cover approximately 14,000 undeveloped acres between the Kuparuk River unit and Thetis Island. The Company plans to drill up to three exploratory wells during the first quarter of 2003. The wells will test an area that the Company believes is prospective for oil in the same sands as the offsetting Kuparuk River unit eight to ten miles to the southeast. The Kuparuk River unit was discovered in 1969 and is estimated to hold 2.5 billion barrels of recoverable oil. No wells have been drilled on the acreage covered by the Company's leases to date, but wells drilled just outside the perimeter of the acreage have encountered the primary target Kuparuk "C" sands and were oil-bearing. The acreage is offshore in approximately five to ten feet of water. Drilling plans call for grounded sea ice pad locations that will be accessed via ice roads from Oliktok Point dock. All sea ice operations are expected to be completed by the end of March 2003. International. The Company's international operations are located in the Neuquen and Austral Basins areas of Argentina and the Chinchaga, Martin Creek and Lookout Butte areas of Canada. Additionally, the Company's other significant development projects, the Sable oil field located in shallow water offshore South Africa and the Adam discovery in southern Tunisia, are scheduled for first production in mid-2003. The Company has also entered into agreements to explore for oil and gas reserves in South Africa, Gabon and Tunisia. As of December 31, 2002, approximately 16 percent, three percent, one percent and one tenth of one percent of the Company's proved reserves are located in Argentina, Canada, South Africa and Tunisia, respectively. Argentina. The Company's share of Argentine production during 2002 averaged 21.7 MBOE per day, or approximately 19 percent of the Company's equivalent production. The Company's operated production in Argentina is concentrated in the Neuquen Basin which is located about 925 miles southwest of Buenos Aires and to the east of the Andes Mountains. Oil and gas are produced primarily from the Al Norte de la Dorsal, the Al Sur de la Dorsal, the Dadin, the Loma Negra, the Anticlinal Campamento and the Estacion Fernandez Oro blocks, in each of which the Company has a 100 percent working interest. Most of the gas produced from these blocks is processed in the Company's recently completed Loma Negra gas processing plant. The Company also operates and has a 50 percent working interest in the Lago Fuego field which is located in Tierra del Fuego, an island in the extreme southern portion of Argentina, approximately 1,500 miles south of Buenos Aires. Most of the Company's non-operated production in Argentina is located in Tierra del Fuego where oil, gas and NGLs are produced from six separate fields in which the Company has a 35 percent working interest. The Company also has a 14.4 percent working interest in the Confluencia field which is located in the Neuquen Basin. During 2002, the Company expended $35.1 million on Argentine development and exploration activities. The Company drilled 14 development wells and 17 extension/exploratory wells, of which 13 development wells and nine extension/exploratory wells were successful. Also during 2002, the Company completed its gas processing plant at Loma Negra and completed a 35 mile gas pipeline that connects the Loma Negra plant to a main gas transmission line that accesses the Buenos Aires gas market. The Company plans to spend approximately $45 million on oil and gas development and exploration opportunities in Argentina during 2003. 17 Canada. The Company's Canadian producing properties are located primarily in Alberta and British Columbia, Canada. Production during 2002 averaged 9.1 MBOE per day, or approximately eight percent of the Company's equivalent production. The Company continues to focus its development, exploration and acquisition activities in the core areas of northeast British Columbia and southwest Alberta. The Canadian assets are geographically concentrated, predominantly shallow gas and more than 95 percent operated by the Company in the following areas: Chinchaga, Martin Creek and Lookout Butte. Production from the Chinchaga area in northeast British Columbia is relatively dry gas from formation depths averaging 3,400 feet. In the Martin Creek area of British Columbia, production is relatively dry gas from various reservoirs ranging from 3,700 feet to 4,300 feet. The Lookout Butte area in southwest Alberta produces gas and condensate from the Mississippian Turner Valley formation at approximately 12,000 feet. During 2002, the Company expended $33.5 million on Canadian development, exploration and acquisition activities. The Company drilled 17 development wells and 12 exploratory wells, primarily in the Chinchaga and Martin Creek areas, of which 13 development wells and 9 exploratory wells were successful. Most of these wells were drilled during the first quarter as these areas are only accessible for drilling during the winter months. The Company plans to spend approximately $45 million on oil and gas development and exploration opportunities in Canada during 2003. Africa. In Africa, the Company has entered into agreements to explore for oil and gas in South Africa, Gabon and Tunisia. The amended South African agreements cover over five million acres along the southern coast of South Africa, generally in water depths less than 650 feet. The Gabon agreement covers 313,937 acres off the coast of Gabon, generally in water depths less than 100 feet. The Tunisian agreements can be separated into two categories: the first includes three permits covering 2.9 million acres onshore southern Tunisia which the Company operates with a 50 percent working interest and the second includes the Anadarko-operated Anaguid permit covering 1.2 million acres onshore southern Tunisia in which the Company has a 38.7 percent working interest and the AGIP-operated Borj El Khadra permit covering 1.2 million acres onshore southern Tunisia in which the Company has a 40 percent working interest. During 2002, the Company expended $70.3 million of acquisition, development and exploration drilling and seismic capital in South Africa, Gabon and Tunisia. South Africa. In South Africa, the Company spent $37.1 million of drilling and seismic capital to drill four successful development wells on its Petro SA-operated Sable development project. During 2003, the Company plans to complete its Sable development project with production anticipated to begin during the second quarter of 2003. Production for the first year is expected to average approximately 12,100 Bbls of oil per day net to the Company's 40 percent working interest. In addition, the Company currently plans to drill three exploration wells in South Africa during 2003. Gabon. In Gabon, the Company spent $23.6 million of drilling and seismic capital to drill and test three additional exploratory wells on its Bigorneau South prospect, located offshore in the Southern Gabon Basin on its Olowi permit. Pioneer is the operator of the permit with a 100 percent working interest. To date, the Company has drilled and tested four successful offshore wells which have established significant oil in place. Full development of the field is expected to involve substantial capital investment underscoring the importance of confirming reservoir characteristics and productivity. Pioneer is currently seeking bids for the development of an early production system covering a limited field area which would allow the Company to gain additional information needed to design a full field development plan. The Company is also seeking improved fiscal terms from the government. Tunisia. In Tunisia, the Company spent $8.2 million of acquisition, drilling and seismic capital primarily to acquire a 40 percent interest in and drill an exploration well on the AGIP-operated Borj El Khadra permit. This well encountered several oil and gas productive zones that tested up to 6,000 Bbls of oil per day. The Company plans to complete the construction of a 15 kilometer flowline from the discovery to an AGIP-operated facility during the third quarter of 2003, allowing production to begin from the initial well shortly thereafter. A development well is scheduled to be drilled in the fourth quarter of 2003. In addition to this development project, plans for Tunisia in 2003 include an exploration well to be drilled on the Company-operated Jorf permit, two exploration wells to be drilled on the Anadarko-operated Anaguid permit and an additional exploration well to be drilled on the AGIP-operated Borj El Khadra permit. 18 Selected Oil and Gas Information The following tables set forth selected oil and gas information for the Company as of and for each of the years ended December 31, 2002, 2001 and 2000. Because of normal production declines, increased or decreased drilling activities and the effects of past and future acquisitions or divestitures, the historical information presented below should not be interpreted as being indicative of future results. Production, price and cost data. The following table sets forth production, price and cost data with respect to the Company's properties for the years ended December 31, 2002, 2001 and 2000: PRODUCTION, PRICE AND COST DATA (a) Year Ended December 31, -------------------------------------------------------------------------------------------------------------- 2002 2001 2000 ----------------------------------- ---------------------------------- ---------------------------------- United United United States Argentina Canada Total States Argentina Canada Total States Argentina Canada Total ------ --------- ------ ------- ------ --------- ------ ------- ------- --------- ------ ------- Production information: Annual production: Oil (MBbls).... 8,555 2,914 45 11,514 8,629 3,566 303 12,498 8,989 3,238 308 12,535 NGLs (MBbls)... 7,487 254 345 8,086 7,232 200 368 7,800 7,883 193 303 8,379 Gas (MMcf)..... 84,811 28,551 17,653 131,015 77,609 31,830 18,426 127,865 83,930 35,695 16,219 135,844 Total (MBOE)... 30,177 7,926 3,333 41,436 28,796 9,071 3,742 41,609 30,861 9,380 3,314 43,555 Average daily production: Oil (Bbls)..... 23,437 7,984 124 31,545 23,641 9,769 831 34,241 24,561 8,847 841 34,249 NGLs (Bbls).... 20,512 696 946 22,154 19,815 547 1,008 21,370 21,538 527 829 22,894 Gas (Mcf)...... 232,360 78,220 48,365 358,945 212,629 87,204 50,481 350,314 229,316 97,526 44,315 371,157 Total (BOE).... 82,677 21,716 9,131 113,524 78,894 24,851 10,253 113,997 84,318 25,628 9,056 119,002 Average prices, including hedge results: Oil (per Bbl).. $ 23.66 $ 20.63 $22.26 $ 22.89 $ 24.34 $23.79 $ 21.87 $ 24.12 $ 22.07 $29.09 $27.50 $ 24.01 NGLs (per Bbl). $ 13.77 $ 14.56 $16.77 $ 13.92 $ 16.88 $19.29 $ 21.11 $ 17.14 $ 20.05 $22.91 $24.32 $ 20.27 Gas (per Mcf).. $ 3.16 $ .48 $ 2.50 $ 2.49 $ 4.10 $ 1.31 $ 2.86 $ 3.23 $ 3.50 $ 1.19 $ 2.88 $ 2.81 Revenue (per BOE)$ 19.00 $ 9.79 $15.27 $ 16.94 $ 22.56 $14.36 $ 17.94 $ 20.36 $ 21.04 $15.03 $18.85 $ 19.58 Average prices, excluding hedge results: Oil (per Bbl).. $ 23.85 $ 20.33 $22.26 $ 22.95 $ 24.56 $22.40 $ 21.87 $ 23.88 $ 28.76 $29.09 $27.50 $ 28.81 NGLs (per Bbl). $ 13.77 $ 14.56 $16.77 $ 13.92 $ 16.88 $19.29 $ 21.11 $ 17.14 $ 20.05 $22.91 $24.32 $ 20.27 Gas (per Mcf).. $ 3.02 $ .48 $ 2.40 $ 2.38 $ 3.96 $ 1.31 $ 3.27 $ 3.20 $ 3.73 $ 1.19 $ 3.45 $ 3.03 Revenue (per BOE)$ 18.65 $ 9.68 $14.77 $ 16.63 $ 22.26 $13.81 $ 19.95 $ 20.21 $ 23.63 $15.03 $21.65 $ 21.63 Average costs: Production costs (per BOE): Lease operating $ 3.21 $ 1.61 $ 2.64 $ 2.87 $ 2.76 $ 2.64 $ 3.01 $ 2.76 $ 2.45 $ 2.30 $ 2.53 $ 2.42 Taxes: Production... .71 .13 - .54 .98 .28 - .74 .99 .30 - .77 Ad valorem... .75 - - .54 .71 - - .49 .41 - - .29 Field fuel..... .85 - - .62 1.27 - - .88 1.01 - - .71 Workover....... .28 .01 .59 .25 .20 .01 .32 .17 .17 - .42 .15 ------ ------ ----- ------ ------ ----- ------ ------ ------ ----- ----- ------ Total....... $ 5.80 $ 1.75 $ 3.23 $ 4.82 $ 5.92 $ 2.93 $ 3.33 $ 5.04 $ 5.03 $ 2.60 $ 2.95 $ 4.34 Depletion expense (per BOE)..... $ 4.64 $ 5.00 $ 8.36 $ 5.01 $ 4.46 $ 5.67 $ 7.71 $ 5.02 $ 3.95 $ 5.56 $ 7.58 $ 4.57 - --------------- (a) These amounts represent the Company's historical results from operations without making pro forma adjustments for any acquisitions, divestitures or drilling activity that occurred during the respective years.
19 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, 2002, 2001 and 2000: PRODUCTIVE WELLS (a) Gross Productive Wells Net Productive Wells -------------------------- ------------------------- Oil Gas Total Oil Gas Total ------ ------ ------ ------ ------ ------- As of December 31, 2002: United States................ 3,448 1,952 5,400 2,745 1,855 4,600 Argentina.................... 694 208 902 534 142 676 Canada....................... 1 246 247 1 197 198 South Africa................. 4 - 4 2 - 2 Tunisia...................... 1 - 1 - - - ------ ------ ------ ------ ------ ------ Total..................... 4,148 2,406 6,554 3,282 2,194 5,476 ====== ====== ====== ====== ====== ====== As of December 31, 2001: United States................ 3,485 1,931 5,416 2,116 1,613 3,729 Argentina.................... 669 162 831 454 132 586 Canada....................... 4 299 303 3 240 243 ------ ------ ------ ------ ------ ------ Total..................... 4,158 2,392 6,550 2,573 1,985 4,558 ====== ====== ====== ====== ====== ====== As of December 31, 2000: United States................ 3,577 1,847 5,424 2,166 1,550 3,716 Argentina.................... 575 211 786 434 154 588 Canada....................... 95 234 329 45 175 220 ------ ------ ------ ------ ------ ------ Total..................... 4,247 2,292 6,539 2,645 1,879 4,524 ====== ====== ====== ====== ====== ====== - --------------- (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. Any well in which one of the multiple completions is an oil completion is classified as an oil well. As of December 31, 2002, the Company owned interests in 111 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, 2002: LEASEHOLD ACREAGE Developed Acreage Undeveloped Acreage ------------------------ ------------------------ Royalty Gross Acres Net Acres Gross Acres Net Acres Acreage ----------- ---------- ----------- ---------- --------- As of December 31, 2002: United States: Onshore................... 996,896 871,234 198,729 156,815 229,686 Offshore.................. 125,786 53,120 604,287 506,712 10,500 ---------- ---------- ----------- ---------- -------- 1,122,682 924,354 803,016 663,527 240,186 Argentina.................... 710,000 299,000 1,002,000 925,000 - Canada....................... 152,000 116,000 356,000 276,000 12,000 South Africa................. 9,600 3,840 5,368,400 4,009,160 - Gabon........................ - - 313,937 313,937 - Tunisia...................... - - 5,308,498 2,402,667 - ---------- ---------- ----------- ---------- -------- Total..................... 1,994,282 1,343,194 13,151,851 8,590,291 252,186 ========== ========== =========== ========== ========
20 Drilling activities. The following table sets forth the number of gross and net productive and dry wells in which the Company had an interest that were drilled during the years ended December 31, 2002, 2001 and 2000. 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, -------------------------- -------------------------- 2002 2001 2000 2002 2001 2000 ------ ------ ------ ------ ------ ------ United States: Productive wells: Development................. 148 228 159 83.0 114.6 91.3 Exploratory................. 6 20 11 2.0 11.0 4.7 Dry holes: Development................. 4 15 3 3.7 14.6 1.9 Exploratory................. 3 8 3 2.1 5.1 1.6 ----- ----- ----- ----- ------ ------ 161 271 176 90.8 145.3 99.5 ----- ----- ----- ----- ------ ------ Argentina: Productive wells: Development................. 13 19 28 13.0 17.7 26.7 Exploratory................. 9 26 38 9.0 25.5 37.6 Dry holes: Development................. 1 1 2 1.0 1.0 2.0 Exploratory................. 8 16 16 8.0 14.0 14.5 ----- ----- ----- ----- ------ ------ 31 62 84 31.0 58.2 80.8 ----- ----- ----- ----- ------ ------ Canada: Productive wells: Development................. 13 24 17 10.4 20.3 17.9 Exploratory................. 9 12 12 9.0 10.2 9.9 Dry holes: Development................. 4 2 4 4.0 2.0 2.5 Exploratory................. 3 13 2 3.0 11.8 1.9 ----- ----- ----- ----- ------ ------ 29 51 35 26.4 44.3 32.2 ----- ----- ----- ----- ------ ------ Africa: Productive wells: Development................. 4 - - 1.6 - - Exploratory................. 4 3 - 3.4 2.4 - Dry holes: Development................. - - - - - - Exploratory................. - 3 1 - 1.9 1.0 ----- ----- ----- ----- ------ ------ 8 6 1 5.0 4.3 1.0 ----- ----- ----- ----- ------ ------ Total....................... 229 390 296 153.2 252.1 213.5 ===== ===== ===== ===== ====== ====== Success ratio (a)............... 90% 85% 90% 86% 80% 88% - --------------- (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.
21 The following table sets forth information about the Company's wells upon which drilling was in progress on December 31, 2002: Gross Wells Net Wells ----------- --------- United States: Development......................................... 7 6.5 Exploratory......................................... - - ----- ------ 7 6.5 ----- ------ Argentina: Development......................................... 3 3.0 Exploratory......................................... 6 6.0 ----- ------ 9 9.0 ----- ------ Canada: Development......................................... 4 4.0 Exploratory......................................... 4 4.0 ----- ------ 8 8.0 ----- ------ Total............................................ 24 23.5 ===== ======
ITEM 3. LEGAL PROCEEDINGS The Company is party to various legal proceedings, which 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 litigation incidental to its business. The claims for damages from such other legal actions are not in excess of 10 percent of the Company's current assets and the Company believes none of these actions to be material. 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 2002. PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER MATTERS The Company's common stock is listed and traded on the New York Stock Exchange under the symbol "PXD". The following table sets forth, for the periods indicated, the high and low sales prices for the Company's common stock, as reported in the New York Stock Exchange composite transactions. The Company's $575 million credit agreement restricts the Company from paying or declaring dividends on common stock and certain other payments in excess of an aggregate $50 million annually. The Company's board of directors did not declare dividends to the holders of the Company's common stock during 2002 or 2001. The Company's board of directors has no current plans to declare dividends during the foreseeable future. High Low -------- -------- Year ended December 31, 2002: Fourth quarter....................................... $ 27.50 $ 21.70 Third quarter........................................ $ 26.23 $ 19.50 Second quarter....................................... $ 26.05 $ 20.00 First quarter........................................ $ 22.30 $ 16.10 Year ended December 31, 2001: Fourth quarter....................................... $ 19.70 $ 13.22 Third quarter........................................ $ 19.38 $ 12.62 Second quarter....................................... $ 23.05 $ 14.30 First quarter........................................ $ 20.24 $ 15.45
On February 14, 2003, the last reported sales price of the Company's common stock, as reported in the New York Stock Exchange composite transactions, was $24.25 per share. As of February 14, 2003, the Company's common stock was held by approximately 30,951 holders of record. 22 ITEM 6. SELECTED FINANCIAL DATA The following selected consolidated financial data 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, ---------------------------------------------------- 2002 2001 2000 1999 1998 -------- -------- -------- -------- -------- (in millions, except per share data) Statement of Operations Data: Revenues and other income: Oil and gas................................ $ 701.8 $ 847.0 $ 852.7 $ 644.6 $ 711.5 Interest and other (a)..................... 11.2 21.8 25.8 89.7 10.4 Gain (loss) on disposition of assets, net.. 4.4 7.7 34.2 (24.2) (.4) ------- ------ ------- ------- ------- 717.4 876.5 912.7 710.1 721.5 ------- ------ ------- ------- ------- Costs and expenses: Oil and gas production..................... 199.6 209.7 189.3 159.5 223.5 Depletion, depreciation and amortization... 216.4 222.6 214.9 236.1 337.3 Impairment of properties and facilities.... - - - 17.9 459.5 Exploration and abandonments............... 85.9 127.9 87.5 66.0 121.9 General and administrative................. 48.4 37.0 33.3 40.2 82.6 Reorganization............................. - - - 8.5 33.2 Interest................................... 95.8 131.9 162.0 170.3 164.3 Other (b).................................. 17.2 39.6 67.2 34.7 30.0 ------- ------ ------- ------- ------- 663.3 768.7 754.2 733.2 1,452.3 ------- ------ ------- ------- ------- Income (loss) before income taxes and extraordinary items........................ 54.1 107.8 158.5 (23.1) (730.8) Income tax benefit (provision)............... (5.1) (4.0) 6.0 .6 (15.6) ------- ------ ------- ------- ------- Income (loss) before extraordinary items..... 49.0 103.8 164.5 (22.5) (746.4) Extraordinary items (c)...................... (22.3) (3.8) (12.3) - - ------- ------ ------- ------- ------- Net income (loss)............................ $ 26.7 $ 100.0 $ 152.2 $ (22.5) $ (746.4) ======= ======= ======= ======= ======= Income (loss) before extraordinary items per share: Basic...................................... $ .44 $ 1.05 $ 1.65 $ (.22) $ (7.46) ======= ======= ======= ======= ======= Diluted.................................... $ .43 $ 1.04 $ 1.65 $ (.22) $ (7.46) ======= ======= ======= ======= ======= Net income (loss) per share: Basic...................................... $ .24 $ 1.01 $ 1.53 $ (.22) $ (7.46) ======= ======= ======= ======= ======= Diluted.................................... $ .23 $ 1.00 $ 1.53 $ (.22) $ (7.46) ======= ======= ======= ======= ======= Dividends per share ......................... $ - $ - $ - $ - $ .10 ======= ======= ======= ======= ======= Weighted average shares outstanding: Basic...................................... 112.5 98.5 99.4 100.3 100.1 ======= ======= ======= ======= ======= Diluted.................................... 114.3 99.7 99.8 100.3 100.1 ======= ======= ======= ======= ======= Statement of Cash Flows Data: Cash flows from operating activities......... $ 332.2 $ 475.6 $ 430.1 $ 255.2 $ 314.1 Cash flows from investing activities......... $ (508.1) $ (422.7) $ (194.5) $ 199.0 $ (517.0) Cash flows from financing activities......... $ 170.9 $ (64.0) $ (244.1) $ (479.1) $ 190.9 Balance Sheet Data (as of December 31): Working capital (deficit).................... $ (127.5) $ 27.4 $ (25.1) $ (13.7) $ (324.8) Property, plant and equipment, net........... $3,168.4 $2,784.3 $2,515.0 $2,503.0 $3,034.1 Total assets................................. $3,455.1 $3,271.1 $2,954.4 $2,929.5 $3,481.3 Long-term obligations........................ $1,796.9 $1,743.7 $1,804.5 $1,914.5 $2,101.2 Total stockholders' equity................... $1,374.9 $1,285.4 $ 904.9 $ 774.6 $ 789.1 - --------------- (a) 1999 includes $41.8 million of option fees and liquidated damages and $30.2 million of income associated with an excise tax refund. (b) Other expense for 2002 includes $6.9 million and $2.6 million for the remeasurement of Argentine peso-denominated net monetary assets and Canadian gas marketing losses, respectively. Other expense for 2001 includes $11.5 million, $9.9 million and $7.7 million of charges for changes in the fair values of derivatives excluded from hedge accounting treatment; Canadian gas marketing losses; and the remeasurement of Argentine peso-denominated net monetary assets and adjustments to reduce the carrying value of Argentine lease and well equipment inventory to market value, respectively. Other expense for 2000, 1999 and 1998 include noncash mark-to-market charges for changes in the fair values of non-hedge financial instruments of $58.5 million, $27.0 million and $21.2 million, respectively. (c) The Company's extraordinary items represent losses from the early extinguishment of debt. See Notes B and E of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for information regarding the Company's extraordinary items.
23 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 2002 Financial and Operating Performance The year ended December 31, 2002 was highlighted by favorable commodity prices and continued strengthening of North American gas fundamentals; the issuance of 11.5 million shares of common stock to fund strategic acquisitions in the Company's core areas of the West Panhandle gas field and the Gulf of Mexico Falcon field development project; initial production from the Canyon Express gas project; continued development of the deepwater Gulf of Mexico Devils Tower and Falcon fields and the Sable oil field offshore South Africa; indications that the Argentine economy and currency may be stabilizing; continued evaluation of the Gabon discovery; an oil discovery in Tunisia; the acquisition of undeveloped property interests in Alaska; the completion of a public offering of $150 million of 7-1/2 percent senior notes that will mature in 2012; and repurchases of $61.0 million of higher yielding funded debt to reduce the Company's future costs of capital. During the years ended December 31, 2002, 2001 and 2000, the Company recorded net income of $26.7 million, $100.0 million and $152.2 million ($.23, $1.00 and $1.53 per diluted share), respectively. Compared to 2001, the Company's 2002 total revenues and other income decreased by $159.0 million, or 18 percent, including a $145.2 million decrease in oil and gas revenues. The decrease in oil and gas revenues was due to decreases of five percent, 19 percent and 23 percent in average oil, NGL and gas prices, respectively, including the effects of commodity price hedges. Compared to 2001, the Company's 2002 total costs and expenses decreased by $105.4 million, or 14 percent. The decrease in total costs and expenses was primarily reflective of a $42.0 million decrease in exploration and abandonments expense, primarily due to the allocation of a larger percentage of the Company's 2002 capital budget to the development of the Company's Canyon Express, Falcon, Devils Tower and Sable projects; a $36.1 million decrease in interest expense, primarily due to declining underlying market interest rates, interest savings associated with the replacement of higher yielding senior notes and capital cost obligations with lower yielding senior notes and corporate credit facility indebtedness, interest rate hedge gains and increased interest capitalized on significant capital projects; and a $22.3 million decrease in other expense, primarily due to declines in derivative mark-to-market provisions, gas marketing losses and bad debt expense. During the year ended December 31, 2002, the Company's net cash provided by operating activities decreased to $332.2 million, as compared to $475.6 million during 2001 and $430.1 million during 2000. The decrease in net cash provided by operating activities during 2002 was primarily due to declines in oil, NGL and gas prices as discussed above. During 2002, successful capital investment activities increased the Company's proved reserves to 736.7 MMBOE, reflecting the effects of strategic acquisitions of properties in the Company's core operating areas and a successful drilling program which resulted in the replacement of 258 percent of production at an acquisition and finding cost per BOE of $6.30. During the three years ended December 31, 2002, Pioneer has replaced 210 percent of production at an acquisition and finding cost per BOE of $6.24. Costs incurred for the year ended December 31, 2002 totaled $672.5 million, including $195.5 million of proved and unproved property acquisitions and $477.0 million of exploration and development drilling and seismic expenditures. During the year ended December 31, 2002, the Company purchased, through two transactions, an additional 30 percent working interest in the Falcon field development and a 25 percent working interest in associated acreage in the deepwater Gulf of Mexico for a combined purchase price of $61.1 million. As a result of these transactions, the Company owns a 75 percent working interest in and operates the Falcon field development and related exploration blocks. Also during 2002, the Company completed the purchase of the remaining 23 percent of the rights that the Company did not already own in its core area West Panhandle gas field, 100 percent of the West Panhandle reserves attributable to field fuel, 100 percent of the related West Panhandle field gathering system and ten blocks surrounding the Company's deepwater Gulf of Mexico Falcon discovery. In connection with these transactions, the Company recorded $100.4 million to proved oil and gas properties, $3.8 million to unproved oil and gas properties and $1.9 million to assets held for resale; retired a capital cost obligation for $60.8 million; settled a $20.9 million gas balancing receivable; assumed trade and environmental obligations amounting to $5.8 million in the aggregate; and paid $140.2 million of cash. 24 See "Results of Operations" and "Capital Commitments, Capital Resources and Liquidity", below, for more in-depth discussions of the Company's oil and gas producing activities, including discussions pertaining to oil and gas production volumes, prices, hedging activities, costs and expenses, capital commitments, capital resources and liquidity. 2003 Outlook Commodity prices. During 2001, commodity prices declined from historically high levels at the beginning of the year to historically moderate levels by year end. World oil prices increased during 2002 in response to political unrest and supply disruptions in the Middle East and Venezuela. During the third and fourth quarters of 2002, North American gas prices improved as market fundamentals strengthened. The Company's outlook for 2003 commodity prices is uncertain. Significant factors that will impact 2003 commodity prices include the final resolution of issues currently impacting Iraq and Venezuela, the extent to which members of the Organization of Petroleum Exporting Countries and other oil exporting nations are able to manage oil supply through export quotas and overall North American gas supply and demand fundamentals. Pioneer will continue to moderate its debt levels, follow cost management measures and strategically hedge oil and gas price risk to mitigate the impact of price volatility on its oil, NGL and gas revenues. As of December 31, 2002, the Company had hedged 22,236 barrels per day ("Bblpd") of 2003 oil production under swap contracts with a weighted average fixed price to be received of $24.45 per Bbl. The Company had also hedged 230,000 Mcf per day of 2003 gas production under swap contracts with a weighted average fixed price to be received of $3.76 per MMBtu. During January 2003, the Company increased its 2003 commodity hedge positions by entering into 6,000 Bblpd of March oil swap contracts with average per Bbl fixed prices of $33.51. Additionally, at December 31, 2002 the Company has deferred oil hedge losses of $.5 million that will be recognized as reductions to oil revenue during the last eight months of 2003 and $72.5 million of gas hedge gains that will be recognized as increases to gas revenue during 2003. 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 open hedge positions at December 31, 2002. Also see "Item 7A. Quantitative and Qualitative Disclosures About Market Risk" for disclosures about the Company's commodity related derivative financial instruments. First quarter 2003. Based on current estimates, the Company expects that its first quarter worldwide production will average 120 to 128 MBOE per day. Included in the mid-point of the estimate is 95 MMcf per day, net to the Company from Canyon Express. First quarter production costs are expected to average $5.10 to $5.40 per BOE based on recent NYMEX strip prices for oil and gas. Depreciation, depletion and amortization expense is expected to average $5.75 to $6.00 per BOE, and total exploration and abandonment expense is expected to be $20 million to $50 million. General and administrative expense is expected to be $16 million to $17 million during the first quarter of 2003, $2 million to $3 million of which relates to estimated additional performance-based compensation costs. Interest expense is expected to be $24 million to $26 million. Interest capitalized during the first quarter of 2003 will be significantly less than interest capitalized during the first three quarters of 2002 as the Company's largest capital project for which interest was being capitalized, the Canyon Express development project, was put into production during September 2002. Additionally, during February 2003, the Company entered into interest rate swap contracts to hedge a portion of the fair value of its 9-5/8 percent senior notes. Under the terms of the interest rate swap contracts, the Company will receive a fixed annual rate of 9-5/8 percent on $250 million notional amount and will pay the counterparties a variable rate on the notional amount equal to the six-month LIBOR, reset semi-annually, plus a weighted average margin of 566.4 basis points. Income taxes, principally in Argentina, are expected to be approximately $2 million as the Company benefits from the carryforward of net operating losses in the United States and Canada. Production growth. The Company expects that its annual 2003 worldwide production will be approximately 165 MBOE per day, an increase of 45 percent over 2002 levels. The growth in production during 2003 includes initial production during the second quarter from the Company's deepwater Gulf of Mexico Falcon gas project and the Sable oil project in South Africa, coupled with peak rates of production from Canyon Express and increases in production from the Company's core properties in the United States, Argentina and Canada due to an aggressive development drilling program with approximately twice as many wells anticipated in 2003 versus 2002. Capital expenditures. During 2003, the Company's budget for oil and gas producing activities is expected to range from $450 million to $550 million, of which approximately 35 percent has been budgeted for exploration expenditures and 65 percent has been budgeted for development drilling and facility costs. The Company's 2003 capital budget is allocated approximately 60 percent to the 25 United States, nine percent to Argentina and Canada and 22 percent to Africa. The Company's 2003 capital budget includes $35 million of remaining development capital to complete the Falcon and Devils Tower development projects in the deepwater Gulf of Mexico and the Sable oil project offshore South Africa. Aggressive development drilling programs in the Company's core Spraberry oil field, Hugoton and West Panhandle gas fields, the United States Gulf Coast, Argentina and Canada will resume with approximately twice as many wells anticipated in 2003 versus 2002. During 2003, the Company has planned exploration drilling in the Gulf of Mexico, the onshore Gulf Coast area, Alaska, Canada, Gabon, Tunisia and South Africa. During the years ended December 31, 2004 and 2005, the Company expects to expend approximately $172 million and $151 million, respectively, of capital for development drilling and facility costs related to its proved undeveloped reserves. Critical Accounting Estimates The Company prepares its consolidated financial statements for inclusion in this Report in accordance with accounting principles that are generally accepted in the United States ("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 judgements and estimates including, in certain circumstances, choices between acceptable GAAP alternatives. Following is a discussion of the Company's most critical accounting estimates, judgements and uncertainties that are inherent in the Company's application of GAAP: Accounting for oil and gas producing activities. The accounting for and disclosure of oil and gas producing activities requires the Company's management to choose between GAAP alternatives and to make judgements about estimates of future uncertainties. Successful efforts method of accounting. The Company utilizes the successful efforts method of accounting for oil and gas producing activities as opposed to the alternate acceptable full cost method. In general, the Company believes that, during periods of active exploration, net assets and net income are more conservatively measured under the successful efforts method of accounting for oil and gas producing activities than under the full cost method. The critical difference between the successful efforts method of accounting and the full cost method is as follows: under the successful efforts method, exploratory dry holes and geological and geophysical exploration costs are charged against earnings during the periods in which they occur; whereas, under the full cost method of accounting, such costs and expenses are capitalized as assets, pooled with the costs of successful wells and charged against the earnings of future periods as a component of depletion expense. During 2002, 2001 and 2000, the Company recognized exploration, abandonment, geological and geophysical expense of $85.9 million, $127.9 million and $87.6 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, 2002 was based on evaluations audited by independent petroleum engineers with respect to the Company's major properties and prepared by the Company's engineers with respect to all other properties. The Company's proved reserve information included in this Report as of December 31, 2001 and 2000 was based on evaluations prepared by the Company's engineers. Estimates prepared by other 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 material revisions to the estimate. The Company's stockholders should not assume that the present value of future net cash flows is the current market value of the Company's estimated 26 proved reserves. In accordance with SEC requirements, the Company based the estimated discounted future net cash flows from proved reserves on prices and costs on the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of the estimate. The Company's estimates of proved reserves materially impact depletion expense. If the estimates of proved reserves decline, the rate at which the Company records depletion expense will increase, reducing future net income. Such a decline may result from lower market prices, which may make it uneconomic to drill for and produce higher cost fields. In addition, the decline in proved reserve estimates may impact the outcome of the Company's assessment of its oil and gas producing properties for impairment. Impairment of proved oil and gas properties. The Company reviews its long-lived proved properties to be held and used whenever management judges 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 management's outlook of future commodity prices and net cash flows that may be generated by the properties. Proved oil and gas properties are reviewed for impairment by depletable pool, which is the lowest level at which depletion of proved properties is calculated. Impairment of unproved oil and gas properties. Management periodically assesses individually significant unproved oil and gas properties for impairment, on a project-by-project basis. Management's assessment of the results of exploration activities, commodity price outlooks, planned future sales or expiration of all or a portion of such projects impact the amount and timing of impairment provisions. Assessments of functional currencies. Management determines the functional currencies of the Company's subsidiaries based on an assessment of the currency of the economic environment in which a subsidiary primarily realizes and expends its operating revenues, costs and expenses. The U.S. dollar is the functional currency of all of the Company's international operations except Canada. The assessment of functional currencies can have a significant impact on periodic results of operations and financial position. Argentine economic and currency measures. The accounting for and remeasurement of the Company's Argentine balance sheets as of December 31, 2002 and 2001 reflect management's assumptions regarding some uncertainties unique to Argentina's current economic situation. See 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. The Argentine economic and political situation continues to evolve and the Argentine government may enact future regulations or policies that, when finalized and adopted, may materially impact, among other items, (i) the realized prices the Company receives for the commodities it produces and sells; (ii) the timing of repatriations of excess cash flow to the Company's corporate headquarters in the United States; (iii) the Company's asset valuations; and (iv) peso-denominated monetary assets and liabilities. Deferred tax asset valuations. Management periodically assesses the probability of recovery of recorded deferred tax assets based on its assessment of future earnings outlooks by tax jurisdiction. Such estimates are inherently imprecise. Many assumptions are utilized in the assessments that may prove to be materially incorrect in the future. New Accounting Pronouncements During June 2001, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations" ("SFAS 143"). SFAS 143 amends Statement of Financial Accounting Standards No. 19, "Financial Accounting and Reporting by Oil and Gas Producing Companies" ("SFAS 19") to require that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. Under the provisions of SFAS 143, asset retirement obligations are capitalized as part of the carrying value of the long-lived asset. Under the provisions of SFAS 19, asset retirement obligations are recognized using a cost-accumulation approach. The Company currently records significant asset retirement obligations through the unit-of-production method, except for such liabilities that were assumed in business combinations, which were recorded at their estimated fair values. The Company adopted the provisions of SFAS 143 on January 1, 2003. The adoption of SFAS 143 resulted in a January 1, 2003 cumulative effect adjustment to record (i) a $13.8 million increase in the carrying values of 27 proved properties, (ii) a $26.3 million decrease in accumulated depreciation, depletion, and amortization of property, plant and equipment, (iii) a $1.0 million increase in current abandonment liabilities and (iv) a $22.4 million increase in noncurrent abandonment liabilities. The net impact of items (i) through (iv) was to record a gain of $16.7 million, net of tax, as a cumulative effect adjustment of a change in accounting principle in the Company's consolidated statements of operations upon adoption on January 1, 2003. During April 2002, the FASB issued Statement of Financial Accounting Standards No. 145, "Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13 and Technical Corrections" ("SFAS 145"). Prior to the adoption of the provisions of SFAS 145, gains or losses on the early extinguishment of debt were required to be classified in a company's periodic consolidated statements of operations as extraordinary gains or losses, net of associated income taxes, after the determination of income or loss from continuing operations. SFAS 145 requires, except in the case of events or transactions of a highly unusual and infrequent nature, gains or losses from the early extinguishment of debt to be classified as components of a company's income or loss from continuing operations. The Company adopted the provisions of SFAS 145 on January 1, 2003. The adoption of the provisions of SFAS 145 is not expected to affect the Company's future financial position or liquidity. Upon adoption of the provisions of SFAS 145, gains or losses from the early extinguishment of debt recognized in the Company's consolidated statements of operations for the years ended December 31, 2002, 2001 and 2000 will be reclassified to other revenues or other expense and included in the determination of the income (loss) from continuing operations of those periods. Results of Operations Oil and gas revenues. Revenues from oil and gas operations totaled $701.8 million during 2002, as compared to $847.0 million during 2001 and $852.7 million during 2000, representing a 17 percent decrease from 2001 to 2002. The revenue decrease from 2001 to 2002 was due to year-on-year worldwide average gas, NGL and oil price declines of 23 percent, 19 percent and five percent, respectively, including the effects of gas and oil price hedges; and an eight percent decline in worldwide oil production, offset by worldwide NGL and gas production increases of four percent and two percent, respectively. The revenue decrease from 2000 to 2001 was due to a four percent decline in BOE production and a 15 percent decline in NGL price, partially offset by a 15 percent increase in gas price, including the effects of gas hedges. The declines in 2001 sales volumes were primarily attributable to normal well production declines. 28 The following table provides production and price data relevant to the analysis of the Company's revenues from oil and gas operations: Year ended December 31, ------------------------------ 2002 2001 2000 -------- -------- -------- Production: Oil (MBbls)................................... 11,514 12,498 12,535 NGLs (MBbls).................................. 8,086 7,800 8,379 Gas (MMcf).................................... 131,015 127,865 135,843 Total (MBOE).................................. 41,436 41,609 43,555 Average daily production: Oil (Bbls).................................... 31,545 34,241 34,249 NGLs (Bbls)................................... 22,154 21,370 22,894 Gas (Mcf)..................................... 358,945 350,314 371,157 Total (BOE)................................... 113,524 113,997 119,002 Average reported prices: Oil (per Bbl) United States............................... $ 23.66 $ 24.34 $ 22.07 Argentina................................... $ 20.63 $ 23.79 $ 29.09 Canada...................................... $ 22.26 $ 21.87 $ 27.50 Worldwide................................... $ 22.89 $ 24.12 $ 24.01 NGL (per Bbl) United States............................... $ 13.77 $ 16.88 $ 20.05 Argentina................................... $ 14.56 $ 19.29 $ 22.91 Canada...................................... $ 16.77 $ 21.11 $ 24.32 Worldwide................................... $ 13.92 $ 17.14 $ 20.27 Gas (per Mcf) United States............................... $ 3.16 $ 4.10 $ 3.50 Argentina................................... $ .48 $ 1.31 $ 1.19 Canada...................................... $ 2.50 $ 2.86 $ 2.88 Worldwide................................... $ 2.49 $ 3.23 $ 2.81 Annual percentage increase (decrease) in average worldwide reported prices: Oil......................................... (5) - 56 NGL......................................... (19) (15) 74 Gas......................................... (23) 15 48
Hedging activities. The commodity prices that the Company reports are based on the market price received for the commodities adjusted by the results of the Company's hedging activities. The Company utilizes commodity derivative contracts (swaps and collars) in order to (i) reduce the effect of price volatility on the commodities the Company produces and sells, (ii) support the Company's annual capital budgeting and expenditure plans and (iii) reduce commodity price risk associated with certain capital projects. The effective portions of changes in the fair values of the Company's commodity price hedge derivatives are deferred as increases or decreases to stockholders' equity until the underlying hedged transaction occurs. Consequently, changes in the effective portions of commodity price hedge derivatives 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 2002, 2001 and 2000 from the Company's hedging activities, the Company's open hedge positions at December 31, 2002 and descriptions of the Company's hedge and non-hedge commodity derivatives. Also see "Item 7A. Quantitative and Qualitative Disclosures About Market Risk" for additional disclosure about the Company's commodity related derivative financial instruments. Interest and other revenue. The Company recorded interest and other income totaling $11.2 million, $21.8 million and $25.8 during 2002, 2001 and 2000, respectively. The Company's interest and other income was comprised of revenue that was not directly attributable to oil and gas producing activities or oil and gas property divestitures. See Note L of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information regarding interest and other income. 29 Gain (loss) on disposition of assets. During the year ended December 31, 2002, the Company realized $118.9 million of cash proceeds from asset divestitures and, associated therewith, recorded net gains of $4.4 million. The proceeds derived from asset divestitures during 2002 included $91.3 million from the early termination of hedge derivatives, $20.9 million from the cash settlement of a gas balancing receivable, $4.7 million from the sale of certain gas properties located in Oklahoma and $2.0 million from the sale of other corporate assets. The Company recorded a gain of $2.8 million associated with the sale of the gas properties in Oklahoma and a gain of $1.6 million from the sale of other corporate assets. The proceeds from the early termination of hedge derivatives represent deferred hedge gains and losses that will be recognized as increases or decreases to future interest expenses or future oil and gas revenues. See Note J of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for information regarding the amortization of deferred hedge gains and losses. During the year ended December 31, 2001, the Company realized $113.5 million of cash proceeds from asset divestitures and, associated therewith, recorded net gains of $7.7 million. The proceeds derived from asset divestitures during 2001 included $85.4 million from the early termination of hedge derivatives, $12.7 million from the sale of the Company's remaining holdings in the common stock of a non-affiliated entity, $12.0 million from the sale of certain oil properties in Canada and $3.4 million from the sale of other corporate assets. The Company recorded a gain of $8.1 million from the sale of the remaining holdings in the common stock of the non-affiliated entity, a loss of $1.1 million from the sales of oil and gas properties and a gain of $.7 million from the sale of other corporate assets. During 2000, the Company completed the divestiture of certain assets for proceeds of $102.7 million. Associated therewith, the Company recorded a net gain on disposition of assets of $34.2 million. The 2000 divestitures included the sale of common stock of a non-affiliated entity for net proceeds of $59.7 million, from which the Company recognized a gain on disposition of assets of $34.3 million. The Company also sold certain oil and gas producing properties and other assets during 2000 for proceeds of $43.0 million, from which the Company recognized a loss on disposition of assets of $.1 million. The net cash proceeds from asset divestitures during 2002, 2001 and 2000 were used, together with net cash flows provided by operating activities, to fund additions to oil and gas properties and to reduce outstanding indebtedness. See Note M of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information regarding asset divestitures. Production costs. Total production costs per BOE decreased in 2002 by four percent and increased in 2001 by 16 percent. In general, lease operating expenses and workover expenses represent the components of production costs over which the Company has management control, while production taxes, ad valorem taxes and field fuel expenses are directly related to commodity price changes. The decrease in production costs during 2002 was primarily due to decreases in field fuel expense and production taxes as a result of lower North American average gas prices and lower Argentine lease operating expenses resulting from lower Argentine expenses on a U.S. dollar equivalent basis due to the devaluation of the Argentine peso versus the U.S. dollar, partially offset by moderately higher workover expenses, ad valorem taxes (which are computed using prior year average annual commodity prices) and declines in the third party gas processing and treating margin component of lease operating expense. The increase in production costs during 2001 was primarily due to increases in field fuel expense as a result of higher North American average gas prices, higher ad valorem taxes and to declines in the third party gas processing and treating margin component of lease operating expenses. The following table provides the components of the Company's production costs during the years ended December 31, 2002, 2001 and 2000: Year Ended December 31, ------------------------------- 2002 2001 2000 ------- ------- ------- (per BOE) Lease operating expenses............ $ 2.87 $ 2.76 $ 2.42 Taxes: Production........................ .54 .74 .77 Ad valorem ....................... .54 .49 .29 Field fuel expenses................. .62 .88 .71 Workover expenses................... .25 .17 .15 ------ ------ ------ Total production costs........ $ 4.82 $ 5.04 $ 4.34 ====== ====== ======
30 Depletion, depreciation and amortization expense. The Company's total depletion, depreciation and amortization expense per BOE was $5.22, $5.35 and $4.93 for the years ended December 31, 2002, 2001 and 2000, respectively. Depletion expense, the largest component of depletion, depreciation and amortization, was $5.01, $5.02 and $4.57 per BOE during the years ended December 31, 2002, 2001 and 2000, respectively, and depreciation and amortization of other property and equipment was $.21, $.33 and $.36 per BOE during each of the respective years. The decrease in depreciation and amortization of other property and equipment during 2002 was primarily comprised of decreases associated with fully amortized information technology assets. During 2001, the increase in per BOE depletion expense was primarily associated with decreases in United States production, which had a lower cost basis relative to combined Argentine and Canadian per BOE cost basis, and to downward revisions to proved reserves as a result of lower commodity prices. Exploration, abandonments, geological and geophysical costs. Exploration, abandonments, geological and geophysical costs totaled $85.9 million, $127.9 million and $87.6 million for the years ended December 31, 2002, 2001 and 2000, respectively. The following table sets forth the components of the Company's 2002, 2001 and 2000 exploration and abandonments/geological and geophysical costs: United Other States Argentina Canada Foreign Total -------- --------- -------- -------- -------- (in thousands) Year Ended December 31, 2002: Geological and geophysical costs........ $ 22,761 $ 4,138 $ 3,544 $ 7,223 $ 37,666 Exploratory dry holes................... 32,557 3,294 1,220 (539) 36,532 Leasehold abandonments and other........ 7,637 2,874 1,077 108 11,696 ------- ------- ------- ------- ------- $ 62,955 $ 10,306 $ 5,841 $ 6,792 $ 85,894 ======= ======= ======= ======= ======= Year Ended December 31, 2001: Geological and geophysical costs........ $ 29,620 $ 6,541 $ 2,373 $ 13,678 $ 52,212 Exploratory dry holes................... 34,883 6,040 5,473 10,432 56,828 Leasehold abandonments and other........ 5,546 11,276 2,036 8 18,866 ------- ------- ------- ------- ------- $ 70,049 $ 23,857 $ 9,882 $ 24,118 $127,906 ======= ======= ======= ======= ======= Year Ended December 31, 2000: Geological and geophysical costs........ $ 22,033 $ 6,881 $ 2,273 $ 7,761 $ 38,948 Exploratory dry holes................... 11,745 6,987 887 8,396 28,015 Leasehold abandonments and other........ 7,089 11,520 1,971 7 20,587 ------- ------- ------- ------- ------- $ 40,867 $ 25,388 $ 5,131 $ 16,164 $ 87,550 ======= ======= ======= ======= =======
The decrease in 2002 exploration, abandonments, geological and geophysical costs reflected a decline in Argentine exploration activities as the Company monitored and assessed the economic environment and risks associated with Argentina; a decline in exploratory dry holes and geological and geophysical costs in Africa, as the Company assessed its exploratory successes in Gabon and Tunisia; and the allocation of a larger percentage of the Company's 2002 capital budget to the development of its significant discoveries in the Gulf of Mexico and offshore South Africa. The increase in 2001 exploration costs, as compared to 2000, was primarily due to increased geological and geophysical costs that were supportive of exploratory drilling, increased exploratory drilling in the Gulf of Mexico and Argentina and an exploratory dry hole drilled in Tunisia. Approximately 20 percent of the Company's 2002 costs incurred for oil and gas producing activities were exploration costs as compared to 34 percent in 2001 and 38 percent in 2000. General and administrative expenses. The Company's general and administrative expenses totaled $48.4 million ($1.17 per BOE), $37.0 million ($.89 per BOE) and $33.3 million ($.76 per BOE) during the years ended December 31, 2002, 2001 and 2000, respectively. The increase in administrative expense during 2002 as compared to 2001 was primarily due to the elimination of operating overhead being charged by the Company to the 42 affiliated partnerships that were merged into a wholly-owned subsidiary of the Company during December 2001 (see "Financial and Operating Performance" and Note D of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information regarding the 2001 merger). Additionally, the Company awarded 645,445 shares of restricted stock to directors, officers and key employees as part of the Company's compensation program. The Company recorded $16.2 million of deferred compensation associated with the restricted stock awards, which amount will be amortized to compensation expense during the vesting periods of the awards. Amortization of the deferred costs of the restricted stock increased general and administrative expenses by $1.9 million in 2002. See Note G of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for 31 information regarding the restricted stock awards and their vesting periods. The increase in general and administrative expense during 2001, as compared to 2000, was primarily due to an increase in compensation expense. Interest expense. Interest expense was $95.8 million, $132.0 million and $162.0 million for the years ended December 31, 2002, 2001 and 2000, respectively. The decline in 2002 interest expense as compared to 2001, was primarily due to incremental interest savings of $18.0 million from the Company's interest rate hedging program; a $6.3 million increase in interest capitalized; interest savings from the retirement of the Company's outstanding 11-5/8 percent and 10-5/8 percent senior subordinated notes during the third quarter of 2001 and $38.7 million of the Company's 9-5/8 percent senior notes during the fourth quarter of 2001; interest savings from the repurchase of $47.1 million of 9-5/8 percent senior notes and $13.9 million of 8-7/8 percent senior notes during 2002; interest savings from the repayment of the $45.2 million West Panhandle gas field capital obligation in July 2002 which bore interest at an annual rate of 20 percent; and interest savings from reductions in underlying market interest rates. The decrease in interest expense for 2001 as compared to 2000 was primarily due to incremental interest savings of $7.0 million from the Company's interest rate hedging program; a $6.0 million increase in interest capitalized; and interest savings associated with the redemption of the Company's outstanding 11-5/8 percent and 10-5/8 percent senior subordinated notes and $38.7 million of the Company's 9-5/8 percent senior notes. As is discussed in "2003 Outlook" above, capitalized interest will decline during 2003, as compared to 2002 levels, primarily due to the completion of the Canyon Express development project during September 2002 and the anticipated completion of the Falcon and Sable development projects during the second quarter of 2003. Additionally, 2003 interest expense will be impacted by fair value hedges of the Company's 9-5/8 percent senior notes that were initiated by the Company during February 2003 and for which more detailed information is provided in "2003 Outlook" and in "Item 7A. Quantitative and Qualitative Disclosures About Market Risk". See Note E 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, interest expense and extraordinary items. Other expenses. Other expenses were $17.3 million during 2002, as compared to $39.6 million during 2001 and $67.2 million during 2000. Other expenses during 2002 were primarily comprised of a $6.9 million charge from the remeasurement of the Company's Argentine peso-denominated net monetary assets and liabilities and $2.5 million of marketing losses incurred to transport and sell purchased Canadian gas to a Chicago, Illinois sales point. See Note B and Note I of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information regarding currency remeasurement and gas transportation commitments. Other expenses in 2001 include $11.4 million of commodity derivative settlements that did not qualify for hedge treatment under Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities"; $9.9 million of marketing losses incurred to transport and sell purchased Canadian gas to a Chicago, Illinois sales point; $7.7 million of losses from the remeasurement of the Company's Argentine peso-denominated net monetary assets and an adjustment to reduce the carrying value of Argentine lease and well equipment inventory to market value; $6.0 million of bad debt expense related to derivative contracts with Enron North America Corp. and $4.6 million of other expenses. The primary component of other expense during 2000 was $58.5 million of mark-to-market losses on derivative contracts that did not qualify for hedge accounting treatment, including $43.9 million of losses on derivative contracts that matured during 2000 and $14.6 million of losses associated with the Company's Btu swap agreements that mature at the end of December 2004. During 2001, the Company entered into offsetting swap agreements that had fixed the prices that are to be received and paid by the Company under the Btu swap agreements. Consequently, the Btu swap agreements are no longer sensitive to changes in oil or gas commodity prices. Income tax provisions (benefits). The Company recognized consolidated income tax provisions of $5.1 million and $4.0 million during 2002 and 2001, respectively, and a consolidated income tax benefit of $6.0 million during 2000. The Company's consolidated tax provision for the year ended December 31, 2002 was comprised of current U.S. state and local taxes of $.2 million, current foreign taxes of $2.1 million and deferred foreign tax provisions of $2.8 million. The Company's consolidated tax provision for the year ended December 31, 2001 was comprised of current U.S. state and local taxes of $1.1 million, current foreign taxes of $10.5 million and deferred foreign tax benefits of $7.6 million. The Company's consolidated tax benefit in 2000 was comprised of a $10.6 million deferred tax benefit in Argentina, partially offset by $4.6 million of current taxes paid in Argentina. 32 Due to uncertainties regarding the Company's ability to realize certain of its net operating loss carryovers and tax credit carryovers prior to their scheduled expirations, the Company has established a valuation allowance of $277.2 million against those carryovers. Although the Company believes it is more likely than not that the carrying values of its remaining deferred tax assets will be realized through future taxable earnings or alternative tax planning strategies, the net deferred tax assets could be reduced further if the Company's estimate of taxable income in future periods is significantly reduced or alternative tax planning strategies are no longer viable. As a result of this situation, it is likely that the Company's effective tax rate in 2003 will be minimal in the United States and Canada and approximately 35 percent in Argentina. See Note O of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for information regarding the Company's income tax, deferred tax asset valuation reserves and net operating loss carryforward expirations. Extraordinary items. During 2002, the Company repurchased $47.1 million of its 9-5/8 percent senior notes, $13.9 million of its 8-7/8 percent senior notes and repaid a $45.2 million West Panhandle field capital cost obligation. Associated with the 2002 debt extinguishments, the Company recognized an extraordinary loss, net of taxes, of $22.3 million. During 2001, the Company redeemed the remaining $22.5 million of its outstanding 11-5/8 percent senior subordinated notes, $6.8 million of its outstanding 10-5/8 percent senior subordinated notes and repurchased $38.7 million of its 9-5/8 percent senior notes. Associated with these debt extinguishments, the Company recognized an extraordinary loss, net of taxes, of $3.8 million. During 2000, the Company replaced its prior credit facility, which was scheduled to mature in August 2002, with a new $575 million corporate credit facility due March 1, 2005 (the "Credit Agreement"). Associated therewith, the Company recognized a $12.3 million extraordinary loss on early extinguishment of debt. See "New Accounting Pronouncements", above, for information regarding future changes in the classification of the Company's extraordinary gains and losses. Capital Commitments, Capital Resources and Liquidity Capital commitments. The Company's primary needs for cash are for exploration, development and acquisitions of oil and gas properties, repayment of contractual obligations and working capital obligations. Funding for exploration, development and acquisitions of oil and gas properties and repayment of contractual obligations may be provided by any combination of internally-generated cash flow, proceeds from the disposition of non-strategic assets or alternative financing sources as discussed in "Capital resources" below. Funding for the Company's working capital obligations is provided by internally-generated cash flow. Oil and gas properties. The Company's cash expenditures for additions to oil and gas properties during 2002, 2001 and 2000 totaled $614.7 million, $529.7 million and $299.7 million, respectively. The Company's 2002 expenditures for additions to oil and gas properties were funded by $332.2 million of net cash provided by operating activities, $118.9 million of proceeds from the disposition of assets and a portion of the proceeds from the issuance of 11.5 million shares of the Company's common stock during April 2002. The Company's 2001 expenditures were internally funded by $475.6 million of net cash provided by operating activities and a portion of the Company's $113.5 million of proceeds from disposition of assets. The Company's 2000 capital expenditures were internally funded by net cash provided by operating activities. The Company strives to maintain its indebtedness at reasonable levels in order to provide sufficient financial flexibility to take advantage of future opportunities. The Company's capital budget for 2003 is expected to range from $450 million to $550 million. The Company believes that net cash provided by operating activities during 2003 will be sufficient to fund the 2003 capital expenditures budget. Contractual obligations, including off-balance sheet obligations. The Company's contractual obligations include long-term debt, operating leases, Btu swap agreements, terminated commodity hedges and other contracts. 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, 2002, the material off-balance sheet arrangements and transactions that the Company has entered into include (i) $27.2 million of undrawn letters of credit issued under the Company's $575 million corporate credit facility and (ii) operating lease agreements under which the Company's future minimum lease commitments are summarized in the table below and in Note I of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data". Contractual obligations for which the ultimate settlement amounts are not fixed and determinable include derivative contracts that are sensitive to future changes in commodity prices, currency exchange rates and interest rates and gas transportation commitments. See "Item 33 7A. Quantitative and Qualitative Disclosures About Market Risk" for a table of changes in the fair value of the Company's derivative contract assets and liabilities during the year ended December 31, 2002 and Note I of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information regarding gas transportation commitments. The following table summarizes the Company's payments due by period for fixed and determinable contractual obligations: Payments Due by Year ------------------------------------------------------------ 2003 2004 2005 2006-2007 Thereafter --------- --------- --------- --------- ------------ (in thousands) Long-term debt (a)............. $ - $ - $ 406,704 $ 161,130 $1,100,702 Operating leases (b)........... 19,364 41,553 39,375 58,924 36,338 Btu swap agreements (c)........ 7,168 7,190 - - - Terminated commodity hedges.... 484 340 - - - -------- -------- -------- -------- --------- $ 27,016 $ 49,083 $ 446,079 $ 220,054 $1,137,040 ======== ======== ======== ======== ========= - ------------ (a) See Note E of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data". (b) See Note I of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data". (c) See Note J of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data".
Capital resources. The Company's primary capital resources are net cash provided by operating activities, proceeds from financing activities and proceeds from sales of non-strategic assets. The Company expects that these resources will be sufficient to fund its capital commitments in 2003. Operating activities. Net cash provided by operating activities during 2002, 2001 and 2000 were $332.2 million, $475.6 million and $430.1 million, respectively. Net cash provided by operating activities in 2002 decreased by $143.4 million, or 30 percent, as compared to that of 2001. The decrease in 2002 net cash provided by operating activities was principally due to declines in commodity prices, offset partially by declines in interest expense. Net cash provided by operating activities in 2001 increased by $45.5 million, or 11 percent, as compared to that of 2000. The increase in 2001 was primarily due to higher commodity prices as compared to 2000, declines in interest expense and an increase in trade receivable collections. Financing activities. During the year ended December 31, 2002, the Company's financing activities provided $170.9 million of cash, comprised of $236.0 million of proceeds, net of issuance costs, from the sale of 11.5 million shares of the Company's common stock; $48.0 million of net borrowings of long-term debt; and $14.4 million of proceeds from the exercise of long-term incentive plan stock options and employee stock purchases. Partially offsetting these cash proceeds from financing activities were $124.2 million of payments of noncurrent liabilities and $3.3 million of debt issuance costs during 2002. In contrast, during the years ended December 31, 2001 and 2000, the Company used $64.0 million and $244.1 million, respectively, of net cash in financing activities. During the years ended December 31, 2001 and 2000, the Company used $5.1 million and $177.3 million of cash, respectively, to repay long-term debt; $53.4 million and $29.8 million, respectively, to repay noncurrent liabilities; $13.0 million and $27.3 million, respectively, to purchase treasury stock; and, during the year ended December 31, 2000, $13.8 million for deferred loan and debt issuance costs. Partially offsetting the above described net cash uses from financing activities were $7.5 million and $4.2 million of net cash provided from the exercise of long-term incentive plan stock options and employee stock purchases during the years ended December 31, 2001 and 2000, respectively. Over the three year period ended December 31, 2002, the Company has used $134.4 million of cash for net reductions in long-term borrowings and has reduced its ratio of debt to book capitalization to 55 percent as of December 31, 2002, from 69 percent as of December 31, 1999. Additionally, the Company has entered into financing transactions with the intent of reducing its costs of capital and increasing liquidity through the extension of debt maturities. During the years ended December 31, 2002 and 2001, the Company entered into interest rate swap contracts to hedge the fair value of its 6-1/2 percent senior notes, its 8-7/8 percent senior notes and its 8-1/4 percent senior notes. The Company also entered into interest rate swaps to hedge a portion of its interest rate risk under the Credit Agreement. In 2002 and 2001, the Company terminated its open interest rate swap portfolios to lock in the substantial fair value of the derivatives. As of December 31, 2002, the Company had $35.7 million of 34 deferred gains associated with the interest rate swap terminations recorded as an increase in the carrying value of the Company's long-term debt. During the years ended December 31, 2002, 2001 and 2000, net gains from the Company's interest rate swaps have reduced interest expense by $25.3 million, $7.3 million and $.3 million, respectively. See Note J of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplemental Data" and "Item 7A. Quantitative and Qualitative Disclosures About Market Risk" for more information about the Company's interest rate hedging activities. As is further described in "Results of Operations" above, during the year ended December 31, 2002, the Company repurchased $47.1 million of its 9-5/8 percent senior notes, $13.9 million of its 8-7/8 percent senior notes and repaid a $45.2 million West Panhandle gas field capital cost obligation. Additionally, during the year ended December 31, 2001, the Company redeemed its remaining 11-5/8 percent and 10-5/8 percent senior subordinated notes and $38.7 million of its 9-5/8 percent senior notes. At December 31, 2002, the Company had a $575.0 million corporate credit facility with a syndicate of banks that matures on March 1, 2005. Outstanding borrowings under the corporate credit facility totaled $260.0 million as of December 31, 2002. In addition, the Company has five outstanding senior note issuances at December 31, 2002. Such debt issuances consist of (i) $136.1 million aggregate principal amount of 8-7/8 percent senior notes due in 2005; (ii) $150 million aggregate principal amount of 8-1/4 percent senior notes due in 2007; (iii) $350 million aggregate principal amount of 6-1/2 percent senior notes due in 2008; (iv) $339.2 million aggregate remaining principal amount of 9-5/8 percent senior notes due in 2010; (v) $150 million aggregate principal amount of 7-1/2 percent senior notes due in 2012; and (vi) $250 million aggregate principal amount of 7-1/5 percent senior notes due in 2028. Certain of the obligations above contain restrictive covenants, each of which the Company is in compliance. The weighted average interest rate on the Company's indebtedness for the year ended December 31, 2002 was 5.74 percent as compared to 7.52 percent for the year ended December 31, 2001 and 8.68 percent for the year ended December 31, 2000, taking into account the effect of interest rate swaps. See Note E of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for more specific information regarding the Company's long-term debt as of December 31, 2002 and 2001. As the Company pursues its strategy, it may utilize various financing sources, including fixed and floating rate debt, convertible securities, preferred stock or common stock. The Company may also issue securities in exchange for oil and gas properties, stock or other interests in other oil and gas companies or related assets. Additional securities may be of a class preferred to common stock with respect to such matters as dividends and liquidation rights and may also have other rights and preferences as determined by the Company's Board of Directors. Sales of non-strategic assets. During 2002, 2001 and 2000, proceeds from the sale of non-strategic assets totaled $118.9 million, $113.5 million and $102.7 million, respectively. The Company's 2002, 2001 and 2000 asset divestitures were comprised of hedge derivatives, common stock of a non-affiliated entity, and non-strategic United States and Canadian oil and gas properties, gas plants and other assets. The cash proceeds received from asset divestitures during 2002 and 2001 were used to fund a portion of the Company's 2002 and 2001 capital expenditures and for general corporate obligations. The net cash proceeds from the 2000 asset divestitures were used to reduce the Company's outstanding indebtedness (see "Results of Operations", above, and Note M of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data"). Book capitalization and liquidity. The Company's total debt was $1.67 billion as of December 31, 2002, as compared to total debt of $1.58 billion on December 31, 2001 and 2000. The Company's total book capitalization at December 31, 2002 was $3.04 billion, consisting of total debt of $1.67 billion and stockholders' equity of $1.37 billion. The Company's debt to total capitalization was 55 percent at December 31, 2002. The Company's ratio of current assets to current liabilities was .54 at December 31, 2002 and 1.12 at December 31, 2001. The decline in the Company's ratio of current assets to current liabilities was primarily due to a $170.7 million difference in the fair value of 2003 maturing derivatives at December 31, 2002 as compared to the fair value of 2002 maturing derivatives at December 31, 2001. Including $27.2 million of undrawn and outstanding letters of credit, the Company has $287.8 million of unused borrowing capacity available under its Credit Agreement as of December 31, 2002. 35 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, 2002 and 2001, 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 that the Company is a party to do not qualify as hedges, the Company does not enter into derivative or other financial instruments for trading purposes. The fair value of the Company's derivative contracts are determined based on counterparties' estimates and valuation models. The Company has not changed its valuation method during 2002. During 2002, the Company was a party to forward foreign exchange contracts, commodity and interest 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 2002: Derivative Contract Assets (Liabilities) -------------------------------------------------- Foreign Interest Exchange Commodity Rate Rate Total ---------- -------- -------- --------- (in thousands) Fair value of contracts outstanding as of December 31, 2001.............. $ 180,554 $ (19,637) $ 61 $ 160,978 Changes in contract fair values (1)...... (183,285) 62,786 203 (120,296) Contract realizations: Maturities........................... (48,212) (11,155) (249) (59,616) Termination - cash settlements....... (58,685) (31,994) - (90,679) Termination - future obligations..... 1,303 - - 1,303 Termination - future receivables..... (479) - - (479) -------- -------- ----- -------- Fair value of contracts outstanding as of December 31, 2002.............. $(108,804) $ - $ 15 $(108,789) ======== ======== ===== ======== - --------------- (1) At inception, new derivative contracts entered into by the Company have no intrinsic value.
Quantitative Disclosures Interest rate sensitivity. The following tables provide information, in U. S. dollar equivalent amounts, about other financial instruments that the Company was a party to as of December 31, 2002 and 2001 and that are or were sensitive to changes in interest rates. For debt obligations, the tables present maturities by expected maturity dates together with the weighted average interest rates expected to be paid on the debt, given current contractual terms and market conditions. 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, 2002 and 2001. For variable rate debt, the average interest rate represents the average rates being paid on the debt projected forward proportionate to the forward yield curves for the six-month London Interbank Offered Rate. 36 Interest Rate Sensitivity Derivative and Other Financial Instruments as of December 31, 2002 (1) Liability 2003 2004 2005 2006 2007 Thereafter Total Fair Value -------- -------- -------- -------- -------- ---------- ---------- ----------- (in thousands except interest rates) Total Debt: U.S. dollar denominated maturities: Fixed rate debt............ $ - $ - $146,704 $ - $161,130 $1,100,702 $1,408,536 $(1,484,009) Weighted average interest rate (%)........ 7.94 7.94 7.87 7.83 7.81 7.77 Variable rate debt......... $ - $ - $260,000 $ - $ - $ - $ 260,000 $ (260,000) Average interest rate (%).. 2.89 4.08 5.27 - ------------ (1) During February 2003, the Company entered into interest rate swap contracts to hedge a portion of the fair value of its 9-5/8 percent senior notes. Under the terms of the interest rate swap contracts, the Company will receive a fixed annual rate of 9-5/8 percent on $250 million notional amount and will pay the counterparties a variable rate on the notional amount equal to the six-month LIBOR, reset semi- annually, plus a weighted average margin of 566.4 basis points.
The accompanying Interest Rate Sensitivity table as of December 31, 2001 also provides information about interest rate swap agreements that the Company was a party to as of that date. These interest rate swap agreements were terminated during the year ended December 31, 2002 and no longer represent market risk to the Company. The interest rate swap agreements as of December 31, 2001 hedged (i) the fair value of the Company's 8-1/4 percent senior notes; (ii) the fair value of the Company's 6-1/2 percent senior notes; and (iii) a portion of the interest rate risk associated with the Company's Credit Agreement. Interest Rate Sensitivity Derivative and Other Financial Instruments as of December 31, 2001 Liability 2002 2003 2004 2005 2006 Thereafter Total Fair Value -------- -------- -------- -------- -------- ---------- ---------- ----------- (in thousands except interest rates) Total Debt: U.S. dollar denominated maturities: Fixed rate debt............ $ - $ - $ - $161,998 $ - $1,121,306 $1,283,304 $(1,268,178) Weighted average interest rate (%)........ 8.06 8.06 8.06 7.98 7.95 7.95 Variable rate debt......... $ - $ - $ - $294,000 $ - $ - $ 294,000 $ (294,000) Average interest rates (%). 4.38 6.12 6.90 7.27 Interest Rate Hedge Derivatives: 8-1/4% senior notes hedge: Notional debt amount....... $150,000 $150,000 $150,000 $150,000 $150,000 $ 150,000 $ 150,000 $ (2,965) Fixed rate receivable (%).. 8.25 8.25 8.25 8.25 8.25 8.25 Variable rate payable (%).. 6.50 8.24 9.02 9.39 9.64 9.79 6-1/2% senior notes hedge: Notional debt amount....... $350,000 $350,000 $350,000 $350,000 $350,000 $ 350,000 $ 350,000 $ (16,229) Fixed rate receivable (%).. 6.50 6.50 6.50 6.50 6.50 6.50 Variable rate payable (%).. 5.15 6.89 7.67 8.04 8.29 8.44 Credit Agreement hedge: Notional debt amount....... $ 55,000 $ 55,000 $ (443) Fixed rate payable (%)..... 5.43 Variable rate receivable (%).......... 4.38
37 Foreign exchange rate sensitivity. The following tables provide information, in U.S. dollar equivalent amounts, about derivative financial instruments that the Company was a party to as of December 31, 2002 and 2001 and that were sensitive to changes in foreign exchange rates. Foreign Exchange Rate Sensitivity Derivative and Other Financial Instruments as of December 31, 2002 Asset 2003 Total Fair Value (1) -------- -------- -------------- (in thousands except interest rates) Foreign Exchange Rate Hedge Derivatives: Notional amount of foreign currency forward contracts.................... $ 2,000 $ 2,000 $ 15 Fixed Canadian to U.S. dollar rate paid........ .6258 - -------------- (1) The Company's foreign currency forward contract matured as a $15 thousand asset during January 2003.
Foreign Exchange Rate Sensitivity Derivative and Other Financial Instruments as of December 31, 2001 Asset 2002 Total Fair Value -------- -------- ---------- (in thousands except interest rates) Foreign Exchange Rate Hedge Derivatives: Notional amount of foreign currency forward contracts.................... $ 24,752 $ 24,752 $ 61 Fixed Canadian to U.S. dollar rate paid........ .6266 Average forward Canadian dollar to U.S. dollar exchange rate as of February 28, 2002......... .6250
Commodity price sensitivity. The following tables provide information, in U.S. dollar equivalent amounts, about derivative financial instruments that the Company was a party to as of December 31, 2002 and 2001 and that were sensitive to changes in oil and gas prices. As of December 31, 2002 and 2001, all of the Company's derivative financial instruments that were sensitive to changes in oil and gas prices qualified as hedges. Commodity hedge instruments. The Company hedges commodity price risk with 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, C 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 and gas prices. Oil Price Sensitivity Derivative Financial Instruments as of December 31, 2002 Liability 2003 2004 Fair Value -------- -------- ------------ Oil Hedge Derivatives (1): Average daily notional Bbl volumes: Swap contracts (2)............................ 22,236 14,000 $ (19,912) Weighted average fixed price per Bbl......... $ 24.45 $ 23.11 Average forward NYMEX oil prices per Bbl (3).... $ 31.55 $ 25.75 - --------------- (1) 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 for 2003 and 2004. (2) During January 2003, the Company increased its 2003 oil hedge positions by entering into 6,000 Bbls per day of March 2003 oil swap contracts with average per Bbl fixed prices of $33.51. (3) The average forward NYMEX oil prices per Bbl are based on February 18, 2003 market quotes.
38 Oil Price Sensitivity Derivative Financial Instruments as of December 31, 2001 Asset 2002 2003 Fair Value -------- -------- ---------- Oil Hedge Derivatives (1): Average daily notional Bbl volumes: Swap contracts.................................. 9,463 2,975 $ 23,423 Weighted average fixed price per Bbl........... $ 26.23 $ 24.02 Collar contracts................................ 2,975 $ 5,506 Weighted average short call ceiling price per Bbl...................................... $ 28.61 Weighted average long put floor price per Bbl...................................... $ 25.00 Average forward NYMEX oil prices (1).............. $ 21.86 $ 21.54 - --------------- (1) The average forward NYMEX oil prices are based on February 28, 2002 market quotes.
Gas Price Sensitivity Derivative Financial Instruments as of December 31, 2002 2006 & Liability 2003 2004 2005 2007 Fair Value -------- -------- -------- --------- ---------- Gas Hedge Derivatives (1) (2): Average daily notional MMBtu volumes: Swap contracts................................... 230,000 180,000 10,000 20,000 $ (88,892) Weighted average fixed price per MMBtu.......... $ 3.76 $ 3.81 $ 3.70 $ 3.75 Average forward NYMEX gas prices per MMBtu (3)..... $ 5.53 $ 4.80 $ 4.31 $ 4.12 - -------------- (1) 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 option contracts and, accordingly, the effects of the basis swaps have been presented together with the associated contracts. (2) 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 per MMBtu by calendar quarter for 2003, 2004, 2005, 2006 and 2007. (3) The average forward NYMEX gas prices per MMBtu are based on February 18, 2003 market quotes.
Gas Price Sensitivity Derivative Financial Instruments as of December 31, 2001 Asset 2002 2003 2004 2005 Fair Value -------- -------- -------- -------- ---------- Gas Hedge Derivatives (1) (2): Average daily notional MMBtu volumes: Swap contracts.................................. 165,205 117,500 165,000 50,000 $ 137,606 Weighted average fixed price per MMBtu......... $ 4.19 $ 3.62 $ 3.84 $ 3.63 Collar contracts................................ 20,000 $ 14,019 Weighted average short call ceiling price per MMBtu................................... $ 6.00 Weighted average long put floor price per MMBtu................................... $ 4.50 Average forward NYMEX gas prices per MMBtu (2).... $ 2.68 $ 3.21 $ 3.42 $ 3.52 - --------------- (1) 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 option contracts and, accordingly, the effects of the basis swaps have been presented together with the associated contracts. (2) The average forward NYMEX gas prices per MMBtu are based on February 28, 2002 market quotes.
39 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. To realize its objectives, the Company borrows under fixed and variable rate debt instruments, based on the availability of capital, market conditions and hedge opportunities. See Note E 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 has, from time to time, entered into interest rate, foreign exchange rate and commodity price derivative contracts to hedge interest rate, foreign exchange rate and commodity price risks in accordance with policies and guidelines approved by the Company's board of directors. In accordance with those policies and guidelines, the Company's executive management determines the appropriate timing and extent of hedge transactions. Although the Company is a party to certain derivative contracts that do not qualify for hedge accounting treatment, the Company's policy is to limit its participation in derivative contracts to those that, in the opinion of management, reduce the Company's overall economic risk. As of December 31, 2002, the Company's primary risk exposures associated with financial instruments to which it is a party include oil and gas price volatility, volatility in the exchange rates of the Canadian dollar and Argentine peso vis a vis the U.S. dollar and interest rate volatility. The Company's primary risk exposures associated with financial instruments have not changed significantly since December 31, 2002. 40 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA Index to Consolidated Financial Statements Page Consolidated Financial Statements of Pioneer Natural Resources Company: Independent Auditors' Report......................................... 42 Consolidated Balance Sheets as of December 31, 2002 and 2001......... 43 Consolidated Statements of Operations for the Years Ended December 31, 2002, 2001 and 2000.................................. 44 Consolidated Statements of Stockholders' Equity for the Years Ended December 31, 2002, 2001 and 2000............................ 45 Consolidated Statements of Cash Flows for the Years Ended December 31, 2002, 2001, and 2000................................. 46 Consolidated Statements of Comprehensive Income (Loss) for the Years Ended December 31, 2002, 2001 and 2000...................... 47 Notes to Consolidated Financial Statements........................... 48 Unaudited Supplementary Information.................................. 81 41 INDEPENDENT AUDITORS' REPORT The Board of Directors and Shareholders Pioneer Natural Resources Company: We have audited the accompanying consolidated balance sheets of Pioneer Natural Resources Company as of December 31, 2002 and 2001, and the related consolidated statements of operations, stockholders' equity, cash flows and comprehensive income (loss) for each of the three years in the period ended December 31, 2002. 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 auditing standards generally accepted in the 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 Pioneer Natural Resources Company at December 31, 2002 and 2001, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2002, in conformity with accounting principles generally accepted in the United States. As discussed in Note B to the consolidated financial statements, in 2001 Pioneer Natural Resources Company adopted Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities". Ernst & Young LLP Dallas, Texas January 24, 2003 42 PIONEER NATURAL RESOURCES COMPANY CONSOLIDATED BALANCE SHEETS (in thousands, except share data) ASSETS December 31, -------------------------- 2002 2001 ----------- ----------- Current assets: Cash and cash equivalents....................................... $ 8,490 $ 14,334 Accounts receivable: Trade, net of reserves for doubtful accounts of $4,744 and $5,553 as of December 31, 2002 and 2001, respectively... 97,774 81,616 Affiliates.................................................... 448 595 Inventories..................................................... 10,648 14,549 Deferred income taxes........................................... 13,900 6,400 Other current assets: Derivative assets, net of valuation reserves of $3,351 and $3,153 as of December 31, 2002 and 2001, respectively....... 3,150 127,074 Other......................................................... 12,683 11,075 ---------- ---------- Total current assets........................................ 147,093 255,643 ---------- ---------- Property, plant and equipment, at cost: Oil and gas properties, using the successful efforts method of accounting: Proved properties............................................. 4,252,897 3,691,783 Unproved properties........................................... 219,073 187,785 Accumulated depletion, depreciation and amortization............ (1,303,541) (1,095,310) ----------- ---------- 3,168,429 2,784,258 ----------- ---------- Deferred income taxes............................................. 76,840 84,319 Other property and equipment, net................................. 22,784 21,560 Other assets, net: Derivative assets, net of valuation reserves of $1,136 and $1,069 as of December 31, 2002 and 2001, respectively......... 793 54,486 Other........................................................... 39,177 70,787 ---------- ---------- $ 3,455,116 $ 3,271,053 ========== ========== LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Accounts payable: Trade......................................................... $ 117,582 $ 92,760 Affiliates.................................................... 7,192 6,405 Interest payable................................................ 37,458 37,410 Other current liabilities: Derivative obligations........................................ 83,638 36,830 Other......................................................... 28,722 54,804 ---------- ---------- Total current liabilities................................... 274,592 228,209 ---------- ---------- Long-term debt.................................................... 1,668,536 1,577,304 Noncurrent derivative obligations................................. 42,490 32,438 Other noncurrent liabilities...................................... 85,841 133,945 Deferred income taxes............................................. 8,760 13,768 Stockholders' equity: Preferred stock, $.01 par value; 100,000,000 shares authorized; zero and one share issued and outstanding as of December 31, 2002 and 2001, respectively................ - - Common stock, $.01 par value; 500,000,000 shares authorized; 119,592,344 shares issued at December 31, 2002; and 107,422,467 shares issued at December 31, 2001................ 1,196 1,074 Additional paid-in capital...................................... 2,714,567 2,462,272 Treasury stock, at cost; 2,339,806 shares at December 31, 2002 and 3,486,073 shares at December 31, 2001................ (32,219) (48,002) Deferred compensation........................................... (14,292) - Accumulated deficit............................................. (1,298,440) (1,323,343) Accumulated other comprehensive income: Deferred hedge gains, net..................................... 9,555 201,046 Cumulative translation adjustment............................. (5,470) (7,658) ---------- ---------- Total stockholders' equity.................................. 1,374,897 1,285,389 Commitments and contingencies ---------- ---------- $ 3,455,116 $ 3,271,053 ========== ==========
The accompanying notes are an integral part of these consolidated financial statements. 43 PIONEER NATURAL RESOURCES COMPANY CONSOLIDATED STATEMENTS OF OPERATIONS (in thousands, except per share data) Year Ended December 31, ----------------------------------- 2002 2001 2000 --------- --------- --------- Revenues and other income: Oil and gas.......................................... $ 701,780 $ 847,022 $ 852,738 Interest and other................................... 11,222 21,778 25,775 Gain on disposition of assets, net................... 4,432 7,681 34,184 -------- -------- -------- 717,434 876,481 912,697 -------- -------- -------- Costs and expenses: Oil and gas production............................... 199,570 209,664 189,265 Depletion, depreciation and amortization............. 216,375 222,632 214,938 Exploration and abandonments......................... 85,894 127,906 87,550 General and administrative........................... 48,402 36,968 33,262 Interest............................................. 95,815 131,958 161,952 Other................................................ 17,256 39,588 67,231 -------- -------- -------- 663,312 768,716 754,198 -------- -------- -------- Income before income taxes and extraordinary items..... 54,122 107,765 158,499 Income tax benefit (provision)......................... (5,063) (4,016) 6,000 -------- -------- -------- Income before extraordinary items...................... 49,059 103,749 164,499 Extraordinary items - loss on early extinguishment of debt, net of tax.................................. (22,346) (3,753) (12,318) -------- -------- -------- Net income............................................. $ 26,713 $ 99,996 $ 152,181 ======== ======== ======== Income per share: Basic: Income before extraordinary items................. $ .44 $ 1.05 $ 1.65 Extraordinary items............................... (.20) (.04) (.12) -------- -------- -------- Net income........................................ $ .24 $ 1.01 $ 1.53 ======== ======== ======== Diluted: Income before extraordinary items................. $ .43 $ 1.04 $ 1.65 Extraordinary items............................... (.20) (.04) (.12) -------- -------- -------- Net income........................................ $ .23 $ 1.00 $ 1.53 ======== ======== ======== Weighted average shares outstanding: Basic............................................. 112,542 98,529 99,378 ======== ======== ======== Diluted........................................... 114,288 99,714 99,763 ======== ======== ========
The accompanying notes are an integral part of these consolidated financial statements. 44 PIONEER NATURAL RESOURCES COMPANY CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (in thousands) Accumulated Other Comprehensive Income ----------------------------- Deferred Invest- Total Additional Deferred Hedge ment Trans- Stock- Common Paid-in Treasury Compen- Accumulated Gains & Gains & lation holders' Stock Capital Stock sation Deficit Losses Losses Adjustment Equity ------- ---------- -------- --------- ----------- -------- -------- ---------- ---------- Balance at December 31, 1999...... $ 1,009 $2,348,448 $(10,384) $ - $(1,574,884) $ - $ - $ 10,425 $ 774,614 Exercise of stock options and employee stock purchases......... 4 4,160 - - - - - - 4,164 Purchase of treasury stock........ - - (27,298) - - - - - (27,298) Net income........................ - - - - 152,181 - - - 152,181 Other comprehensive income (loss): Unrealized gains on available for sale securities: Unrealized holdings gains.... - - - - - - 33,828 - 33,828 Gains included in net income...................... - - - - - - (25,674) - (25,674) Currency translation adjustment. - - - - - - - (6,910) (6,910) ------ --------- ------- -------- ---------- -------- ------- ------- --------- Balance at December 31, 2000...... 1,013 2,352,608 (37,682) - (1,422,703) - 8,154 3,515 904,905 ------ --------- ------- -------- ---------- -------- ------- ------- --------- Common stock issued for partnership acquisitions......... 57 104,236 - - - - - - 104,293 Exercise of stock options and employee stock purchases......... 4 5,428 2,708 - (636) - - - 7,504 Purchase of treasury stock........ - - (13,028) - - - - - (13,028) Net income........................ - - - - 99,996 - - - 99,996 Other comprehensive income (loss): Deferred hedge gains and losses: Transition adjustment........ - - - - - (197,444) - - (197,444) Deferred hedge gains......... - - - - - 393,004 - - 393,004 Net losses included in net income...................... - - - - - 5,486 - - 5,486 Unrealized gains and losses on available for sale securities: Unrealized holdings losses... - - - - - - (45) - (45) Gains included in net income. - - - - - - (8,109) - (8,109) Currency translation adjustment. - - - - - - - (11,173) (11,173) ------ --------- ------- -------- ---------- -------- ------- ------- --------- Balance at December 31, 2001...... 1,074 2,462,272 (48,002) - (1,323,343) 201,046 - (7,658) 1,285,389 ------ --------- ------- -------- ---------- -------- ------- ------- --------- Issuance of common stock.......... 115 235,885 - - - - - - 236,000 Adjustment to common stock issued for 2001 partnership acquisitions.................... - (175) - - - - - - (175) Exercise of stock options and employee stock purchases......... - 416 15,783 - (1,810) - - - 14,389 Deferred compensation: Compensation deferred........... 7 16,169 - (16,176) - - - - - Deferred compensation included in net income.................. - - - 1,884 - - - - 1,884 Net income........................ - - - - 26,713 - - - 26,713 Other comprehensive income (loss): Deferred hedge gains and losses, net of tax: Deferred hedge losses........ - - - - - (179,067) - - (179,067) Net gains included in net income...................... - - - - - (12,424) - - (12,424) Currency translation adjustment. - - - - - - - 2,188 2,188 ------ --------- ------- ------- ---------- -------- ------- ------- --------- Balance at December 31, 2002...... $ 1,196 $2,714,567 $(32,219) $(14,292) $(1,298,440) $ 9,555 $ - $ (5,470) $1,374,897 ====== ========= ======= ======= ========== ======== ======= ======= =========
The accompanying notes are an integral part of these consolidated financial statements. 45 PIONEER NATURAL RESOURCES COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (in thousands) Year Ended December 31, ------------------------------------- 2002 2001 2000 --------- --------- ----------- Cash flows from operating activities: Net income.................................................. $ 26,713 $ 99,996 $ 152,181 Adjustments to reconcile net income to net cash provided by operating activities: Depletion, depreciation and amortization............... 216,375 222,632 214,938 Exploration expenses, including dry holes.............. 64,617 103,595 66,959 Deferred income taxes.................................. 2,788 (7,649) (10,600) Gain on disposition of assets, net..................... (4,432) (7,681) (34,184) Loss on early extinguishment of debt, net of tax....... 22,346 3,753 12,318 Interest related amortization.......................... (5,809) 8,689 12,699 Commodity hedge related amortization................... 26,490 6,199 - Other noncash items.................................... 9,301 14,944 59,776 Change in operating assets and liabilities, net of effects from acquisitions: Accounts receivable.................................... (23,922) 41,295 (7,486) Inventory.............................................. 3,023 (4,256) (2,789) Other current assets................................... (1,836) (6,304) (9,896) Accounts payable....................................... (342) (541) 26,260 Interest payable....................................... 48 (733) 2,097 Other current liabilities.............................. (3,115) 1,661 (52,177) -------- -------- ---------- Net cash provided by operating activities.............. 332,245 475,600 430,096 -------- -------- ---------- Cash flows from investing activities: Cash acquired in acquisitions, net of fees paid............. - 11,119 - Proceeds from disposition of assets......................... 118,850 113,453 102,736 Additions to oil and gas properties......................... (614,698) (529,723) (299,682) Other property dispositions (additions), net................ (12,283) (17,590) 2,445 -------- -------- ---------- Net cash used in investing activities.................. (508,131) (422,741) (194,501) -------- -------- ---------- Cash flows from financing activities: Borrowings under long-term debt............................. 529,805 328,331 922,607 Principal payments on long-term debt........................ (481,783) (333,410) (1,099,935) Common stock issuance proceeds, net of issuance costs....... 236,000 - - Payments of other noncurrent liabilities.................... (124,245) (53,437) (29,759) Exercise of stock options and employee stock purchases...... 14,389 7,504 4,164 Purchase of treasury stock.................................. - (13,028) (27,298) Deferred loan fees/issuance costs........................... (3,293) - (13,847) -------- -------- ---------- Net cash provided by (used in) financing activities.... 170,873 (64,040) (244,068) -------- -------- ---------- Net decrease in cash and cash equivalents .................... (5,013) (11,181) (8,473) Effect of exchange rate changes on cash and cash equivalents.. (831) (644) (156) Cash and cash equivalents, beginning of year.................. 14,334 26,159 34,788 -------- -------- ---------- Cash and cash equivalents, end of year........................ $ 8,490 $ 14,334 $ 26,159 ======== ======== ==========
The accompanying notes are an integral part of these consolidated financial statements. 46 PIONEER NATURAL RESOURCES COMPANY CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (in thousands) Year ended December 31, ------------------------------------ 2002 2001 2000 ---------- ---------- ---------- Net income............................................ $ 26,713 $ 99,996 $ 152,181 Other comprehensive income (loss): Deferred hedge gains and losses, net of tax: Transition adjustment............................ - (197,444) - Deferred hedge gains (losses).................... (179,067) 393,004 - Net (gains) losses included in net income........ (12,424) 5,486 - Gains and losses on available for sale securities: Unrealized holding gains (losses)................ - (45) 33,828 Gains included in net income..................... - (8,109) (25,674) Currency translation adjustment..................... 2,188 (11,173) (6,910) --------- ---------- --------- Other comprehensive income (loss).............. (189,303) 181,719 1,244 --------- --------- --------- Comprehensive income (loss)........................... $ (162,590) $ 281,715 $ 153,425 ========= ========= =========
The accompanying notes are an integral part of these consolidated financial statements. 47 PIONEER NATURAL RESOURCES COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 2002, 2001 and 2000 NOTE A. Organization and Nature of Operations Pioneer Natural Resources Company (the "Company") is a Delaware corporation whose common stock is listed and traded on the New York Stock Exchange. The Company is an oil and gas exploration and production company with ownership interests in oil and gas properties located in the United States, Argentina, Canada, South Africa, Gabon 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 subsidiaries since their acquisition or formation, and the Company's interest in the affiliated oil and gas partnerships for which it serves as general partner through certain of its wholly-owned subsidiaries. The Company proportionately consolidates less than 100 percent-owned oil and gas partnerships in accordance with industry practice. The Company owns less than a 20 percent interest in the oil and gas partnerships that it proportionately consolidates. All material intercompany balances and transactions have been eliminated. Investments in non-affiliated equity securities that have a readily determinable fair value are classified as "trading securities" if management's current intent is to hold them for only a short period of time; otherwise, they are accounted for as "available-for-sale" securities. The Company reevaluates the classification of investments in non-affiliated equity securities at each balance sheet date. The carrying value of trading securities and available-for-sale securities are adjusted to fair value as of each balance sheet date. Unrealized holding gains are recognized for trading securities in interest and other revenue, and unrealized holding losses are recognized in other expense during the periods in which changes in fair value occur. As of December 31, 2002, the Company had $.2 million of trading securities recorded to other assets. The Company had no investments in trading securities as of December 31, 2001. 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 did not have any investments in available-for-sale securities as of December 31, 2002 or 2001. Investments in non-affiliated 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 did not have any equity security investments that did not have a readily determinable fair value as of December 31, 2002 or 2001. Use of estimates in the preparation of financial statements. Preparation of the accompanying consolidated financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Depletion of oil and gas properties is determined using estimates of proved oil and gas reserves. There are numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. Similarly, evaluations for impairment of proved and unproved oil and gas properties are subject to numerous uncertainties including, among others, estimates of future recoverable reserves; commodity price outlooks; foreign laws, restrictions and currency exchange rates; and export and excise taxes. Early in January 2002, the Argentine government severed the direct one-to-one U.S. dollar to Argentine peso relationship that had existed for many years. The following bullet points disclose the significant Argentine assumptions utilized in the preparation of the 2002 and 2001 financial statements: 48 PIONEER NATURAL RESOURCES COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 2002, 2001 and 2000 o As of December 31, 2002 and 2001, the Company used exchange rates of 3.37 pesos to $1 and 1.7 pesos to $1, respectively, to remeasure the peso-denominated monetary assets and liabilities of the Company's Argentine subsidiaries. o As part of the December 31, 2001 remeasurement process, the Company estimated that the recovery or settlement values to be realized on pre-devaluation, peso-denominated receivables and payables would be approximately 1.2 pesos to $1. o After remeasuring inventory at historical exchange rates, the Company reduced the carrying value of its Argentine lease and well equipment to market values. The market value of the inventory was estimated to be 15 percent higher than the historical peso balance, but lower than the Company's carrying cost on an equivalent U.S. dollar basis as of December 31, 2001. o The Company reviewed its Argentine proved and unproved properties for impairment as of December 31, 2002 and 2001. The Company's assessments were based on the Company's expectations of future commodity prices to be received and expenses to be paid in Argentina. The December 31, 2002 assumptions utilized to determine future net cash flows had oil and natural gas liquids ("NGLs") prices at world market prices adjusted for export taxes and local market discounts. Gas prices were assumed to return to predevaluation U.S. dollar levels after a period of time to allow for inflation. Expenses were initially assumed to be equivalent to reported expenses in 2002, but to gradually increase to 15 percent above 2002 levels. Based upon these assumptions, the Company determined that the carrying value of its proved and unproved properties was fully recoverable. The remeasurement of the peso-denominated monetary net assets of the Company's Argentine subsidiaries as of December 31, 2002 resulted in the Company recognizing a $6.9 million charge during 2002. The December 31, 2001 remeasurement of the Company's Argentine subsidiaries' peso-denominated monetary net assets and the adjustment to reduce the subsidiaries' carrying values of lease and well equipment inventory to market values resulted in the Company recognizing a $7.7 million charge in 2001. Numerous uncertainties exist surrounding the ultimate resolution of Argentina's economic and political instability and actual results could differ from those estimates and assumptions utilized. The Argentine economic and political situation continues to evolve and the Argentine government may enact future regulations or policies that, when finalized and adopted, may materially impact, among other items, (i) the realized prices the Company receives for the commodities it produces and sells; (ii) the timing of repatriations of excess cash flow to the Company's corporate headquarters in the United States; (iii) the Company's asset valuations; and (iv) peso-denominated monetary assets and liabilities. New accounting pronouncements. During June 2001, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations" ("SFAS 143"). SFAS 143 amends Statement of Financial Accounting Standards No. 19, "Financial Accounting and Reporting by Oil and Gas Producing Companies" ("SFAS 19") to require that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. Under the provisions of SFAS 143, asset retirement obligations are capitalized as part of the carrying value of the long-lived asset. Under the provisions of SFAS 19, asset retirement obligations are recognized using a cost-accumulation approach. The Company currently records significant asset retirement obligations through the unit-of-production method, except for such liabilities that were assumed in business combinations, which were recorded at their estimated fair values. The Company adopted the provisions of SFAS 143 on January 1, 2003. The adoption of SFAS 143 resulted in a January 1, 2003 cumulative effect adjustment to record (i) a $13.8 million increase in the carrying values of proved properties, (ii) a $26.3 million decrease in accumulated depreciation, depletion, 49 PIONEER NATURAL RESOURCES COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 2002, 2001 and 2000 and amortization of property, plant and equipment, (iii) a $1.0 million increase in current abandonment liabilities and (iv) a $22.4 million increase in noncurrent abandonment liabilities. The net impact of items (i) through (iv) was to record a gain of $16.7 million, net of tax, as a cumulative effect adjustment of a change in accounting principle in the Company's consolidated statements of operations upon adoption on January 1, 2003. During April 2002, the FASB issued Statement of Financial Accounting Standards No. 145, "Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13 and Technical Corrections" ("SFAS 145"). Prior to the adoption of the provisions of SFAS 145, gains or losses on the early extinguishment of debt were required to be classified in a company's periodic consolidated statements of operations as extraordinary gains or losses, net of associated income taxes, after the determination of income or loss from continuing operations. SFAS 145 requires, except in the case of events or transactions of a highly unusual and infrequent nature, gains or losses from the early extinguishment of debt to be classified as components of a company's income or loss from continuing operations. The Company adopted the provisions of SFAS 145 on January 1, 2003. The adoption of the provisions of SFAS 145 is not expected to affect the Company's future financial position or liquidity. Upon adoption of the provisions of SFAS 145, gains or losses from the early extinguishment of debt recognized in the Company's consolidated statements of operations for the years ended December 31, 2002, 2001 and 2000 will be reclassified to other revenues or other expense and included in the determination of the income (loss) from continuing operations of those periods. Cash equivalents. Cash and cash equivalents include cash on hand and depository accounts held by banks. Inventories - equipment. Lease and well equipment to be used in future production and drilling activities are carried at the lower of cost or market, on a first-in, first-out basis. The Company has established lower of cost or market allowances to reduce the carrying values of its equipment inventories in the amounts of $3.6 million and $6.8 million as of December 31, 2002 and 2001, respectively. Inventories - commodities. Commodities are carried at the lower of average cost or market. When sold from inventory, commodities are removed on a first-in, first-out basis. 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 also expenses the costs associated with exploratory wells that find oil and gas reserves if a determination that proved reserves have been found cannot be made within one year of the exploration well being drilled. The Company capitalizes interest on expenditures for significant development projects until such projects are ready for their intended use. The Company owns interests in 11 natural gas processing plants and five treating facilities. The Company operates seven of the plants and all five treating facilities. The Company's ownership in the natural gas processing plants and treating facilities is primarily to accommodate handling the Company's gas production and thus are considered a component of the capital and operating costs of the respective fields that they service. To the extent that there is excess capacity at a plant or treating facility, the Company attempts to process third party gas volumes for a fee to keep the plant or treating facility at capacity. All revenues and expenses derived from third party gas volumes processed through the plants and treating facilities are reported as components of oil and gas production costs. The third party revenues generated from the plant and treating facilities for the three years ended December 31, 2002, 2001 and 2000 were $28.4 million, $32.7 million and $36.3 million, respectively. The third party expenses attributable to the plants and treating facilities for those same periods were $9.3 million, $9.7 million and $9.0 million, respectively. 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. 50 PIONEER NATURAL RESOURCES COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 2002, 2001 and 2000 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. Capitalized costs of individual properties sold or abandoned are charged to accumulated depletion, depreciation and amortization with the proceeds from the sales of individual properties credited to property costs. No gain or loss is recognized until the entire amortization base is sold. However, gain or loss is recognized from the sale of less than an entire amortization base if the disposition is significant enough to materially impact the depletion rate of the remaining properties in the amortization base. If significant, the Company accrues the estimated future costs to plug and abandon wells under the unit-of-production method. The charge, if any, is reflected in the accompanying Consolidated Statements of Operations as abandonment expense while the liability is reflected in the accompanying Consolidated Balance Sheets as other liabilities. Plugging and abandonment liabilities assumed in a business combination accounted for as a purchase are recorded at fair value. At December 31, 2002 and 2001, the Company has recognized plugging and abandonment liabilities of $34.7 million and $39.5 million, respectively. See "New accounting pronouncements" for a discussion of the provisions of SFAS 143 that will be adopted by the Company on January 1, 2003. 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 that are individually significant are periodically assessed for impairment by comparing their cost to their estimated value on a project-by-project basis. The estimated value 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. The remaining unproved oil and gas properties, if any, are aggregated and an overall impairment allowance is provided based on the Company's historical experience. Treasury stock. Treasury stock purchases are recorded at cost. Upon reissuance, the cost of treasury shares held is reduced by the average purchase price per share of the aggregate treasury shares held. Environmental. The Company's environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Expenditures that extend the life of the related property or mitigate or prevent future environmental contamination are capitalized. Liabilities are recorded when environmental assessment and/or remediation is probable and the costs can be reasonably estimated. Such liabilities are undiscounted unless the timing of cash payments for the liability are fixed or reliably determinable. Revenue recognition. The Company uses the entitlements method of accounting for oil, NGL and gas revenues. Sales proceeds in excess of the Company's entitlement are included in other liabilities and the Company's share of sales taken by others is included in other assets in the accompanying Consolidated Balance Sheets. The following table presents the Company's entitlement assets and entitlement liabilities and their associated volumes as of December 31, 2002 and 2001 (in millions): 51 PIONEER NATURAL RESOURCES COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 2002, 2001 and 2000 December 31, --------------------------------- 2002 2001 --------------- --------------- Amount MMcf Amount MMcf ------ ------ ------ ------ Entitlement assets....................... $ 9.7 4,240 $ 30.9 25,335 Entitlement liabilities.................. $ 15.1 14,302 $ 20.3 15,197
Derivatives and hedging. Prior to January 1, 2001, the following criteria were required to be met in order for the Company to account for a derivative instrument as a hedge of an existing asset or liability, or of a forecasted transaction: an asset, liability or forecasted transaction must have existed that exposed the Company to price, interest rate or foreign exchange rate risk that was not offset in another asset or liability; the derivative instrument must have reduced that price, interest rate or foreign exchange rate risk; and, the derivative instrument must have been designated as a hedge at the inception of the instrument and throughout the hedge period. Additionally, in order to qualify as a hedge, there must have been clear correlation between changes in the fair value or expected cash flows of the derivative instrument and the fair value or expected cash flows of the hedged asset or liability, or forecasted transaction, such that changes in the derivative instrument offset the effect of price, interest rate or foreign exchange rate changes on the exposed items. Prior to January 1, 2001, gains or losses realized from derivative instruments that qualified as hedges were deferred as assets or liabilities until the underlying hedged asset, liability or transaction monetized, matured or was otherwise recognized under generally accepted accounting principles. When recognized in net income (loss), hedge gains and losses were classified as components of the commodity prices, interest or foreign exchange rates that the derivative instrument hedged. Derivative instruments that were not hedges were recorded at fair value, as assets or liabilities. Changes in the fair values of non-hedge derivative instruments were recognized as other income or other expense during the periods in which their fair values changed. In June 1998, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" ("SFAS 133") as amended, the provisions of which the Company adopted effective January 1, 2001. 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 (loss). 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 (loss). Effective changes in the fair value of derivative instruments that are cash flow hedges are recognized in Accumulated other comprehensive income ("AOCI") - deferred hedge gains, net in the stockholders' equity section of the Company's Consolidated Balance Sheets until such time as the hedged items are recognized in net income (loss). Ineffective portions of a derivative instrument's change in fair value are immediately recognized in net income (loss). The adoption of SFAS 133 resulted in a January 1, 2001 transition adjustment to (i) reclassify $57.8 million of deferred losses on terminated hedge positions from other assets (including $11.6 million of other current assets), (ii) increase other current assets, other assets and other current liabilities by $7.0 million, $6.2 million and $146.6 million, respectively, to record the fair value of open hedge derivatives, (iii) increase the carrying value of hedged long-term debt by $6.2 million and (iv) reduce stockholders' equity by $197.4 million for the net impact of items (i) through (iii) above. The $197.4 million reduction in stockholders' equity was reflected as a transition adjustment in other comprehensive income (loss) on January 1, 2001. 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 52 PIONEER NATURAL RESOURCES COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 2002, 2001 and 2000 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 actual hedge effectiveness at the end of each calendar quarter. See Note J for a description of the specific types of derivative transactions in which the Company participates. Stock-based compensation. The Company has a long-term incentive plan (the "Long-Term Incentive Plan") under which the Company grants stock-based compensation. The Long-Term Incentive Plan is described more fully in Note G. The Company accounts for stock-based compensation granted under the Long-Term Incentive Plan using the intrinsic value method prescribed by Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees" ("APB 25") and related interpretations. Stock-based compensation expenses were not recognized in net income, as all options granted under the Long-Term Incentive Plan had exercise prices equal to the market value of the underlying common stock on the dates of grant. The following table illustrates the effect on net income and earnings per share if the Company had applied the fair value recognition provisions of Statement of Financial Accounting Standards No. 123, "Accounting for Stock-Based Compensation" ("SFAS 123") to stock-based employee compensation: Year ended December 31, -------------------------------- 2003 2002 2001 -------- -------- -------- (in thousands, except per share amounts) Net income, as reported............................... $ 26,713 $ 99,996 $152,181 Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects... (9,807) (6,533) (4,163) ------- ------- ------- Pro forma net income.................................. $ 16,906 $ 93,463 $148,018 ======= ======= ======= Net income per share: Basic - as reported................................. $ .24 $ 1.01 $ 1.53 ======= ======= ======= Basic - pro forma................................... $ .15 $ .95 $ 1.49 ======= ======= ======= Diluted - as reported............................... $ .23 $ 1.00 $ 1.53 ======= ======= ======= Diluted - pro forma................................. $ .15 $ .94 $ 1.48 ======= ======= =======
Foreign currency translation. The U.S. dollar is the functional currency for all of the Company's international operations except Canada. Accordingly, monetary assets and liabilities denominated in a foreign currency are remeasured to U.S. dollars at the exchange rate in effect at the end of each reporting period; revenues and costs and expenses denominated in a foreign currency are remeasured at the average of the exchange rates that were in effect during the period in which the revenues and costs and expenses were recognized. The resulting gains or losses from remeasuring foreign currency denominated balances into U.S. dollars are recorded in other income or other expense, respectively. Non-monetary assets and liabilities denominated in a foreign currency are remeasured at the historic exchange rates that were in effect when the assets or liabilities were acquired or incurred. The functional currency of the Company's Canadian operations is the Canadian dollar. The financial statements of the Company's Canadian subsidiary entities are translated to U. S. dollars as follows: all assets and liabilities are translated using the exchange rate in effect at the end of each reporting period; revenues and costs and expenses are translated using the average of the exchange rates that were in effect during the period in which the revenues and costs and expenses were recognized. The resulting gains or losses from translating non-U.S. dollar denominated balances are 53 PIONEER NATURAL RESOURCES COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 2002, 2001 and 2000 recorded in the accompanying Consolidated Statements of Stockholders' Equity for the period through accumulated other comprehensive income (loss). The exchange rates used to translate the financial statements of the Company's Canadian subsidiary in the preparation of these consolidated financial statements appear below: December 31, ----------------------- 2002 2001 2000 ----- ----- ----- Translation: U.S. Dollar from Canadian Dollar - Balance Sheets.............. .6362 .6277 .6671 U.S. Dollar from Canadian Dollar - Statements of Operations.... .6371 .6356 .6650
Reclassifications. Certain reclassifications have been made to the 2001 and 2000 amounts to conform to the 2002 presentation. NOTE C. 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, 2002 and 2001: 2002 2001 --------------------- ---------------------- Carrying Fair Carrying Fair Value Value Value Value --------- --------- --------- ---------- (in thousands) Derivative contract assets (liabilities): Commodity price hedges.................... $(108,837) $(108,837) $ 151,290 $ 151,290 Btu swap contracts........................ $ (13,363) $ (13,363) $ (19,422) $ (19,422) Interest rate swaps....................... $ - $ - $ (19,637) $ (19,637) Foreign currency contracts................ $ 15 $ 15 $ 61 $ 61 Financial assets: Trading securities........................ $ 236 $ 236 $ - $ - 5-1/2% note receivable due 2008........... $ 2,247 $ 2,283 $ - $ - Financial liabilities - long-term debt: Line of credit............................ $(260,000) $(260,000) $(294,000) $(294,000) 8-7/8% senior notes due 2005.............. $(146,704) $(147,318) $(161,998) $(159,000) 8-1/4% senior notes due 2007.............. $(161,130) $(164,925) $(153,672) $(154,215) 6-1/2% senior notes due 2008.............. $(362,592) $(359,205) $(332,613) $(329,280) 9-5/8% senior notes due 2010.............. $(338,197) $(406,901) $(385,110) $(421,508) 7-1/2% senior notes due 2012.............. $(150,000) $(160,635) $ - $ - 7-1/5% senior notes due 2028.............. $(249,913) $(245,025) $(249,911) $(204,175)
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. During the year ended December 31, 2002, the Company terminated all of its interest rate swaps and the Company's foreign currency contracts matured. 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. 54 PIONEER NATURAL RESOURCES COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 2002, 2001 and 2000 Financial assets. As of December 31, 2002, the Company had an investment in bonds that were classified as trading securities and a note receivable. The Company divested the bonds during January 2003. The fair value of the 5-1/2 percent note receivable was determined based on underlying market rates of interest. 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 E for additional information regarding the Company's long-term debt. NOTE D. Acquisitions Falcon acquisitions. During the year ended December 31, 2002, the Company purchased, through two transactions, an additional 30 percent working interest in the Falcon field development and a 25 percent working interest in associated acreage in the deepwater Gulf of Mexico for a combined purchase price of $61.1 million. As a result of these transactions, the Company owns a 75 percent working interest in and operates the Falcon field development and related exploration blocks. West Panhandle acquisitions. During July 2002, the Company completed the purchase of the remaining 23 percent of the rights that the Company did not already own in its core area West Panhandle gas field, 100 percent of the West Panhandle reserves attributable to field fuel, 100 percent of the related West Panhandle field gathering system and ten blocks surrounding the Company's deepwater Gulf of Mexico Falcon discovery. In connection with these transactions, the Company recorded $100.4 million to proved oil and gas properties, $3.8 million to unproved oil and gas properties and $1.9 million to assets held for resale; retired a capital cost obligation for $60.8 million; settled a $20.9 million gas balancing receivable; assumed trade and environmental obligations amounting to $5.8 million in the aggregate; and paid $140.2 million of cash. The capital cost obligation retired by the Company for $60.8 million represented an obligation for West Panhandle gas field capital additions that was not able to be prepaid and bore interest at an annual rate of 20 percent. The portion of the purchase price allocated to the retirement of the capital cost obligation was based on a discounted cash flow analysis using a market discount rate for obligations with similar terms. The capital cost obligation had a carrying value of $45.2 million, resulting in an extraordinary loss of $15.6 million from the early extinguishment of this obligation. Affiliated partnership mergers. During 2001, the limited partners of 42 of the Company's affiliated partnerships approved an agreement and plan of merger ("Plan of Merger") among the Company, Pioneer Natural Resources USA, Inc. ("Pioneer USA"), a wholly-owned subsidiary of the Company, and the partnerships. The Plan of Merger was accounted for as a purchase business combination. In consideration for the partnerships' net assets, the limited partners received 5.7 million shares of the Company's common stock valued at $18.35 per share. In connection with this transaction, the Company recorded $92.9 million to proved oil and gas properties, $13.6 million to cash and $.3 million to other net assets. The cash acquired from the partnerships, net of $2.5 million of cash transaction costs, is included in "cash acquired in acquisitions, net of fees paid" in the accompanying Consolidated Statement of Cash Flows for the year ended December 31, 2001. Except for the cash acquired, this transaction represents a noncash investing activity of the Company that was funded by the issuance of common stock. During 2000, the Company received the approval of the partners of 13 employee partnerships to merge with Pioneer USA for a purchase price of $2.0 million. Of the total purchase price, $317 thousand was paid to Company employees. Additionally, during 2000, the Company purchased all of the direct oil and gas interests held by the Company's Chairman of the Board and Chief Executive Officer for $195 thousand. Other acquisitions. During the year ended December 31, 2002, in addition to the Falcon and West Panhandle acquisitions referred to above, the Company spent approximately $25.5 million to acquire additional unproved acreage in the United States, including 34 Gulf of Mexico shelf blocks, six deepwater Gulf of Mexico blocks, a 70 percent 55 PIONEER NATURAL RESOURCES COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 2002, 2001 and 2000 working interest in ten state leases on Alaska's North Slope and property interests in other areas of the United States. Also during 2002, the Company acquired unproved and proved oil and gas property interests in Canada for 2.3 million and $.5 million, respectively, and $1.8 million of additional unproved property interests in Tunisia. During 2001, the Company spent $77.9 million to acquire additional working interests in the United States Gulf of Mexico Aconcagua discovery, the related Canyon Express gathering system and the Devils Tower project; 21 deepwater Gulf of Mexico blocks; 250,000 acres in the Anticlinal Campamento, Dos Hermanas and La Calera areas of the Neuquen Basin in Argentina; and a 30 percent interest in the Anaguid permit in the Ghadames basin onshore Southern Tunisia. During 2000, the Company spent $65.0 million to acquire additional working interests in the United States Gulf of Mexico discovery at Devils Tower and the Chinchaga gas field in Canada, an interest in the Camden Hills deepwater Gulf of Mexico discovery and the Canyon Express gathering system. NOTE E. Long-term Debt Long-term debt, including the effects of fair value hedges and discounts, consisted of the following components at December 31, 2002 and 2001: December 31, --------------------------- 2002 2001 ---------- ----------- (in thousands) Line of credit............................... $ 260,000 $ 294,000 8-7/8% senior notes due 2005................. 146,704 161,998 8-1/4% senior notes due 2007................. 161,130 153,672 6-1/2% senior notes due 2008................. 362,592 332,613 9-5/8% senior notes due 2010................. 338,197 385,110 7-1/2% senior notes due 2012................. 150,000 - 7-1/5% senior notes due 2028................. 249,913 249,911 --------- --------- $1,668,536 $1,577,304 ========= =========
Maturities of long-term debt at December 31, 2002 are as follows (in thousands): 2003 and 2004................... $ - 2005............................ $ 406,704 2006............................ $ - 2007............................ $ 161,130 Thereafter...................... $1,100,702
Line of credit. During May 2000, the Company entered into a $575.0 million corporate credit facility (the "Credit Agreement") with a syndication of banks (the "Banks") that matures on March 1, 2005. Advances under the Credit Agreement bear interest, at the option of the Company, based on (a) a base rate equal to the higher of the Bank of America, N.A. prime rate (4.25 percent at December 31, 2002) or a rate per annum based on the weighted average of the rates on overnight Federal funds transactions with members of the Federal Reserve System (1.16 percent at December 31, 2002), plus 50 basis points; plus a eurodollar margin (the "Eurodollar Margin") less 125 basis points, (b) a Eurodollar rate, substantially equal to the London Interbank Offered Rate ("LIBOR") (1.38 percent at December 31, 2002 for 90 day borrowings), plus a Eurodollar Margin, or (c) a fixed rate (for aggregate advances not exceeding $50 million) as quoted by the Banks pursuant to a request by the Company. The Eurodollar Margin is based on a grid of the Company's debt rating and ratio of total debt to earnings before gain or loss on the disposition of assets; interest expense; income taxes; depreciation, depletion and amortization expense; exploration and abandonment expense and other noncash charges and expenses (the "Total Leverage Ratio"). As of December 31, 2002, the Eurodollar Margin was 137.5 basis points. 56 PIONEER NATURAL RESOURCES COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 2002, 2001 and 2000 The Credit Agreement imposes certain restrictive covenants on the Company, including the maintenance of a Total Leverage Ratio not to exceed 3.75 to 1.00; maintenance of an annual ratio of the net present value of the Company's oil and gas properties to total debt of at least 1.25 to 1.00; a limitation on the Company's total debt; and, restrictions on certain payments. The Company was in compliance with all of its debt covenants as of December 31, 2002. As of December 31, 2002 and 2001, the Company had $27.2 million and $27.9 million of undrawn letters of credit issued under the Credit Agreement, respectively, and unused Credit Agreement borrowing capacity of $287.8 million and $253.1 million, respectively. Senior notes. The Company's senior notes are general unsecured obligations ranking equally in right of payment with all other senior unsecured indebtedness of the Company and are senior in right of payment to all existing and future subordinated indebtedness of the Company. The Company is a holding company that conducts all of its operations through subsidiaries; consequently, the senior notes issuances are structurally subordinated to all obligations of its subsidiaries. Interest on the Company's senior notes is payable semiannually. Pioneer USA has fully and unconditionally guaranteed the senior note issuances. See Note R for a discussion of Pioneer USA debt guarantees and Consolidating Financial Statements. During April 2002, the Company issued $150.0 million of 7-1/2 percent senior notes due April 15, 2012 (the "7-1/2 percent senior notes"). The 7-1/2 percent senior notes were issued at a price equal to 100 percent of their principal amount and resulted in net proceeds to the Company, after underwriting discounts, commissions and costs of issuance, of $146.7 million. The net proceeds from the issuance of the 7-1/2 percent senior notes were used to reduce outstanding borrowings under the Credit Agreement. The 7-1/2 percent senior notes and 9-5/8 percent senior notes contain various restrictive covenants, including restrictions on the incurrence of additional indebtedness and certain payments defined within the associated indenture. The Company in compliance with all of its senior note covenants as of December 31, 2002. Early extinguishment of debt and capital cost obligation. During the year ended December 31, 2002, the Company repurchased $47.1 million of its outstanding 9-5/8 percent senior notes, $13.9 million of its outstanding 8-7/8 percent senior notes and repaid a $45.2 million capital cost obligation. The Company recognized extraordinary losses, net of taxes, of $6.7 million and $15.6 million associated with these debt extinguishments, respectively. See Note D for additional information regarding the capital cost obligation that was repaid during the year ended December 31, 2002. During 2001, the Company redeemed the remaining $22.5 million of outstanding 11-5/8 percent senior subordinated discount notes and $6.8 million of outstanding 10-5/8 percent senior subordinated notes. Additionally, the Company repurchased $38.7 million of its 9-5/8 percent senior notes during 2001. Associated with these debt extinguishments, the Company recognized an extraordinary loss, net of taxes, of $3.8 million during the year ended December 31, 2001. In May 2000, the Company recognized an extraordinary loss of $12.3 million, net of tax, from the early extinguishment of its prior revolving credit facility. See Note B for a discussion of the classification of gains and losses on the early extinguishment of debt after the adoption of SFAS 145 on January 1, 2003. Interest expense. The following amounts have been incurred and charged to interest expense for the years ended December 31, 2002, 2001 and 2000: 57 PIONEER NATURAL RESOURCES COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 2002, 2001 and 2000 Year ended December 31, ------------------------------------- 2002 2001 2000 --------- --------- ----------- (in thousands) Cash payments for interest................................ $ 113,827 $ 129,992 $ 147,156 Accretion/amortization of discounts or premiums on loans.. 5,488 7,937 7,995 Amortization of deferred hedge gains (see Note J)......... (14,108) (2,750) - Amortization of capitalized loan fees..................... 2,436 2,252 2,769 Kansas ad valorem tax (see Note I)........................ 375 1,250 1,935 Net change in accruals.................................... 48 (732) 2,097 -------- -------- --------- Interest incurred....................................... 108,066 137,949 161,952 Less interest capitalized............................... (12,251) (5,991) - -------- -------- --------- Interest expense..................................... $ 95,815 $ 131,958 $ 161,952 ======== ======== ========
NOTE F. Related Party Transactions Activities with affiliated partnerships. Prior to 1992, the Company, through its wholly-owned subsidiaries, sponsored 44 drilling partnerships, three public income partnerships and 13 affiliated employee partnerships, all of which were formed primarily for the purpose of drilling and completing wells or acquiring producing properties. During 2001, the Company completed the merger of 42 of the limited partnerships into Pioneer USA. During 2000, the Company completed the merger of the 13 employee partnerships into Pioneer USA. See Note D for additional information regarding the mergers. During 1994, 1993 and 1992, the Company formed a Direct Investment Partnership for the purpose of permitting selected key employees to invest directly, on an unpromoted basis, in wells that the Company drilled in those years. In November 2000, the Company exercised its right under the Direct Investment Partnership agreements to purchase each partner's interest in their respective Direct Investment Partnership. The Company paid $4.3 million to complete the purchase, of which $887 thousand was paid to Company employees. 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. The activities with affiliated partnerships are summarized for the following related party transactions for the years ended December 31, 2002, 2001 and 2000: 2002 2001 2000 ------ ------ ------ (in thousands) Receipt of lease operating and supervision charges in accordance with standard industry operating agreements........................................... $1,495 $9,281 $9,222 Reimbursement of general and administrative expenses.... $ 127 $1,265 $1,550
NOTE G. Incentive Plans Retirement Plans Deferred compensation retirement plan. In August 1997, the Compensation Committee of the Board of Directors approved a deferred compensation retirement plan for the officers and certain key employees of the Company. Each officer and key employee is allowed to contribute up to 25 percent of their base salary. The Company will then 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 58 PIONEER NATURAL RESOURCES COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 2002, 2001 and 2000 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 $805 thousand, $652 thousand and $611 thousand for 2002, 2001 and 2000, respectively. 401(k) plan. The Pioneer Natural Resources USA, Inc. 401(k) and Matching Plan (the "401(k) Plan") is a defined contribution plan established under the Internal Revenue Code Section 401. The 401(k) Plan was formed by the merger of the Pioneer Natural Resources USA, Inc. 401(k) Plan and the Pioneer Natural Resources USA, Inc. Matching Plan on January 1, 2002. All regular full-time and part-time employees of Pioneer USA are eligible to participate in the 401(k) Plan on the first day of the month following their date of hire. Participants may contribute an amount of not less than two percent nor more than 12 percent of their annual salary into the 401(k) Plan. Matching contributions are made to the 401(k) Plan in cash by Pioneer USA in amounts equal to 200 percent of a participant's contributions to the 401(k) Plan that are not in excess of five percent of the participant's basic compensation (the "Matching Contribution"). Each participant's account is credited with the participant's contributions, their Matching Contributions and allocations of the 401(k) Plan's earnings. Participants are fully vested in their account balances except for Matching Contributions and their proportionate share of 401(k) Plan earnings attributable to Matching Contributions, which proportionately vest over a four year period that begins with the participant's date of hire. During the years ended December 31, 2002, 2001 and 2000, the Company recognized compensation expense of $4.1 million, $3.4 million and $3.4 million, respectively, as a result of Matching Contributions. Long-Term Incentive Plan In August 1997, the Company's stockholders approved the Long-Term Incentive Plan, which provides for the granting of incentive awards in the form of stock options, stock appreciation rights, performance units and restricted stock to directors, officers and employees of the Company. The Long-Term Incentive Plan provides for the issuance of a maximum number of shares of common stock equal to 10 percent of the total number of shares of common stock equivalents outstanding less the total number of shares of common stock subject to outstanding awards under any stock-based plan for the directors, officers or employees of the Company. The following table calculates the number of shares or options available for grant under the Company's Long-Term Incentive Plan as of December 31, 2002 and 2001: December 31, -------------------------- 2002 2001 ----------- ----------- Shares outstanding................................................ 117,252,538 103,936,394 Outstanding exercisable options or exercisable within 60 days..... 5,024,173 4,658,155 ----------- ----------- 122,276,711 108,594,549 =========== =========== Maximum shares/options allowed under the Long-Term Incentive Plan. 12,227,671 10,859,455 Less: Outstanding awards under Long-Term Incentive Plan.......... (7,432,414) (6,377,520) Outstanding options under predecessor incentive plans...... (488,671) (548,551) ----------- ----------- Shares/options available for future grant......................... 4,306,586 3,933,384 =========== ===========
Stock option awards. The Company has a program of awarding semi-annual stock options to its officers and employees and gives its non-employee directors a choice to receive (i) 100 percent restricted stock, (ii) 100 percent stock options, (iii) 100 percent cash, or (iv) a combination of 50/50 of any two, as their annual compensation. This program provides for stock option awards at an exercise price based upon the closing sales price of the Company's common stock on the day prior to the date of grant. Employee stock option awards vest over an 18 month or three year schedule and provide a five year exercise period from each vesting date. Non-employee directors' stock options vest quarterly and provide for a five year exercise period from each vesting date. The Company granted 1,643,212; 1,627,071 and 1,439,035 options under the Long-Term Incentive Plan during 2002, 2001 and 2000, respectively. 59 PIONEER NATURAL RESOURCES COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 2002, 2001 and 2000 Restricted stock awards. During the year ended December 31, 2002, the Company issued 654,445 restricted shares of the Company's common stock. The restricted awards were issued as compensation to directors, officers and key employees of the Company. The restricted share awards include 18,545 shares that were granted to directors of the Company on May 13, 2002. Director awards for 3,302 shares vest on a quarterly pro-rata basis during the year ended May 13, 2003 and director awards for 15,243 shares vest on May 13, 2005. The remaining 635,900 restricted shares were awarded to officers and key employees of the Company on August 12, 2002 and vest on August 12, 2005. The Company recorded $16.2 million of deferred compensation in the stockholder's equity section of the accompanying Consolidated Balance Sheet associated with the restricted stock awards, which amount will be amortized to compensation expense over the vesting periods of the awards. During the year ended December 31, 2002, amortization of the restricted stock awards increased the Company's compensation expense by $1.9 million. The following table reflects the outstanding restricted stock awards and activity related thereto for 2002: For the Year Ended December 31, 2002 --------------------- Weighted Number Average of Shares Price --------- -------- Restricted Stock Awards: Restricted shares outstanding at beginning of year........ - $ - Shares granted............................................ 654,445 $ 24.72 Lapse of restrictions..................................... (1,652) $ 24.60 -------- Restricted shares outstanding at end of year................. 652,793 $ 24.72 ========
There were no restricted stock awards to directors or employees during the years ended December 31, 2001 and 2000. Other stock based plans. Prior to the formation of the Company in 1997, the Company's predecessor companies had long-term incentive plans in place that allowed the predecessor companies to grant incentive awards similar to the provisions of the Long-Term Incentive Plan. Upon formation of the Company, all awards under these plans were assumed by the Company with the provision that no additional awards be granted under the predecessor plans. SFAS 123 disclosures. The Company applies APB 25 and related interpretations in accounting for its stock option awards. Accordingly, no compensation expense has been recognized for its stock option awards. If compensation expense for the stock option awards had been determined consistent with SFAS 123, the Company's net income and net income per share would have been less than reported amounts. See Note B comparisons of net income and net income per share as reported and as adjusted for the pro forma effects of determining compensation expense in accordance with SFAS 123. Under SFAS 123, the fair value of each stock option grant is estimated on the date of grant using the Black-Scholes option pricing model with the following weighted average assumptions used for grants in 2002, 2001 and 2000: For the Year Ended December 31, ---------------------------- 2002 2001 2000 ------- ------- -------- Risk-free interest rate............. 2.80% 4.13% 5.66% Expected life....................... 5 years 5 years 5 years Expected volatility................. 45% 49% 50% Expected dividend yield............. - - -
60 PIONEER NATURAL RESOURCES COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 2002, 2001 and 2000 A summary of the Company's stock option plans as of December 31, 2002, 2001 and 2000, and changes during the years ended on those dates, are presented below: For the Year Ended For the Year Ended For the Year Ended December 31, 2002 December 31, 2001 December 31, 2000 --------------------- --------------------- --------------------- Weighted Weighted Weighted Number Average Number Average Number Average of Shares Price of Shares Price of Shares Price ---------- -------- ---------- -------- ---------- -------- Non-statutory stock options: Outstanding, beginning of year.. 6,926,071 $ 18.16 6,510,559 $ 18.10 6,241,889 $ 19.45 Options granted............... 1,643,212 $ 21.14 1,627,071 $ 18.29 1,439,035 $ 10.32 Options forfeited............. (154,717) $ 26.27 (566,189) $ 25.83 (798,058) $ 18.05 Options exercised............. (1,146,274) $ 12.19 (645,370) $ 11.14 (372,307) $ 10.78 ---------- ---------- ---------- Outstanding, end of year........ 7,268,292 $ 19.60 6,926,071 $ 18.16 6,510,559 $ 18.10 ========== ========== ========== Exercisable at end of year...... 4,269,659 $ 20.15 4,005,762 $ 20.82 3,897,187 $ 23.47 ========== ========== ========== Weighted average fair value of options granted during the year............................ $ 8.87 $ 8.65 $ 4.88 ========= ========= =========
The following table summarizes information about the Company's stock options outstanding at December 31, 2002: Options Outstanding Options Exercisable ------------------------------------------------------- -------------------------------------- Number Weighted Average Weighted Weighted Range of Outstanding at Remaining Average Number Exercisable Average Exercise Prices December 31, 2002 Contractual Life Exercise Price at December 31, 2002 Exercise Price - --------------- ----------------- ---------------- -------------- -------------------- -------------- $ 5-11 800,715 3.9 years $ 8.35 619,504 $ 8.49 $ 12-18 3,805,527 4.9 years $ 16.69 1,714,584 $ 15.42 $ 19-26 1,288,548 4.9 years $ 24.13 562,069 $ 23.44 $ 27-30 1,323,242 1.1 years $ 29.59 1,323,242 $ 29.59 $ 31-52 50,260 2.6 years $ 39.88 50,260 $ 39.88 ----------- ----------- 7,268,292 4,269,659 =========== ===========
Employee Stock Purchase Plan The Company has an Employee Stock Purchase Plan (the "ESPP") that allows eligible employees to annually purchase the Company's common stock at a discounted price. Officers of the Company are not eligible to participate in the ESPP. Contributions to the ESPP are limited to 15 percent of an employee's pay (subject to certain ESPP limits) during the nine month offering period. Participants in the ESPP purchase the Company's common stock at a price that is 15 percent below the closing sales price of the Company's common stock on either the first day or the last day of each annual offering period, whichever closing sales price is lower. NOTE H. Issuance of Common Stock During April 2002, the Company completed a public offering of 11.5 million shares of its common stock at $21.50 per share. Associated therewith, the Company received $236.0 million of net proceeds after the payment of issuance costs. The Company used the net proceeds from the public offering to fund the acquisition of the Falcon assets and associated acreage in the deepwater Gulf of Mexico and the West Panhandle gas field acquisitions. See Note D for information regarding these acquisitions. 61 PIONEER NATURAL RESOURCES COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 2002, 2001 and 2000 NOTE I. Commitments and Contingencies Severance agreements. The Company has entered into severance agreements with its officers, subsidiary company officers and certain key employees. Salaries and bonuses for the Company's officers are set by the Compensation Committee for the parent company officers and by the Management Committee for subsidiary company officers and key employees. These committees can grant increases or reductions to base salary at their discretion. The current annual salaries for the parent company officers, the subsidiary company officers and key employees covered under such agreements total approximately $18.2 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 various legal actions incidental to its business, including, but not limited to, the proceedings described below. The majority of these lawsuits primarily involve claims for damages arising from oil and gas leases and ownership interest disputes. The Company believes that the ultimate disposition of these legal actions will not have a material adverse effect on the Company's consolidated financial position, liquidity, capital resources or future results of operations. The Company will continue to evaluate its litigation matters on a quarter-by-quarter basis and will adjust its litigation reserves as appropriate to reflect the then current status of litigation. Alford. The Company is party to a 1993 class action lawsuit filed in the 26th Judicial District Court of Stevens County, Kansas by two classes of royalty owners, one for each of the Company's gathering systems connected to the Company's Satanta gas plant. The case was relatively inactive for several years. In early 2000, the plaintiffs amended their pleadings to add claims regarding the field compression installed by the Company in the 1990's. The lawsuit now has two material claims. First, the plaintiffs assert that the expenses related to the field compression are a "cost of production" for which plaintiffs cannot be charged their proportionate share under the applicable oil and gas leases. Second, the plaintiffs claim they are entitled to 100 percent of the value of the helium extracted at the Company's Satanta gas plant. If the plaintiffs were to prevail on the above two claims in their entirety, it is possible that the Company's liability could reach $25 million, plus prejudgment interest. However, the Company believes it has valid defenses to plaintiffs' claims, has paid the plaintiffs properly under their respective oil and gas leases, and intends to vigorously defend itself. The Company believes the cost of the field compression is not a "cost of production", but is rather an expense of transporting the gas to the Company's Satanta gas plant for processing, where valuable hydrocarbon liquids and helium are extracted from the gas. The plaintiffs benefit from such extractions and the Company believes that charging the plaintiffs with their proportionate share of such transportation and processing expenses is consistent with Kansas law. The Company has also vigorously defended against plaintiffs' claims to 100 percent of the value of the helium extracted, and believes that in accordance with applicable law, it has properly accounted to the plaintiffs for their fractional royalty share of the helium under the specified royalty clauses of the respective oil and gas leases. The factual evidence in the case was presented to the 26th Judicial District Court without a jury in December 2001. Oral arguments were heard by the court in April 2002, and although the court has not yet entered a judgment or findings, it could do so at any time. The Company strongly denies the existence of any material underpayment to plaintiffs and believes it presented strong evidence at trial to support its positions. The Company has not yet determined the amount of damages, if any, that would be payable if the lawsuit was determined adversely to the Company. Although the amount of any resulting liability could have a material adverse effect on the Company's results of operations for the quarterly reporting period in which such liability is recorded, the Company does not expect that any such liability will have a material adverse effect on its consolidated financial position as a whole or on its liquidity, capital resources or future annual results of operations. 62 PIONEER NATURAL RESOURCES COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 2002, 2001 and 2000 Kansas ad valorem tax. The Natural Gas Policy Act of 1978 ("NGPA") allows a "severance, production or similar" tax to be included as an add-on, over and above the maximum lawful price for gas. Based on a Federal Energy Regulatory Commission ("FERC") ruling that Kansas ad valorem tax was such a tax, one of the Company's predecessor entities collected the Kansas ad valorem tax in addition to the otherwise maximum lawful price. The FERC's ruling was appealed to the United States Court of Appeals for the District of Columbia ("D.C. Circuit"), which held in June 1988 that the FERC failed to provide a reasoned basis for its findings and remanded the case to the FERC for further consideration. On December 1, 1993, the FERC issued an order reversing its prior ruling, but limiting the effect of its decision to Kansas ad valorem taxes for sales made on or after June 28, 1988. The FERC clarified the effective date of its decision by an order dated May 18, 1994. The order clarified that the effective date applies to tax bills rendered after June 28, 1988, not sales made on or after that date. Numerous parties filed appeals on the FERC's action in the D.C. Circuit. Various gas producers challenged the FERC's orders on two grounds: (1) that the Kansas ad valorem tax, properly understood, does qualify for reimbursement under the NGPA; and (2) the FERC's ruling should, in any event, have been applied prospectively. Other parties challenged the FERC's orders on the grounds that the FERC's ruling should have been applied retroactively to December 1, 1978, the date of the enactment of the NGPA and producers should have been required to pay refunds accordingly. The D.C. Circuit issued its decision on August 2, 1996, which holds that producers must make refunds of all Kansas ad valorem tax collected with respect to production since October 4, 1983, as opposed to June 28, 1988. Petitions for rehearing were denied on November 6, 1996. Various gas producers subsequently filed a petition for writ of certiori with the United States Supreme Court seeking to limit the scope of the potential refunds to tax bills rendered on or after June 28, 1988 (the effective date originally selected by the FERC). Williams Natural Gas Company filed a cross-petition for certiori seeking to impose refund liability back to December 1, 1978. Both petitions were denied on May 12, 1997. The Company and other producers filed petitions for adjustment with the FERC on June 24, 1997. The Company was seeking waiver or set-off from FERC with respect to that portion of the refund associated with (i) non-recoupable royalties, (ii) non-recoupable Kansas property taxes based, in part, upon the higher prices collected, and (iii) interest for all periods. On September 10, 1997, FERC denied this request, and on October 10, 1997, the Company and other producers filed a request for rehearing. Pipelines were given until November 10, 1997 to file claims on refunds sought from producers and refunds totaling approximately $30.2 million were made against the Company. Through December 31, 2002, the Company has settled $21.7 million of the original claim amounts, of which $11.8 million was settled during 2002. The carrying value of the obligation settled during 2002 exceeded the settlement paid by the Company by $3.5 million. Accordingly, the Company recognized other income of $3.5 million during 2002. As of December 31, 2002 and December 31, 2001, the Company had on deposit $10.6 million and $24.5 million, respectively, including accrued interest, in an escrow account and had corresponding obligations for the remaining claims recorded in other current liabilities in the accompanying Consolidated Balance Sheets. The Company believes that the escrowed amounts, plus accrued interest, will be sufficient to settle the remaining claims. Lease agreements. The Company leases offshore production facilities, equipment and office facilities under noncancellable operating leases on which rental expense for the years ended December 31, 2002, 2001 and 2000 was approximately $6.7 million, $6.6 million and $7.0 million, respectively. Future minimum lease commitments under noncancellable operating leases at December 31, 2002 are as follows (in thousands): 2003.......................................... $ 19,364 2004.......................................... $ 41,553 2005.......................................... $ 39,375 2006.......................................... $ 32,266 2007.......................................... $ 26,258 Thereafter.................................... $ 36,338
63 PIONEER NATURAL RESOURCES COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 2002, 2001 and 2000 Transportation agreements. The Company's wholly-owned Canadian subsidiary is a party to pipeline transportation service agreements, with remaining terms of approximately 13 years, whereby it has committed to transport a specified volume of gas each year from Canada to a point in Chicago, Illinois. Such gas volumes are comprised of a significant portion of the Company's Canadian net 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 84 MMcf of gas per day during 2003 and decline to approximately 80 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 $2.6 million and $9.9 million of gas marketing losses in other expenses during 2002 and 2001, respectively. NOTE J. Derivative Financial Instruments Hedge Derivatives The Company, from time to time, uses derivative instruments to manage interest rate, commodity price and currency exchange rate risks. Fair value hedges. The Company monitors capital markets and trends to identify opportunities to enter into interest rate swaps to minimize its costs of capital. As of December 31, 2002, the Company was not a party to any fair value hedges. As of December 31, 2001, the carrying value of the Company's fair value hedges was a liability of $19.6 million. During April 2000 and May 2001, the Company entered into interest rate swap agreements to hedge the fair value of the Company's 8-7/8 percent senior notes and 8-1/4 percent senior notes, respectively. The terms of the interest rate swap agreements matched the notional amounts and scheduled maturities of the bonds; required the counterparties to pay the Company a fixed annual interest rate equal to the stated bond coupon rates on the notional amounts; and required the Company to pay the counterparties variable annual interest rates on the notional amounts equal to the periodic six-month LIBOR plus weighted average margin rates of 178.2 basis points and 238.1 basis points on the 8-7/8 percent senior notes and 8-1/4 percent senior notes; respectively. During September 2001, the Company terminated its 8-7/8 percent and 8-1/4 percent interest rate swaps for $23.3 million of cash proceeds, including accrued interest. During April 2002 the Company entered into interest rate swap agreements to hedge the fair value of the Company's 8-7/8 percent senior notes and, during November 2001, the Company entered into interest rate swap agreements to hedge the fair value of its 6-1/2 percent senior notes and 8-1/4 percent senior notes. The terms of the interest rate swap agreements matched the notional amounts and scheduled maturities of the bonds; required the counterparties to pay the Company fixed annual interest rates equal to the stated bond coupon rates on the notional amounts; and required the Company to pay the counterparties variable annual interest rates on the notional amounts equal to the periodic six-month LIBOR plus weighted average margin rates of 397 basis points, 202.2 basis points, and 337 basis points on the 8-7/8 percent senior notes, 6-1/2 percent senior notes and 8-1/4 percent senior notes; respectively. During September 2002, the Company terminated these interest rate swaps for $36.3 million of cash proceeds, including accrued interest. As of December 31, 2002, the carrying value of the Company's long-term debt in the accompanying Consolidated Balance Sheets included $35.7 million of incremental liability attributable to the unamortized deferred hedge gains realized from the terminations of the Company's fair value hedge agreements during 2002 and 2001. The amortization of these deferred hedge gains reduced the Company's reported interest expense by $14.1 million and $2.8 million during the years ended December 31, 2002 and 2001, respectively. 64 PIONEER NATURAL RESOURCES COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 2002, 2001 and 2000 The following table sets forth the scheduled amortization of deferred hedge gains on terminated fair value hedges that will be recognized as reductions in the Company's future interest expense: First Second Third Fourth Outstanding Quarter Quarter Quarter Quarter Total ------- ------- ------- ------- ----------- (in thousands) 2003 hedge gain amortization........... $ 5,937 $ 5,564 $ 4,735 $ 4,161 $ 20,397 2004 hedge gain amortization........... $ 3,518 $ 3,122 $ 2,458 $ 2,105 11,203 Remaining net gains to be amortized through 2008......................... 4,072 ------- $ 35,672 =======
The terms of the fair value hedges described above perfectly matched the terms of the underlying senior notes. Thus, the Company did not exclude any component of the derivatives' gains or losses from the measurement of hedge effectiveness. Cash flow hedges. The Company utilizes, from time to time, commodity swap and collar contracts to (i) reduce the effect of price volatility on the commodities the Company produces and sells, (ii) support the Company's annual capital budgeting and expenditure plans and (iii) reduce commodity price risk associated with certain capital projects. The Company has also utilized interest rate swap agreements to reduce the effect of interest rate volatility on the Company's variable rate line of credit indebtedness and forward currency exchange agreements to reduce the effect of U.S. dollar to Canadian dollar exchange rate volatility. Oil. All material sales contracts governing the Company's oil production have been tied directly or indirectly to the New York Mercantile Exchange prices. The following table sets forth the Company's outstanding oil hedge contracts and the weighted average NYMEX prices for those contracts as of December 31, 2002: Yearly First Second Third Fourth Outstanding Quarter Quarter Quarter Quarter Total ------- ------- ------- ------- ----------- Daily oil production: 2003 - Swap Contracts Volume (Bbl).................... 19,900 23,000 23,000 23,000 22,236 Price per Bbl................... $ 24.59 $ 24.44 $ 24.40 $ 24.40 $ 24.45 2004 - Swap Contracts Volume (Bbl).................... 14,000 14,000 14,000 14,000 14,000 Price per Bbl................... $ 23.11 $ 23.11 $ 23.11 $ 23.11 $ 23.11
The Company reports average oil prices per Bbl including the effects of oil quality adjustments and the net effect of oil hedges. The following table sets forth the Company's oil prices, both reported (including hedge results) and realized (excluding hedge results), and the net effect of settlements of oil price hedges to revenue: Year Ended December 31, ----------------------------- 2002 2001 2000 ------- ------- ------- Average price reported per Bbl...................... $ 22.89 $ 24.12 $ 24.01 Average price realized per Bbl...................... $ 22.95 $ 23.88 $ 28.81 Addition (reduction) to revenue (in millions)....... $ (.8) $ 3.0 $ (60.1)
65 PIONEER NATURAL RESOURCES COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 2002, 2001 and 2000 Natural gas liquids prices. During the years ended December 31, 2002, 2001 and 2000, the Company did not enter into any NGL hedge contracts. 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. The following table sets forth the Company's outstanding gas hedge contracts and the weighted average index prices for those contracts as of December 31, 2002: Yearly First Second Third Fourth Outstanding Quarter Quarter Quarter Quarter Average --------- --------- --------- --------- ----------- Daily gas production: 2003 - Swap Contracts Volume (Mcf)............... 230,000 230,000 230,000 230,000 230,000 Index price per MMBtu...... $ 3.76 $ 3.76 $ 3.76 $ 3.76 $ 3.76 2004 - Swap Contracts Volume (Mcf)............... 180,000 180,000 180,000 180,000 180,000 Index price per MMBtu...... $ 3.81 $ 3.81 $ 3.81 $ 3.81 $ 3.81 2005 - Swap Contracts Volume (Mcf)............... 10,000 10,000 10,000 10,000 10,000 Index price per MMBtu...... $ 3.70 $ 3.70 $ 3.70 $ 3.70 $ 3.70 2006 - Swap Contracts Volume (Mcf)............... 20,000 20,000 20,000 20,000 20,000 Index price per MMBtu...... $ 3.75 $ 3.75 $ 3.75 $ 3.75 $ 3.75 2007 - Swap Contracts Volume (Mcf)............... 20,000 20,000 20,000 20,000 20,000 Index price per MMBtu...... $ 3.75 $ 3.75 $ 3.75 $ 3.75 $ 3.75
The Company reports average gas prices per Mcf including the effects of Btu content, gas processing and shrinkage adjustments and the net effect of gas hedges. The following table sets forth the Company's gas prices, both reported (including hedge results) and realized (excluding hedge results), and the net effect of settlements of gas price hedges to revenue: Year Ended December 31, ---------------------------- 2002 2001 2000 ------ ------ ------ Average price reported per Mcf...................... $ 2.49 $ 3.23 $ 2.81 Average price realized per Mcf...................... $ 2.38 $ 3.20 $ 3.03 Addition/(reduction) to revenue (in millions)....... $ 13.6 $ 3.0 $(29.0)
Interest rates. During the year ended December 31, 2001, the Company entered into interest rate swap agreements and designated the swap agreements as being cash flow hedges of the interest rate volatility associated with a portion of the Company's variable rate line of credit indebtedness. The terms of the interest rate swap agreements provided for an aggregate notional amount of $55 million of debt; commenced on May 21, 2001 and matured on May 20, 2002; required the counterparties to pay the Company a variable rate equal to the periodic six-month LIBOR plus 125 basis points; and, required the Company to pay the counterparties a weighted average annual rate of 5.43 percent on the notional amount. The Company recognized interest expense of $447 thousand and $185 thousand associated with these interest rate swap agreements during the years ended December 31, 2002 and 2001, respectively. The Company recognized no ineffectiveness associated with changes in the fair values of these derivative instruments. 66 PIONEER NATURAL RESOURCES COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 2002, 2001 and 2000 Foreign currency rates. During 2001, the Company entered into forward agreements to exchange an aggregate $24.8 million U.S. dollars for Canadian dollars at a weighted average exchange rate of .6266 U.S. dollars for 1.0 Canadian dollar. These agreements were designated as hedges of the Company's exchange rate risk associated with Canadian sales of gas under U.S. dollar denominated sales agreements. The Company recognized settlement gains of $249 thousand associated with these forward agreements during the year ended December 31, 2002, which increased the Company's reported gas price. The Company did not recognize any ineffectiveness associated with changes in the fair values of these derivative instruments. Except for one forward agreement that represented an asset of $15 thousand to the Company on December 31, 2002, these agreements matured during the year ended December 31, 2002. Hedge ineffectiveness and excluded items. During the years ended December 31, 2002 and 2001, the Company recognized other expense of $1.7 million and $9.1 million, respectively, related to the ineffective portions of its cash flow hedging instruments. Additionally, based on SFAS 133 interpretive guidance that was in effect prior to April 2001, the Company excluded from the measurement of hedge effectiveness changes in the time and volatility value components of collar contracts designated as cash flow hedges. Associated therewith, the Company recorded other expense of $2.4 million during the three month period ended March 31, 2001. In April 2001, the Company discontinued the exclusion of time value and volatility from the measurement of hedge effectiveness. Accumulated other comprehensive income - deferred hedge gains and losses, net. As described in Note B, the Company records the effective portions of deferred cash flow hedge gains and losses in AOCI - deferred hedge gains, net. Once the underlying hedged transaction occurs the deferred hedge gain or loss is reclassified from AOCI - deferred hedge gains, net to earnings. If it is determined that the underlying hedged transaction is not likely to occur, the deferred hedge gain or loss is reclassified from AOCI - deferred hedge gains, net to other income or other expense during the period in which it is determined that the underlying hedged transaction is not likely to occur. As of December 31, 2002 and 2001, AOCI - deferred hedge gains, net represented net deferred gains of $9.6 million and $201.0 million, respectively. The AOCI - deferred hedge gains, net balance as of December 31, 2002 was comprised of $107.8 million of unrealized deferred hedge losses on the effective portions of open commodity cash flow hedges and $117.4 million of net deferred gains on terminated cash flow hedges. The AOCI - deferred hedge gains, net balance as of December 31, 2001 was comprised of $177.7 million of unrealized deferred gains on the effective portions of open commodity, interest rate and forward currency rate cash flow hedges and $23.3 million of net deferred gains on terminated cash flow hedges. The decrease in AOCI - deferred hedge gains, net during the year ended December 31, 2002 was primarily attributable to increases in future commodity prices relative to the commodity prices stipulated in the hedge agreements and the reclassification of deferred hedge gains to net income as derivatives matured by their terms. The unrealized deferred hedge gains and 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 agreements or terminated prior to settlement. The net deferred gains and losses on terminated cash flow hedges are fixed. During the twelve month period ending December 31, 2003, the Company expects to reclassify $73.6 million of net deferred losses associated with open cash flow hedges and $72.1 million of net deferred gains on terminated cash flow hedges from AOCI - deferred hedge gains, net to oil and gas revenue. The following table sets forth the scheduled reclassifications of deferred hedge gains on terminated cash flow hedges that will be recognized in the Company's future oil and gas revenues: First Second Third Fourth Total Quarter Quarter Quarter Quarter Year -------- --------- -------- -------- --------- (in thousands) 2003 deferred hedge gains......... $ 18,123 $ 18,043 $ 18,021 $ 17,864 $ 72,051 2004 deferred hedge gains......... $ 11,206 $ 11,156 $ 11,226 $ 11,175 44,763 2005 deferred hedge gains......... $ 149 $ 153 $ 156 $ 158 616 -------- $ 117,430 ========
67 PIONEER NATURAL RESOURCES COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 2002, 2001 and 2000 Non-hedge Derivatives Btu swap agreements. The Company is a party to Btu swap agreements that mature at the end of 2004. The Btu swap agreements do not qualify for hedge accounting treatment. The Company recorded mark-to-market adjustments to decrease the carrying value of the Btu swap liability by $.7 million during the year ended December 31, 2001 and to increase the carrying value of the Btu swap liability by $14.6 million during the year ended December 31, 2000. During the year ended December 31, 2001, the Company entered into offsetting Btu swap agreements that fixed the Company's remaining obligations associated with the Btu swap agreements. The undiscounted future settlement obligations of the Company under the Btu swap agreements are $7.2 million per year for each of 2003 and 2004. Foreign currency agreements. Prior to their maturity in 2000, the Company was a party to a series of forward foreign exchange rate swap agreements that exchanged Canadian dollars for U.S. dollars. These contracts did not qualify as hedges. The Company recorded a mark-to-market adjustment to increase the carrying value of the foreign exchange swap liabilities by $1.9 million during the year ended December 31, 2000. Other non-hedge commodity derivatives. During the year ended December 31, 1999, the Company sold call options that provided the counterparties an option to exercise calls either on 10,000 Bbls per day of oil, at a strike price of $20.00 per Bbl, or on 100,000 MMBtu per day of gas, at a weighted average strike price of $2.75 per MMBtu. These contracts, which matured during the year ended December 31, 2000, did not qualify for hedge accounting treatment. The Company recorded mark-to-market adjustments to increase the carrying value of the associated contract liability by $42.0 million during the year ended December 31, 2000. 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. 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 customers individually accounted for 10 percent or more of the consolidated oil, NGL and gas revenues of the Company during one or more of the years ended December 31, 2002, 2001 and 2000: Percentage of Consolidated Oil, NGL and Gas Revenues --------------------------------- 2002 2001 2000 -------- -------- -------- Williams Energy Services............. 7 11 13 Anadarko Petroleum Corporation....... 7 10 6 At December 31, 2002, the amounts receivable from Williams Energy Services and Anadarko Petroleum Corporation were $13.4 million and $11.7 million, respectively, which are included in the caption "Accounts receivable - trade" in the accompanying Consolidated Balance Sheet. 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, 2002 and 2001, the Company has $7.6 million of derivative assets for which Enron North America Corp was the Company's counterparty. Associated therewith, the Company recognized bad debt expense of $.4 million and $6.0 million during the years ended December 31, 2002 and 2001, respectively, which amounts are included in other expense in the accompanying Consolidated Statements of Operations. 68 PIONEER NATURAL RESOURCES COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 2002, 2001 and 2000 NOTE L. Interest and Other Income The Company recorded interest and other income of $11.2 million, $21.8 million and $25.8 million during the years ended December 31, 2002, 2001 and 2000. The major categories of the Company's interest and other income are summarized in the following table: Year Ended December 31, -------------------------------- 2002 2001 2000 -------- -------- -------- (in thousands) Kansas ad valorem escrow adjustments (see Note I)...... $ 3,500 $ 1,100 $ 1,000 Excise tax income...................................... 2,398 4,126 6,915 Production payment income.............................. - 5,552 1,262 Interest income........................................ 642 2,128 3,906 Seismic data sales..................................... 87 1,841 1,148 Foreign exchange gains................................. 142 223 220 Other income........................................... 4,453 6,808 11,324 ------- ------- ------- $ 11,222 $ 21,778 $ 25,775 ======= ======= =======
NOTE M. Asset Divestitures During the years ended December 31, 2002, 2001 and 2000, the Company completed asset divestitures for net proceeds of $118.9 million, $113.5 million and $102.7 million, respectively. Associated therewith, the Company recorded gains on disposition of assets of $4.4 million, $7.7 million and $34.2 million during the years ended December 31, 2002, 2001 and 2000, respectively. Hedge derivative divestitures. During the years ended December 31, 2002 and 2001, the Company terminated, prior to their scheduled maturity, hedge derivatives for cash sales proceeds of $91.3 million and $85.4 million, respectively. Net gains from these divestitures were deferred and are being amortized over the original contract lives of the terminated derivatives as reductions to interest expense or increases to oil and gas revenues. See Note J for more information regarding deferred gains on terminated hedge derivatives. Available for sale securities divestitures. During the year ended December 31, 2000, the Company sold 3,370,982 shares of common stock of a non-affiliated entity for $59.7 million, recording an associated gain on disposition of assets of $34.3 million. During 2001, the Company sold its remaining 613,250 shares of the non-affiliated entity for $12.7 million of cash proceeds and recognized an associated gain on disposition of assets of $8.1 million. Other United States divestitures. During the year ended December 31, 2002, the Company received $20.9 million of proceeds from the cash settlement of a gas balancing receivable, $4.7 million from the sale of certain gas properties located in Oklahoma and $1.8 million from the sale of other corporate assets. Associated with these divestitures, the Company recorded net gains of $4.2 million. During the year ended December 31, 2001, the Company sold other corporate assets for $3.0 million of proceeds. Associated with the sale of these assets, the Company recorded a net gain of $.4 million. During the year ended December 31, 2000, the Company sold an office building in Midland, Texas, certain other assets and non-strategic oil and gas properties primarily located in the United States Gulf Coast and Mid Continent areas. Associated with these divestitures, the Company realized net divestment proceeds of $43.0 million and recorded a net loss on disposition of assets of $.4 million. Other international divestitures. During the year ended December 31, 2002, other Canadian and Argentine corporate assets were sold for $.2 million. The Company recorded $.2 million of net gains associated with those 69 PIONEER NATURAL RESOURCES COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 2002, 2001 and 2000 divestitures. During the year ended December 31, 2001, the Company received $12.0 million of proceeds from the sale of certain oil properties in Canada and $.4 million of proceeds from the sale of other international assets. Associated with these transactions, the Company recognized a net loss of $.8 million. NOTE N. Other Expense The following table provides the components of the Company's other expense during the years ended December 31, 2002, 2001 and 2000: Years Ended December 31, -------------------------------- 2002 2001 2000 -------- -------- -------- (in thousands) Derivative ineffectiveness and mark-to-market provisions (see Note J)................................ $ 1,664 $ 11,458 $ 58,518 Gas marketing losses (see Note I)......................... 2,556 9,850 - Foreign currency remeasurement and exchange losses (a).... 7,623 8,474 80 Bad debt expense (see Note K)............................. 129 6,152 65 Other charges............................................. 5,284 3,654 8,568 ------- ------- ------- $ 17,256 $ 39,588 $ 67,231 ======= ======= ======= - ---------- (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. In early January 2002, the Argentine government severed the one-to-one relationship between the value of the Argentine peso and the U.S. dollar, which is the functional currency of the Company's Argentine operations. Consequently, the Company has remeasured its Argentine peso-denominated monetary net assets as of December 31, 2002 and 2001 and adjusted its lease and well equipment inventory balances to market values as of December 31, 2001. Associated therewith, the Company recognized charges of $6.9 million and $7.7 million during 2002 and 2001, respectively.
NOTE O. Income Taxes The Company accounts for income taxes in accordance with the provisions of Statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes". 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 and foreign taxing authorities. Current and estimated tax payments of $2.3 million, $11.7 million and $4.6 million were made during the years ended December 31, 2002, 2001 and 2000, respectively. During the years ended December 31, 2002, 2001 and 2000, the Company's income tax provision (benefit) and amounts separately allocated were attributable to the following items: Year Ended December 31, -------------------------------- 2002 2001 2000 -------- -------- -------- (in thousands) Income (loss) before extraordinary items....... $ 5,063 $ 4,016 $ (6,000) Changes in other comprehensive income: Deferred hedge gains and losses.............. (2,561) 2,293 - Cumulative translation adjustment............ (20) (121) (200) ------- ------- ------- $ 2,482 $ 6,188 $ (6,200) ======= ======= =======
70 PIONEER NATURAL RESOURCES COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 2002, 2001 and 2000 Income tax provision (benefit) attributable to income (loss) before extraordinary items consists of the following: Year Ended December 31, ----------------------------------- 2002 2001 2000 --------- --------- --------- (in thousands) Current: U.S. state and local................ $ 209 $ 1,080 $ - Foreign............................. 2,066 10,585 4,600 -------- -------- -------- 2,275 11,665 4,600 -------- -------- -------- Deferred: Foreign............................. 2,788 (7,649) (10,600) -------- -------- -------- Total................................. $ 5,063 $ 4,016 $ (6,000) ======== ======== ========
Income (loss) before income taxes and extraordinary items consists of the following: Year Ended December 31, ----------------------------------- 2002 2001 2000 --------- --------- --------- (in thousands) Income (loss) before income taxes and extraordinary items: U.S. federal........................ $ 58,821 $ 140,045 $ 138,941 Foreign............................. (4,699) (32,280) 19,558 -------- -------- -------- $ 54,122 $ 107,765 $ 158,499 ======== ======== ========
Reconciliations of the United States federal statutory rate to the Company's effective rate for income (loss) before extraordinary items are as follows: 2002 2001 2000 ------- ------ ------ U.S. federal statutory tax rate....... 35.0 35.0 35.0 Valuation allowance................... (23.7) (27.5) (30.9) Rate differential on foreign operations........................... (.1) (3.2) (2.9) Other................................. (1.8) (.6) (5.0) ------- ------ ------ Consolidated effective tax rate....... 9.4 3.7 (3.8) ======= ====== ======
The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities are as follows: December 31, ---------------------- 2002 2001 --------- --------- (in thousands) Deferred tax assets: Net operating loss carryforwards..................... $ 299,495 $ 341,206 Alternative minimum tax credit carryforwards......... 1,565 1,565 Other................................................ 143,894 44,745 -------- -------- Total deferred tax assets.......................... 444,954 387,516 Valuation allowance.................................. (277,217) (183,122) -------- -------- Net deferred tax assets............................ 167,737 204,394 -------- -------- Deferred tax liabilities: Oil and gas properties, principally due to differences in basis, depletion and the deduction of intangible drilling costs for tax purposes................................... 80,364 115,524 Other................................................ 5,393 11,919 -------- -------- Total deferred tax liabilities..................... 85,757 127,443 -------- -------- Net deferred tax asset............................. $ 81,980 $ 76,951 ======== ========
71 PIONEER NATURAL RESOURCES COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 2002, 2001 and 2000 Realization of deferred tax assets associated with net operating loss carryforwards ("NOLs") and other credit carryforwards is dependent upon generating sufficient taxable income prior to their expiration. The Company believes that there is a risk that certain of these NOLs and other credit carryforwards may expire unused and, accordingly, has a valuation allowance of $277.2 million against the carryforwards at December 31, 2002. Although realization is not assured for the remaining deferred tax asset, the Company believes it is more likely than not that they will be realized through future taxable earnings or alternative tax planning strategies. However, the net deferred tax assets could be reduced further if the Company's estimate of taxable income in future periods is significantly reduced or alternative tax planning strategies are no longer viable. At December 31, 2002, the Company had NOLs for United States, Canadian, South African, Gabonese and Tunisian income tax purposes of $742.7 million, $37.4 million, $40.3 million, $13.4 million and $8.7 million, respectively, which are available to offset future regular taxable income in each respective tax jurisdiction, if any. Additionally, at December 31, 2002, the Company has alternative minimum tax net operating loss carryforwards ("AMT NOLs") in the United States of $637.5 million, which are available to reduce future alternative minimum taxable income, if any. These carryforwards expire as follows: U.S. ---------------------- Canada South Africa Gabon Tunisia Expiration Date NOL AMT NOL NOL NOL NOL NOL --------------- --------- --------- -------- --------- --------- -------- (in thousands) December 31, 2005...... $ - $ - $ 31,637 $ - $ - $ - December 31, 2006...... - - 5,738 - - - December 31, 2007...... 13,320 - - - - - December 31, 2008...... 112,508 104,574 - - - - December 31, 2009...... 129,226 102,727 - - - - December 31, 2010...... 124,859 110,961 - - - - December 31, 2011...... 6,521 4,045 - - - - December 31, 2012...... 68,334 58,723 - - - - December 31, 2018...... 127,656 98,290 - - - - December 31, 2019...... 145,999 144,837 - - - - December 31, 2020...... 14,235 13,297 - - - - Indefinite............. - - - 40,304 13,397 8,712 -------- -------- ------- -------- -------- ------- Total............... $ 742,658 $ 637,454 $ 37,375 $ 40,304 $ 13,397 $ 8,712 ======== ======== ======= ======== ======== =======
The Company believes $160.0 million of the U.S. NOLs and AMT NOLs are subject to Section 382 of the Internal Revenue Code and are limited in each taxable year to approximately $20.0 million. NOTE P. Geographic Operating Segment Information The Company has operations in only one industry segment, that being the oil and gas exploration and production industry; however, the Company is organizationally structured along geographic operating segments, or regions. The Company has reportable operations in the United States, Argentina and Canada. Other foreign is primarily comprised of operations in South Africa, Gabon and Tunisia. The following table provides the geographic operating segment data required by Statement of Financial Accounting Standards No. 131, "Disclosure about Segments of an Enterprise and Related Information", as well as results of operations of oil and gas producing activities required by Statement of Financial Accounting Standards No. 69, "Disclosures about Oil and Gas Producing Activities". 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 and Other" table column includes revenues, expenses, additions to properties, plants and equipment and assets that are not routinely included in the earnings measures or attributes internally reported to management on a geographic operating segment basis. 72 PIONEER NATURAL RESOURCES COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 2002, 2001 and 2000 United Other Headquarters Consolidated States Argentina Canada Foreign and Other Total ---------- --------- --------- --------- ------------ ------------ (in thousands) Year Ended December 31, 2002: Oil and gas revenues..................... $ 573,289 $ 77,615 $ 50,876 $ - $ - $ 701,780 Interest and other....................... - - - - 11,222 11,222 Gain (loss) on disposition of assets..... 3,248 (3) 995 - 192 4,432 --------- -------- -------- -------- ---------- --------- 576,537 77,612 51,871 - 11,414 717,434 --------- -------- -------- -------- ---------- --------- Production costs......................... 174,929 13,870 10,771 - - 199,570 Depletion, depreciation and amortization. 140,107 39,659 27,857 - 8,752 216,375 Exploration and abandonments............. 62,955 10,306 5,841 6,792 - 85,894 General and administrative............... - - - - 48,402 48,402 Interest................................. - - - - 95,815 95,815 Other.................................... - - - - 17,256 17,256 --------- -------- -------- -------- ---------- --------- 377,991 63,835 44,469 6,792 170,225 663,312 --------- -------- -------- -------- ---------- --------- Income (loss) before income taxes and extraordinary items.................... 198,546 13,777 7,402 (6,792) (158,811) 54,122 Income tax benefit (provision)........... (69,491) (4,822) (3,118) 2,377 69,991 (5,063) --------- -------- -------- -------- ---------- --------- Income (loss) before extraordinary items. $ 129,055 $ 8,955 $ 4,284 $ (4,415) $ (88,820) $ 49,059 ========= ======== ======== ======== ========== ========= Cost incurred for long-lived assets...... $ 533,560 $ 35,121 $ 33,506 $ 70,268 $ - $ 672,455 ========= ======== ======== ======== ========== ========= Segment assets (as of December 31)....... $2,375,505 $ 680,063 $ 176,110 $ 118,070 $ 105,368 $3,455,116 ========= ======== ======== ======== ========== ========= Year Ended December 31, 2001: Oil and gas revenues..................... $ 649,635 $ 130,241 $ 67,146 $ - $ - $ 847,022 Interest and other....................... - - - - 21,778 21,778 Gain (loss) on disposition of assets..... 224 - (1,339) - 8,796 7,681 --------- -------- -------- -------- ---------- --------- 649,859 130,241 65,807 - 30,574 876,481 --------- -------- -------- -------- ---------- --------- Production costs......................... 170,578 26,614 12,472 - - 209,664 Depletion, depreciation and amortization. 128,477 51,391 28,868 - 13,896 222,632 Exploration and abandonments............. 70,049 23,857 9,882 24,118 - 127,906 General and administrative............... - - - - 36,968 36,968 Interest................................. - - - - 131,958 131,958 Other.................................... - - - - 39,588 39,588 --------- -------- -------- -------- ---------- --------- 369,104 101,862 51,222 24,118 222,410 768,716 --------- -------- -------- -------- ---------- --------- Income (loss) before income taxes and extraordinary items.................... 280,755 28,379 14,585 (24,118) (191,836) 107,765 Income tax benefit (provision)........... (98,264) (9,933) (6,216) 8,441 101,956 (4,016) --------- -------- -------- -------- ---------- --------- Income (loss) before extraordinary items. $ 182,491 $ 18,446 $ 8,369 $ (15,677) $ (89,880) $ 103,749 ========= ======== ======== ======== ========== ========= Cost incurred for long-lived assets...... $ 454,229 $ 98,311 $ 36,048 $ 57,972 $ - $ 646,560 ========= ======== ======== ======== ========== ========= Segment assets (as of December 31)....... $2,212,540 $ 710,702 $ 187,841 $ 53,314 $ 106,656 $3,271,053 ========= ======== ======== ======== ========== ========= Year Ended December 31, 2000: Oil and gas revenues..................... $ 649,273 $ 140,990 $ 62,475 $ - $ - $ 852,738 Interest and other....................... - - - - 25,775 25,775 Gain on disposition of assets............ 4,690 - 335 - 29,159 34,184 --------- -------- -------- -------- ---------- --------- 653,963 140,990 62,810 - 54,934 912,697 --------- -------- -------- -------- ---------- --------- Production costs......................... 155,075 24,417 9,773 - - 189,265 Depletion, depreciation and amortization. 121,932 52,141 25,132 - 15,733 214,938 Exploration and abandonments............. 40,867 25,388 5,131 16,164 - 87,550 General and administrative............... - - - - 33,262 33,262 Interest................................. - - - - 161,952 161,952 Other.................................... - - - - 67,231 67,231 --------- -------- -------- -------- ---------- --------- 317,874 101,946 40,036 16,164 278,178 754,198 --------- -------- -------- -------- ---------- --------- Income (loss) before income taxes and extraordinary item..................... 336,089 39,044 22,774 (16,164) (223,244) 158,499 Income tax benefit (provision)........... (117,631) (13,665) (10,162) 5,657 141,801 6,000 --------- -------- -------- -------- ---------- --------- Income (loss) before extraordinary item.. $ 218,458 $ 25,379 $ 12,612 $ (10,507) $ (81,443) $ 164,499 ========= ======== ======== ======== ========== ========= Cost incurred for long-lived assets...... $ 204,122 $ 68,430 $ 43,591 $ 23,597 $ - $ 339,740 ========= ======== ======== ======== ========== ========= Segment assets (as of December 31)....... $1,899,633 $ 702,868 $ 227,250 $ 16,552 $ 108,132 $2,954,435 ========= ======== ======== ======== ========== =========
73 PIONEER NATURAL RESOURCES COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 2002, 2001 and 2000 NOTE Q. Income Per Share Before Extraordinary Items Basic income per share before extraordinary items is computed by dividing income before extraordinary items by the weighted average number of common shares outstanding for the period. The computation of diluted income per share before extraordinary items reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock or resulted in the issuance of common stock that would then share in the earnings of the Company. The following table is a reconciliation of the basic and diluted weighted average common shares outstanding for the years ended December 31, 2002, 2001 and 2000: Year Ended December 31, -------------------------------- 2002 2001 2000 -------- -------- -------- (in thousands) Weighted average common shares outstanding: Basic......................................... 112,542 98,529 99,378 Dilutive common stock options (a)............. 1,725 1,185 385 Restricted stock awards (b)................... 21 - - -------- -------- -------- Diluted....................................... 114,288 99,714 99,763 ======== ======== ======== - --------------- (a) Common stock options to purchase 1,925,743 shares, 3,595,880 shares and 4,911,749 shares of common stock were outstanding but not included in the computations of diluted net income per share for 2002, 2001 and 2000, respectively, because the exercise prices of the options were greater than the average market price of the common shares and would be anti-dilutive to the computations. (b) During the year ended December 31, 2002, the Company issued 654,445 restricted shares of the Company's common stock. The restricted shares were issued as compensation to directors, officers and key employees of the Company. The restricted shares include 18,545 shares that were granted to directors of the Company on May 13, 2002. Director awards for 3,302 shares vest on a quarterly pro-rata basis during the year ended May 13, 2003, and director awards for 15,243 shares vest on May 13, 2005. The remaining 635,900 restricted shares were awarded to officers and key employees of the Company on August 12, 2002 and vest on August 12, 2005.
NOTE R. Pioneer USA Pioneer USA is a wholly-owned subsidiary of the Company that has fully and unconditionally guaranteed certain debt securities of the Company (see Note E above). The Company has not prepared financial statements and related disclosures for Pioneer USA under separate cover because management of the Company has determined that such information is not material to investors. In accordance with practices accepted by the United States Securities and Exchange Commission, the Company has prepared Consolidating Condensed Financial Statements in order to quantify the assets of Pioneer USA as a subsidiary guarantor. The following Consolidating Condensed Balance Sheets as of December 31, 2002 and 2001, and Consolidating Statements of Operations and Comprehensive Income (Loss) and Consolidating Condensed Statements of Cash Flows for the years ended December 31, 2002, 2001 and 2000 present financial information for Pioneer Natural Resources Company as the Parent on a stand-alone basis (carrying any investments in subsidiaries under the equity method), financial information for Pioneer USA on a stand-alone basis (carrying any investment in non-guarantor subsidiaries under the equity method), financial information for the non- guarantor subsidiaries of the Company on a consolidated basis, the consolidation and elimination entries necessary to arrive at the information for the Company on a consolidated basis, and the financial information for the Company on a consolidated basis. Pioneer USA is not restricted from making distributions to the Company. 74 PIONEER NATURAL RESOURCES COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 2002, 2001 and 2000 CONSOLIDATING CONDENSED BALANCE SHEET As of December 31, 2002 Pioneer Natural Resources Non- Company Pioneer Guarantor The (Parent) USA Subsidiaries Eliminations Company ----------- ----------- ------------ ------------ ----------- (in thousands) ASSETS Current assets: Cash and cash equivalents............... $ 6 $ 1,783 $ 6,701 $ $ 8,490 Other current assets.................... 1,727,828 (1,480,657) (108,568) 138,603 ---------- ---------- --------- ---------- Total current assets................ 1,727,834 (1,478,874) (101,867) 147,093 ---------- ---------- --------- ---------- Property, plant and equipment, at cost: Oil and gas properties, using the successful efforts method of accounting: Proved properties..................... - 3,024,845 1,228,052 4,252,897 Unproved properties................... - 43,969 175,104 219,073 Accumulated depletion, depreciation and amortization...................... - (947,091) (356,450) (1,303,541) ---------- ---------- --------- ---------- - 2,121,723 1,046,706 3,168,429 ---------- ---------- ---------- ---------- Deferred income taxes..................... 75,311 - 1,529 76,840 Other property and equipment, net......... - 19,000 3,784 22,784 Other assets, net......................... 16,067 14,231 9,672 39,970 Investment in subsidiaries................ 1,247,042 136,159 - (1,383,201) - ---------- ---------- --------- ---------- $ 3,066,254 $ 812,239 $ 959,824 $ 3,455,116 ========== ========== ========= ========== LIABILITIES AND STOCKHOLDERS' EQUITY Total current liabilities................. $ 30,785 $ 216,065 $ 27,742 $ $ 274,592 Long-term debt, less current maturities... 1,668,536 - - 1,668,536 Other noncurrent liabilities.............. - 147,970 (19,639) 128,331 Deferred income taxes..................... - - 8,760 8,760 Stockholders' equity...................... 1,366,933 448,204 942,961 (1,383,201) 1,374,897 Commitments and contingencies............. - - - - ---------- ---------- --------- ---------- $ 3,066,254 $ 812,239 $ 959,824 $ 3,455,116 ========== ========== ========= ==========
CONSOLIDATING CONDENSED BALANCE SHEET As of December 31, 2001 Pioneer Natural Resources Non- Company Pioneer Guarantor The (Parent) USA Subsidiaries Eliminations Company ----------- ----------- ------------ ------------ ----------- (in thousands) ASSETS Current assets: Cash and cash equivalents............... $ 79 $ 10,900 $ 3,355 $ $ 14,334 Other current assets.................... 1,540,985 (1,125,968) (173,708) 241,309 ---------- ---------- --------- ---------- Total current assets................ 1,541,064 (1,115,068) (170,353) 255,643 ---------- ---------- --------- ---------- Property, plant and equipment, at cost: Oil and gas properties, using the successful efforts method of accounting: Proved properties..................... - 2,688,962 1,002,821 3,691,783 Unproved properties................... - 25,222 162,563 187,785 Accumulated depletion, depreciation and amortization...................... - (815,323) (279,987) (1,095,310) ---------- ---------- --------- ---------- - 1,898,861 885,397 2,784,258 ---------- ---------- --------- ---------- Deferred income taxes..................... 82,811 - 1,508 84,319 Other property and equipment, net......... - 17,881 3,679 21,560 Other assets, net......................... 15,911 81,356 28,006 125,273 Investment in subsidiaries................ 1,060,457 87,636 - (1,148,093) - ---------- ---------- --------- ---------- $ 2,700,243 $ 970,666 $ 748,237 $ 3,271,053 ========== ========== ========= ========== LIABILITIES AND STOCKHOLDERS' EQUITY Total current liabilities................. $ 30,745 $ 176,442 $ 21,022 $ $ 228,209 Long-term debt, less current maturities... 1,577,304 - - 1,577,304 Other noncurrent liabilities.............. 19,582 124,552 22,249 166,383 Deferred income taxes..................... - - 13,768 13,768 Stockholders' equity...................... 1,072,612 669,672 691,198 (1,148,093) 1,285,389 Commitments and contingencies............. - - - - ---------- ---------- --------- ---------- $ 2,700,243 $ 970,666 $ 748,237 $ 3,271,053 ========== ========== ========= ==========
75 PIONEER NATURAL RESOURCES COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 2002, 2001 and 2000 CONSOLIDATING CONDENSED STATEMENT OF OPERATIONS AND COMPREHENSIVE LOSS For the Year Ended December 31, 2002 (in thousands) Pioneer Natural Resources Non- Consolidated Company Pioneer Guarantor Income Tax The (Parent) USA Subsidiaries Provision Eliminations Company --------- --------- ------------ ------------ ------------ --------- Revenues and other income: Oil and gas........................... $ - $ 527,189 $ 174,591 $ - $ $ 701,780 Interest and other.................... - 8,214 3,008 - 11,222 Gain on disposition of assets, net.... - 3,230 1,202 - 4,432 -------- -------- -------- --------- -------- - 538,633 178,801 - 717,434 -------- -------- -------- --------- -------- Costs and expenses: Oil and gas production................ - 165,669 33,901 - 199,570 Depletion, depreciation and amortization......................... - 139,822 76,553 - 216,375 Exploration and abandonments.......... - 62,982 22,912 - 85,894 General and administrative............ 1,323 37,723 9,356 - 48,402 Interest.............................. 17,451 76,820 1,544 - 95,815 Equity (income) loss from subsidiary.. (52,580) 8,374 - - 44,206 - Other................................. 405 4,879 11,972 - 17,256 -------- -------- -------- --------- -------- (33,401) 496,269 156,238 - 663,312 -------- -------- -------- --------- -------- Income before income taxes.............. 33,401 42,364 22,563 - 54,122 Income tax provision.................... - - (5,063) - (5,063) -------- -------- -------- --------- -------- Income before extraordinary items....... 33,401 42,364 17,500 - 49,059 Extraordinary items - loss on early extinguishment of debt................ (6,688) - (15,658) - (22,346) -------- -------- -------- --------- -------- Net income.............................. 26,713 42,364 1,842 - 26,713 Other comprehensive income (loss): Deferred hedge gains, net: Deferred hedge losses............... (4) (156,396) (22,667) - (179,067) Net (gains) losses included in net income............................ 447 (10,352) (2,519) - (12,424) Translation adjustment................ - - 2,188 - 2,188 -------- -------- -------- --------- -------- Comprehensive income (loss)............. $ 27,156 $(124,384) $ (21,156) $ - $(162,590) ======== ======== ======== ========= ========
76 PIONEER NATURAL RESOURCES COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 2002, 2001 and 2000 CONSOLIDATING CONDENSED STATEMENT OF OPERATIONS AND COMPREHENSIVE INCOME For the Year Ended December 31, 2001 (in thousands) Pioneer Natural Resources Non- Consolidated Company Pioneer Guarantor Income Tax The (Parent) USA Subsidiaries Provision Eliminations Company --------- --------- ------------ ------------ ------------ --------- Revenues and other income: Oil and gas........................... $ - $ 626,964 $ 220,058 $ - $ $ 847,022 Interest and other.................... 368 14,415 6,995 - 21,778 Gain (loss) on disposition of assets, net......................... - 8,524 (843) - 7,681 -------- ---------- -------- --------- -------- 368 649,903 226,210 - 876,481 -------- -------- -------- -------- -------- Costs and expenses: Oil and gas production................ - 168,287 41,377 - 209,664 Depletion, depreciation and amortization........................ - 135,838 86,794 - 222,632 Exploration and abandonments.......... - 73,649 54,257 - 127,906 General and administrative............ 804 25,476 10,688 - 36,968 Interest.............................. 31,261 83,473 17,224 - 131,958 Equity (income) loss from subsidiary.. (135,459) 5,588 - - 129,871 - Other................................. - 9,247 30,341 - 39,588 -------- -------- -------- -------- -------- (103,394) 501,558 240,681 - 768,716 -------- -------- -------- -------- -------- Income (loss) before income taxes....... 103,762 148,345 (14,471) - 107,765 Income tax provision.................... - (783) (3,220) (13) (4,016) -------- -------- -------- -------- -------- Income (loss) before extraordinary items................................. 103,762 147,562 (17,691) (13) 103,749 Extraordinary items - loss on early extinguishment of debt................ (3,753) - - - (3,753) -------- -------- -------- -------- -------- Net income (loss)....................... 100,009 147,562 (17,691) (13) 99,996 Other comprehensive income: Deferred hedge gains, net: Transition adjustment............... - (172,007) (25,437) - (197,444) Deferred hedge gains (losses)....... (578) 364,051 29,531 - 393,004 Net (gains) losses included in net income............................ 135 (8,595) 13,946 - 5,486 Gains and losses on available for sale securities: Unrealized holdings losses.......... - (45) - - (45) Gains included in net income........ - (8,109) - - (8,109) Translation adjustment................ - - (11,173) - (11,173) -------- -------- -------- -------- -------- Comprehensive income.................... $ 99,566 $ 322,857 $ (10,824) $ (13) $ 281,715 ======== ======== ======== ======== ========
77 PIONEER NATURAL RESOURCES COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 2002, 2001 and 2000 CONSOLIDATING CONDENSED STATEMENT OF OPERATIONS AND COMPREHENSIVE INCOME For the Year Ended December 31, 2000 (in thousands) Pioneer Natural Resources Non- Consolidated Company Pioneer Guarantor Income Tax The (Parent) USA Subsidiaries Provision Eliminations Company --------- --------- ------------ ------------ ------------ --------- Revenues and other income: Oil and gas........................... $ - $ 616,030 $ 236,708 $ - $ $ 852,738 Interest and other.................... 29 13,808 11,938 - 25,775 Gain (loss) on disposition of assets, net.......................... (6,172) 36,946 3,410 - 34,184 -------- ---------- -------- --------- -------- (6,143) 666,784 252,056 - 912,697 -------- -------- -------- --------- -------- Costs and expenses: Oil and gas production................ - 150,281 38,984 - 189,265 Depletion, depreciation and amortization......................... - 129,996 84,942 - 214,938 Exploration and abandonments.......... - 43,938 43,612 - 87,550 General and administrative............ 283 22,519 10,460 - 33,262 Interest.............................. (53,180) 151,026 64,106 - 161,952 Equity (income) loss from subsidiary.. (117,704) (6,313) - - 124,017 - Other................................. - 63,459 3,772 - 67,231 -------- -------- -------- --------- -------- (170,601) 554,906 245,876 - 754,198 -------- -------- -------- --------- -------- Income before income taxes.............. 164,458 111,878 6,180 - 158,499 Income tax benefit (provision).......... - (4) 5,963 41 6,000 -------- -------- -------- --------- -------- Income before extraordinary item........ 164,458 111,874 12,143 41 164,499 Extraordinary item - loss on early extinguishment of debt................ (12,318) - - - (12,318) -------- -------- -------- --------- -------- Net income.............................. 152,140 111,874 12,143 41 152,181 Other comprehensive income (loss): Unrealized gains on available for sale securities: Unrealized holdings gains........... - 33,828 - - 33,828 Gains included in net income........ - (25,674) - - (25,674) Translation adjustment................ - - (6,910) - (6,910) -------- -------- -------- --------- -------- Comprehensive income.................... $ 152,140 $ 120,028 $ 5,233 $ 41 $ 153,425 ======== ======== ======== ========= ========
78 PIONEER NATURAL RESOURCES COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 2002, 2001 and 2000 CONSOLIDATING CONDENSED STATEMENT OF CASH FLOWS For the Year Ended December 31, 2002 (in thousands) Pioneer Natural Resources Non- Company Pioneer Guarantor The (Parent) USA Subsidiaries Company ---------- --------- ------------ --------- Cash flows from operating activities: Net cash provided by (used in) operating activities...... $ (327,185) $ 406,939 $ 252,491 $ 332,245 --------- -------- -------- --------- Cash flows from investing activities: Proceeds from disposition of assets...................... 31,994 86,703 153 118,850 Additions to oil and gas properties...................... - (365,981) (248,717) (614,698) Other property (additions) retirements, net.............. - (13,171) 888 (12,283) --------- -------- -------- --------- Net cash provided by (used in) investing activities.. 31,994 (292,449) (247,676) (508,131) --------- -------- -------- --------- Cash flows from financing activities: Borrowings under long-term debt.......................... 529,805 - - 529,805 Principal payments on long-term debt..................... (481,783) - - (481,783) Issuance of common stock................................. 236,000 - - 236,000 Payments of noncurrent liabilities....................... - (123,607) (638) (124,245) Deferred loan fees/issuance costs........................ (3,293) - - (3,293) Exercise of stock options and employee stock purchases... 14,389 - - 14,389 --------- -------- -------- --------- Net cash provided by (used in) financing activities.. 295,118 (123,607) (638) 170,873 --------- -------- -------- --------- Net increase (decrease) in cash and cash equivalents....... (73) (9,117) 4,177 (5,013) Effect of exchange rate changes on cash and cash equivalents.............................................. - - (831) (831) Cash and cash equivalents, beginning of period............. 79 10,900 3,355 14,334 --------- -------- -------- --------- Cash and cash equivalents, end of period................... $ 6 $ 1,783 $ 6,701 $ 8,490 ========= ======== ======== =========
CONSOLIDATING CONDENSED STATEMENT OF CASH FLOWS For the Year Ended December 31, 2001 (in thousands) Pioneer Natural Resources Non- Company Pioneer Guarantor The (Parent) USA Subsidiaries Company ---------- --------- ------------ --------- Cash flows from operating activities: Net cash provided by (used in) operating activities...... $ (10,503) $ 307,776 $ 178,327 $ 475,600 --------- -------- -------- --------- Cash flows from investing activities: Cash acquired in acquisition, net of fees paid........... - 11,119 - 11,119 Proceeds from disposition of assets...................... 21,170 75,816 16,467 113,453 Additions to oil and gas properties...................... - (336,753) (192,970) (529,723) Other property additions, net............................ - (10,717) (6,873) (17,590) --------- -------- -------- --------- Net cash provided by (used in) investing activities.. 21,170 (260,535) (183,376) (422,741) --------- -------- -------- --------- Cash flows from financing activities: Borrowings under long-term debt.......................... 328,331 - - 328,331 Principal payments on long-term debt..................... (333,410) - - (333,410) (Payments of) borrowings under noncurrent liabilities.... - (54,728) 1,291 (53,437) Purchase of treasury stock............................... (13,028) - - (13,028) Exercise of stock options and employee stock purchases... 7,504 - - 7,504 --------- -------- -------- --------- Net cash provided by (used in) financing activities.. (10,603) (54,728) 1,291 (64,040) --------- -------- -------- --------- Net increase (decrease) in cash and cash equivalents....... 64 (7,487) (3,758) (11,181) Effect of exchange rate changes on cash and cash equivalents.............................................. - - (644) (644) Cash and cash equivalents, beginning of period............. 15 18,387 7,757 26,159 --------- -------- -------- --------- Cash and cash equivalents, end of period................... $ 79 $ 10,900 $ 3,355 $ 14,334 ========= ======== ======== =========
79 PIONEER NATURAL RESOURCES COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 2001, 2000 and 1999 CONSOLIDATING CONDENSED STATEMENT OF CASH FLOWS For the Year Ended December 31, 2000 (in thousands) Pioneer Natural Resources Non- Company Pioneer Guarantor The (Parent) USA Subsidiaries Company ----------- --------- ------------ ----------- Cash flows from operating activities: Net cash provided by operating activities................ $ 213,491 $ 118,300 $ 98,305 $ 430,096 ---------- -------- -------- ---------- Cash flows from investing activities: Proceeds from disposition of assets...................... - 92,342 10,394 102,736 Additions to oil and gas properties...................... - (179,861) (119,821) (299,682) Other property (additions) dispositions, net............. - (10,004) 12,449 2,445 --------- -------- -------- ---------- Net cash used in investing activities............. - (97,523) (96,978) (194,501) --------- -------- -------- ---------- Cash flows from financing activities: Borrowings under long-term debt.......................... 922,607 - - 922,607 Principal payments on long-term debt..................... (1,099,107) (828) - (1,099,935) Payment of noncurrent liabilities........................ - (24,261) (5,498) (29,759) Purchase of treasury stock............................... (27,298) - - (27,298) Deferred loan fees/issuance costs........................ (13,847) - - (13,847) Exercise of stock options and employee stock purchases... 4,164 - - 4,164 ---------- -------- -------- ---------- Net cash used in financing activities............. (213,481) (25,089) (5,498) (244,068) ---------- -------- -------- ---------- Net increase (decrease) in cash and cash equivalents....... 10 (4,312) (4,171) (8,473) Effect of exchange rate changes on cash and cash equivalents.............................................. - - (156) (156) Cash and cash equivalents, beginning of period............. 5 22,699 12,084 34,788 ---------- -------- -------- ---------- Cash and cash equivalents, end of period................... $ 15 $ 18,387 $ 7,757 $ 26,159 ========== ======== ======== ==========
80 PIONEER NATURAL RESOURCES COMPANY UNAUDITED SUPPLEMENTARY INFORMATION Years Ended December 31, 2002, 2001 and 2000 Capitalized Costs December 31, ------------------------- 2002 2001 ----------- ----------- (in thousands) Oil and Gas Properties: Proved................................................. $ 4,252,897 $ 3,691,783 Unproved............................................... 219,073 187,785 ---------- ---------- 4,471,970 3,879,568 Less accumulated depletion............................. (1,303,541) (1,095,310) ----------- ---------- Net capitalized costs for oil and gas properties....... $ 3,168,429 $ 2,784,258 ========== ==========
Costs Incurred for Oil and Gas Producing Activities Property Acquisition Costs Total ----------------------- Exploration Development Costs Proved Unproved Costs Costs Incurred --------- --------- ----------- ----------- --------- (in thousands) Year Ended December 31, 2002: United States...................... $ 156,736 $ 34,048 $ 72,831 $ 269,945 $ 533,560 Argentina.......................... 12 51 14,530 20,528 35,121 Canada............................. 457 2,329 9,992 20,728 33,506 South Africa....................... - - 2,789 34,300 37,089 Gabon.............................. - - 23,585 - 23,585 Tunisia............................ - 1,843 6,320 - 8,163 Other foreign...................... - - 1,431 - 1,431 -------- -------- --------- --------- -------- Total costs incurred............. $ 157,205 $ 38,271 $ 131,478 $ 345,501 $ 672,455 ======== ======== ========= ========= ======== Year Ended December 31, 2001: United States...................... $ 132,793 $ 19,572 $ 129,639 $ 172,225 $ 454,229 Argentina.......................... 13,182 2,465 36,237 46,427 98,311 Canada............................. 29 97 12,707 23,215 36,048 South Africa....................... 706 125 21,936 13,860 36,627 Gabon.............................. - - 11,387 - 11,387 Tunisia............................ - 1,835 3,652 - 5,487 Other foreign...................... - - 4,471 - 4,471 -------- -------- --------- --------- -------- Total costs incurred............. $ 146,710 $ 24,094 $ 220,029 $ 255,727 $ 646,560 ======== ======== ========= ========= ======== Year Ended December 31, 2000: United States...................... $ 26,102 $ 28,199 $ 65,023 $ 84,798 $ 204,122 Argentina.......................... 1,169 520 35,406 31,335 68,430 Canada............................. 8,709 2,506 6,744 25,632 43,591 South Africa....................... - - 20,176 - 20,176 Gabon.............................. - - 1,326 - 1,326 Other foreign...................... - - 2,095 - 2,095 -------- -------- --------- --------- -------- Total costs incurred............. $ 35,980 $ 31,225 $ 130,770 $ 141,765 $ 339,740 ======== ======== ========= ========= ========
81 PIONEER NATURAL RESOURCES COMPANY UNAUDITED SUPPLEMENTARY INFORMATION Years Ended December 31, 2002, 2001 and 2000 Results of Operations Information about the Company's results of operations for oil and gas producing activities is presented in Note P 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, 2002, which are located principally in the United States, Argentina, Canada, South Africa and Tunisia, were based on evaluations audited by independent petroleum engineers with respect to the Company's major properties and prepared by the Company's engineers with respect to all other properties. The estimates of the Company's proved oil and gas reserves as of December 31, 2001 and 2000 were prepared by the Company's engineers. Reserves were estimated in accordance with guidelines established by the SEC and the Financial Accounting Standards Board, 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 reserve estimates for 2002, 2001 and 2000 utilize respective oil prices of $29.67, $18.88 and $25.71 per Bbl (reflecting adjustments for oil quality); respective NGL prices of $19.01, $11.58 and $16.74 per Bbl; and, respective gas prices of $3.37, $2.21 and $7.50 per Mcf (reflecting adjustments for Btu content, gas processing and shrinkage). Oil and gas reserve quantity estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. The accuracy of such estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of subsequent drilling, testing and production may cause either upward or downward revision of previous estimates. Further, the volumes considered to be commercially recoverable fluctuate with changes in prices and operating costs. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of currently producing oil and gas properties. Accordingly, these estimates are expected to change as additional information becomes available in the future. 82 PIONEER NATURAL RESOURCES COMPANY UNAUDITED SUPPLEMENTARY INFORMATION Years Ended December 31, 2002, 2001 and 2000 Oil and Gas Producing Activities: 2002 2001 2000 ------------------------------ ----------------------------- ----------------------------- Oil Oil Oil & NGLs Gas & NGLs Gas & NGLs Gas Total Proved Reserves: (MBbls) (MMcf) MBOE (MBbls) (MMcf) MBOE (MBbls) (MMcf) MBOE -------- --------- ------- ------- --------- ------- ------- --------- ------- UNITED STATES Balance, January 1............... 279,146 1,474,090 524,829 266,802 1,354,327 492,523 259,066 1,314,842 478,206 Revisions of previous estimates.. 61,529 5,983 62,525 (1,179) 41,039 5,661 19,295 63,912 29,947 Purchases of minerals-in-place... 8,634 83,361 22,528 24,943 63,113 35,462 1,237 28,071 5,916 New discoveries and extensions... 4,364 5,349 5,255 4,442 93,220 19,979 4,819 66,486 15,900 Production....................... (16,042) (84,812) (30,177) (15,862) (77,609) (28,796) (16,872) (83,930) (30,860) Sales of minerals-in-place....... - - - - - - (743) (35,054) (6,586) -------- --------- ------- ------- --------- ------- ------- --------- ------- Balance, December 31............. 337,631 1,483,971 584,960 279,146 1,474,090 524,829 266,802 1,354,327 492,523 ARGENTINA Balance, January 1............... 35,669 471,150 114,193 35,843 408,282 103,890 29,797 415,620 99,067 Revisions of previous estimates.. (4,954) 47,829 3,017 (932) 4,460 (189) 1,411 (15,558) (1,182) Purchases of minerals-in-place... - - - 170 31,700 5,453 - - - New discoveries and extensions... 3,985 41,652 10,927 4,354 58,538 14,110 8,066 43,914 15,385 Production....................... (3,168) (28,550) (7,926) (3,766) (31,830) (9,071) (3,431) (35,694) (9,380) -------- --------- ------- ------- --------- ------- ------- --------- ------- Balance, December 31............. 31,532 532,081 120,211 35,669 471,150 114,193 35,843 408,282 103,890 CANADA Balance, January 1............... 2,659 132,061 24,669 4,066 132,919 26,219 3,970 145,251 28,179 Revisions of previous estimates.. 24 (1,150) (167) 212 15,067 2,723 429 (10,013) (1,240) Purchases of minerals-in-place... - - - - - - 140 7,768 1,435 New discoveries and extensions... 68 6,070 1,080 81 5,644 1,022 138 6,132 1,160 Production....................... (390) (17,653) (3,333) (671) (18,426) (3,742) (611) (16,219) (3,315) Sales of minerals-in-place....... - - - (1,029) (3,143) (1,553) - - - -------- --------- ------- ------- --------- ------- ------- --------- ------- Balance, December 31............. 2,361 119,328 22,249 2,659 132,061 24,669 4,066 132,919 26,219 SOUTH AFRICA Balance, January 1............... 7,685 - 7,685 5,552 - 5,552 - - - Revisions of previous estimates.. 790 - 790 - - - - - - Purchases of minerals-in-place... - - - 2,133 - 2,133 - - - New discoveries and extensions... - - - - - - 5,552 - 5,552 -------- --------- ------- ------- --------- ------- ------- --------- ------- Balance, December 31............. 8,475 - 8,475 7,685 - 7,685 5,552 - 5,552 TUNISIA Balance, January 1............... - - - - - - - - - New discoveries and extensions... 845 - 845 - - - - - - -------- --------- ------- ------- --------- ------- ------- --------- ------- Balance, December 31............. 845 - 845 - - - - - - TOTAL Balance, January 1............... 325,159 2,077,301 671,376 312,263 1,895,528 628,184 292,833 1,875,713 605,452 Revisions of previous estimates (a).................. 57,389 52,662 66,165 (1,899) 60,566 8,195 21,135 38,341 27,525 Purchases of minerals-in-place... 8,634 83,361 22,528 27,246 94,813 43,048 1,377 35,839 7,351 New discoveries and extensions... 9,262 53,071 18,107 8,877 157,402 35,111 18,575 116,532 37,997 Production....................... (19,600) (131,015) (41,436) (20,299) (127,865) (41,609) (20,914) (135,843) (43,555) Sales of minerals-in-place....... - - - (1,029) (3,143) (1,553) (743) (35,054) (6,586) -------- --------- ------- ------- --------- ------- ------- --------- ------- Balance, December 31............. 380,844 2,135,380 736,740 325,159 2,077,301 671,376 312,263 1,895,528 628,184 ======== ========= ======= ======= ========= ======= ======= ========= ======= Proved Developed Reserves: United States.................. 196,893 1,027,750 368,184 206,922 1,081,592 387,188 209,636 1,118,976 396,133 Argentina...................... 28,248 341,967 85,243 22,679 345,281 80,226 22,931 358,124 82,618 Canada......................... 2,086 94,607 17,854 2,930 80,953 16,422 2,598 61,210 12,800 -------- --------- ------- ------- --------- ------- ------- --------- ------- January 1.................... 227,227 1,464,324 471,281 232,531 1,507,826 483,836 235,165 1,538,310 491,551 ======== ========= ======= ======= ========= ======= ======= ========= ======= United States.................. 209,948 1,067,701 387,899 196,893 1,027,750 368,184 206,922 1,081,592 387,188 Argentina...................... 22,180 402,640 89,287 28,248 341,967 85,243 22,679 345,281 80,226 Canada......................... 2,042 90,003 17,042 2,086 94,607 17,854 2,930 80,953 16,422 -------- --------- ------- ------- --------- ------- ------- --------- ------- December 31.................. 234,170 1,560,344 494,228 227,227 1,464,324 471,281 232,531 1,507,826 483,836 ======== ========= ======= ======= ========= ======= ======= ========= ======= - ------------- (a) The revisions of previous estimates above, include revisions attributable to changes in commodity prices totaling a 28,643 MBOE increase, a 24,970 MBOE decrease and a 14,009 MBOE increase for the years ended December 31, 2002, 2001 and 2000, respectively.
83 PIONEER NATURAL RESOURCES COMPANY UNAUDITED SUPPLEMENTARY INFORMATION Years Ended December 31, 2002, 2001 and 2000 Standardized Measure of Discounted Future Net Cash Flows The standardized measure of discounted future net cash flows is computed by applying year-end prices of oil and gas (with consideration of price changes only to the extent provided by contractual arrangements) to the estimated future production of proved oil and gas reserves less estimated future expenditures (based on year-end costs) to be incurred in developing and producing the proved reserves, discounted using a rate of 10 percent per year to reflect the estimated timing of the future cash flows. Future income taxes are calculated by comparing undiscounted future cash flows to the tax basis of oil and gas properties plus available carryforwards and credits and applying the current tax rates to the difference. The discounted future net cash flows estimated in the table below do not include the effects of the Company's commodity hedging contracts. Utilizing December 31, 2002 commodity prices held constant over each hedge contract's term, the net present value of the Company's hedge contracts discounted at 10 percent was a liability equal to approximately $226 million. 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. 84 PIONEER NATURAL RESOURCES COMPANY UNAUDITED SUPPLEMENTARY INFORMATION Years Ended December 31, 2002, 2001 and 2000 For the Year Ended December 31, ----------------------------------------- 2002 2001 2000 ----------- ----------- ----------- (in thousands) UNITED STATES Oil and gas producing activities: Future cash inflows.................................. $15,161,717 $ 8,222,573 $18,660,169 Future production costs.............................. (4,830,294) (3,231,730) (4,907,134) Future development costs............................. (864,386) (735,984) (479,290) Future income tax expense............................ (2,325,946) (598,612) (3,777,157) ---------- ---------- ---------- 7,141,091 3,656,247 9,496,588 10% annual discount factor.............................. (3,684,400) (1,691,118) (4,780,133) ---------- ---------- ---------- Standardized measure of discounted future cash flows.... $ 3,456,691 $ 1,965,129 $ 4,716,455 ========== ========== ========== ARGENTINA Oil and gas producing activities: Future cash inflows.................................. $ 986,716 $ 1,070,664 $ 1,183,652 Future production costs.............................. (175,938) (227,435) (215,853) Future development costs............................. (84,669) (144,604) (114,606) Future income tax expense............................ (143,845) (45,140) (81,705) ---------- ---------- ---------- 582,264 653,485 771,488 10% annual discount factor.............................. (242,158) (262,334) (264,126) ---------- ---------- ---------- Standardized measure of discounted future cash flows.... $ 340,106 $ 391,151 $ 507,362 ========== ========== ========== CANADA Oil and gas producing activities: Future cash inflows.................................. $ 502,260 $ 301,002 $ 1,029,007 Future production costs.............................. (89,246) (73,601) (104,189) Future development costs............................. (22,294) (27,050) (35,443) Future income tax expense............................ (87,363) (10,771) (306,399) ---------- ---------- ---------- 303,357 189,580 582,976 10% annual discount factor.............................. (104,345) (59,995) (168,441) ---------- ---------- ---------- Standardized measure of discounted future cash flows.... $ 199,012 $ 129,585 $ 414,535 ========== ========== ========== SOUTH AFRICA Oil and gas producing activities: Future cash inflows.................................. $ 256,436 $ 149,777 $ 126,134 Future production costs.............................. (92,820) (73,697) (65,232) Future development costs............................. (23,200) (54,281) (47,970) Future income tax expense............................ (4,465) - - ---------- ---------- ---------- 135,951 21,799 12,932 10% annual discount factor.............................. (14,588) (7,338) (5,782) ---------- ---------- ---------- Standardized measure of discounted future cash flows.... $ 121,363 $ 14,461 $ 7,150 ========== ========== ========== TUNISIA Oil and gas producing activities: Future cash inflows.................................. $ 23,460 $ - $ - Future production costs.............................. (2,396) - - Future development costs............................. (3,570) - - Future income tax expense............................ (6,447) - - ---------- ---------- ---------- 11,047 - - 10% annual discount factor.............................. (1,667) - - ---------- ---------- ---------- Standardized measure of discounted future cash flows.... $ 9,380 $ - $ - ========== ========== ========== TOTAL Oil and gas producing activities: Future cash inflows.................................. $16,930,589 $ 9,744,016 $20,998,962 Future production costs.............................. (5,190,694) (3,606,463) (5,292,408) Future development costs............................. (998,119) (961,919) (677,309) Future income tax expense............................ (2,568,066) (654,523) (4,165,261) ---------- ---------- ---------- 8,173,710 4,521,111 10,863,984 10% annual discount factor.............................. (4,047,158) (2,020,785) (5,218,482) ---------- ---------- ---------- Standardized measure of discounted future cash flows.... $ 4,126,552 $ 2,500,326 $ 5,645,502 ========== ========== ==========
85 PIONEER NATURAL RESOURCES COMPANY UNAUDITED SUPPLEMENTARY INFORMATION Years Ended December 31, 2002, 2001 and 2000 For the Year Ended December 31, ---------------------------------------- Oil and Gas Producing Activities 2002 2001 2000 ----------- ----------- ----------- (in thousands) Oil and gas sales, net of production costs............... $ (489,338) $ (631,365) $ (663,473) Net changes in prices and production costs............... 2,042,575 (4,528,168) 3,829,794 Extensions and discoveries............................... 152,253 184,454 525,361 Development costs incurred during the period............. 262,469 239,156 101,350 Sales of minerals-in-place............................... - (23,372) (72,624) Purchases of minerals-in-place........................... 187,460 201,535 187,097 Revisions of estimated future development costs.......... (387,404) (429,365) (200,734) Revisions of previous quantity estimates................. 527,987 40,771 344,454 Accretion of discount.................................... 250,033 701,943 293,726 Changes in production rates, timing and other............ 99,722 (274,689) (262,784) ---------- ---------- ---------- Change in present value of future net revenues........... 2,645,757 (4,519,100) 4,082,167 Net change in present value of future income taxes....... (1,019,531) 1,373,924 (1,373,924) ---------- ---------- ---------- 1,626,226 (3,145,176) 2,708,243 Balance, beginning of year............................... 2,500,326 5,645,502 2,937,259 --------- ---------- ---------- Balance, end of year..................................... $4,126,552 $ 2,500,326 $ 5,645,502 ========= ========== ==========
Selected Quarterly Financial Results Quarter ---------------------------------------------- First Second Third Fourth --------- ---------- --------- -------- (in thousands, except per share data) 2002 Operating revenues........................... $ 165,539 $ 172,430 $ 168,317 $ 195,494 Total revenues and other income.............. $ 166,658 $ 174,338 $ 178,753 $ 197,685 Costs and expenses........................... $ 169,027 $ 158,916 $ 157,953 $ 177,416 Net income (loss): Before extraordinary items................ $ (1,959) $ 13,985 $ 18,611 $ 18,422 Extraordinary items, net of tax (a)....... - (2,843) (19,501) (2) -------- -------- -------- -------- Net income (loss)......................... $ (1,959) $ 11,142 $ (890) $ 18,420 ======== ======== ======== ======== Net income (loss) per share: Basic: Before extraordinary items.............. $ (.02) $ .13 $ .16 $ .16 Extraordinary items..................... - (.03) (.17) - -------- -------- -------- -------- Net income (loss)....................... $ (.02) $ .10 $ (.01) $ .16 ======== ======== ======== ======== Diluted: Before extraordinary items.............. $ (.02) $ .12 $ .16 $ .16 Extraordinary items..................... - (.02) (.17) - -------- -------- -------- -------- Net income (loss)....................... $ (,02) $ .10 $ (.01) $ .16 ======== ======== ======== ======== 2001 Operating revenues........................... $ 257,986 $ 218,611 $ 198,088 $ 172,337 Total revenues............................... $ 270,446 $ 231,038 $ 204,471 $ 170,526 Costs and expenses........................... $ 202,127 $ 200,092 $ 178,864 $ 187,633 Net income (loss): Before extraordinary items................ $ 67,919 $ 28,338 $ 23,228 $ (15,736) Extraordinary items, net of tax (a)....... - - 1,374 (5,127) -------- -------- -------- -------- Net income (loss)......................... $ 67,919 $ 28,338 $ 24,602 $ (20,863) ======== ======== ======== ======== Net income (loss) per share: Basic: Before extraordinary items.............. $ .69 $ .29 $ .24 $ (.16) Extraordinary items..................... - - .01 (.05) -------- -------- -------- -------- Net income (loss)....................... $ .69 $ .29 $ .25 $ (.21) ======== ======== ======== ======== Diluted: Before extraordinary items.............. $ .68 $ .28 $ .24 $ (.16) Extraordinary items..................... - - .01 (.05) -------- -------- -------- -------- Net income (loss)....................... $ .68 $ .28 $ .25 $ (.21) ======== ======== ======== ========
86 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT The information required in response to this item is set forth in the Company's definitive proxy statement for the annual meeting of stockholders to be held on May 15, 2003 and is incorporated herein by reference. ITEM 11. EXECUTIVE COMPENSATION The information required in response to this item is set forth in the Company's definitive proxy statement for the annual meeting of stockholders to be held on May 15, 2003 and is incorporated herein by reference. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT The information required in response to this item is set forth in the Company's definitive proxy statement for the annual meeting of stockholders to be held on May 15, 2003 and is incorporated herein by reference. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS The information required in response to this item is set forth in the Company's definitive proxy statement for the annual meeting of stockholders to be held on May 15, 2003 and is incorporated herein by reference. ITEM 14. CONTROLS AND PROCEDURES (a) Evaluation of disclosure controls and procedures. Within 90 days prior to the filing date of this Report, the Company's principal executive officer ("CEO") and principal financial officer ("CFO") carried out an evaluation of the effectiveness of the Company's disclosure controls and procedures. Based on those evaluations, the Company's CEO and CFO believe (i) that the Company's disclosure controls and procedures are designed to ensure that information required to be disclosed by the Company in the reports it files under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms and that such information is accumulated and communicated to the Company's management, including the CEO and CFO, as appropriate to allow timely decisions regarding required disclosure; and (ii) that the Company's disclosure controls and procedures are effective. (b) Changes in internal controls. There have been no significant changes in the Company's internal controls or in other factors that could significantly affect the Company's internal controls subsequent to the evaluation referred to in Item 14. (a), above, nor have there been any corrective actions with regard to significant deficiencies or material weaknesses. 87 PART IV ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K (a) Listing of Financial Statements and Exhibits Financial Statements The following consolidated financial statements of the Company are included in "Item 8. Financial Statements and Supplementary Data": Independent Auditors' Report Consolidated Balance Sheets as of December 31, 2002 and 2001 Consolidated Statements of Operations for the years ended December 31, 2002, 2001 and 2000 Consolidated Statements of Stockholders' Equity for the years ended December 31, 2002, 2001 and 2000 Consolidated Statements of Cash Flows for the years ended December 31, 2002, 2001 and 2000 Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2002, 2001 and 2000 Notes to Consolidated Financial Statements Unaudited Supplementary Information (b) Reports on Form 8-K During the three months ended December 31, 2002, the Company filed one Current Report on Form 8-K dated October 24, 2002. The Company's October 24, 2002 Form 8-K provided, under Items 7 and 9, (i) the Company's news release dated October 24, 2002 that announced the Company's financial and operating results for the three and nine month periods ended September 30, 2002, an operational update and the Company's fourth quarter 2002 financial outlook; and (ii) tables summarizing, as of October 23, 2002, the Company's open oil hedge positions, open gas hedge positions and deferred hedge gains and losses on terminated commodity hedges. (c) 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. (d) Financial Statement Schedules No financial statement schedules are required to be filed as part of this Report or they are inapplicable. 88 Exhibits Exhibit Number Description 3.1 - Amended and Restated Certificate of Incorporation of the Company (incorporated by reference to Exhibit 3.1 to the Company's Registration Statement on Form S-4, dated June 27, 1997, Registration No. 333-26951). 3.2 - Restated Bylaws of the Company (incorporated by reference to Exhibit 3.2 to the Company's Registration Statement on Form S-4, dated June 27, 1997, Registration No. 333-26951). 3.3 - Certificate of Designation of Series A Junior Participating Preferred Stock (incorporated by reference to Exhibit A to Exhibit 4.1 to the Company's Registration Statement on Form 8-A, File No. 001-13245, filed with the SEC on July 24, 2001). 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. 001-13245, filed with the SEC on July 24, 2001). 10.1 - 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. 001-10695). 10.2 - 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 10.1 (incorporated by reference to Exhibit 10.5 to the Company's Quarterly Report on Form 10-Q for the period ended September 30, 1997, File No. 001-13245). 10.3 - Second Supplemental Indenture, dated as of December 30, 1997, among Pioneer USA, a Delaware corporation, Pioneer NewSub1, Inc., a Texas corporation, and The Chase Manhattan Bank, a New York banking association, as Trustee, with respect to the indenture identified above as Exhibit 10.1 (incorporated by reference to Exhibit 10.17 to the Company's Current Report on Form 8-K, File No. 001-13245, filed with the SEC on January 2, 1998). 10.4 - Third Supplemental Indenture, dated as of December 30, 1997, among Pioneer NewSub1, Inc. (as successor to Pioneer USA), a Texas corporation, Pioneer DebtCo, Inc., a Texas corporation, and The Chase Manhattan Bank, a New York banking association, as Trustee, with respect to the indenture identified above as Exhibit 10.1 (incorporated by reference to Exhibit 10.18 to the Company's Current Report on Form 8-K, File No. 001-13245, filed with the SEC on January 2, 1998). 10.5 - Fourth Supplemental Indenture, dated as of December 30, 1997, among Pioneer DebtCo, Inc. (as successor to Pioneer NewSub1, Inc., as successor to Pioneer USA), a Texas corporation, the Company, a Delaware corporation, Pioneer USA, a Delaware corporation, and The Chase Manhattan Bank, a New York banking association, as Trustee, with respect to the indenture identified above as Exhibit 10.1 (incorporated by reference to Exhibit 10.19 to the Company's Current Report on Form 8-K, File No. 001-13245, filed with the SEC on January 2, 1998). 89 Exhibit Number Description 10.6 - Guarantee, dated as of December 30, 1997, by Pioneer USA relating to the $150,000,000 in aggregate principal amount of 8-7/8% Senior Notes due 2005 and $150,000,000 in aggregate principal amount of 8-1/4% Senior Notes due 2007 issued under the indenture identified above as Exhibit 10.1 (incorporated by reference to Exhibit 10.20 to the Company's Current Report on Form 8-K, File No. 001-13245, filed with the SEC on January 2, 1998). 10.7 - Form of 8-7/8% Senior Notes Due 2005, dated as of April 12, 1995, in the aggregate principal amount of $150,000,000, together with Officers' Certificate dated April 12, 1995, establishing the terms of the 8-7/8% Senior Notes Due 2005 pursuant to the indenture identified above as Exhibit 10.1 (incorporated by reference to Exhibit 4.2 to Parker & Parsley's Quarterly Report on Form 10-Q for the period ended June 30, 1995, File No. 001-10695). 10.8 - Form of 8-1/4% Senior Notes due 2007, dated as of August 22, 1995, in the aggregate principal amount of $150,000,000, together with Officers' Certificate dated August 22, 1995, establishing the terms of the 8-1/4% Senior Notes due 2007 pursuant to the indenture identified above as Exhibit 10.1 (incorporated by reference to Exhibit 1.2 to Parker & Parsley's Current Report on Form 8-K, dated August 17, 1995, File No. 001-10695). 10.9 - Indenture, dated January 13, 1998, between the Company and The Bank of New York, as Trustee (incorporated by reference to Exhibit 99.1 to the Company's and Pioneer USA's Current Report on Form 8-K, File No. 001-13245, filed with the SEC on January 14, 1998). 10.10 - First Supplemental Indenture, dated as of January 13, 1998, among the Company, Pioneer USA, as the Subsidiary Guarantor, and The Bank of New York, as Trustee, with respect to the indenture identified above as Exhibit 10.9 (incorporated by reference to Exhibit 99.2 to the Company's and Pioneer USA's Current Report on Form 8-K, File No. 001-13245, filed with the SEC on January 14, 1998). 10.11 - Form of 6.50% Senior Notes Due 2008 of the Company (incorporated by reference to Exhibit 99.3 to the Company's and Pioneer USA's Current Report on Form 8-K, File No. 001-13245, filed with the SEC on January 14, 1998). 10.12 - Form of 7.20% Senior Notes Due 2028 of the Company (incorporated by reference to Exhibit 99.4 to the Company's and Pioneer USA's Current Report on Form 8-K, File No. 001-13245, filed with the SEC on January 14, 1998). 10.13 - Guarantee dated as of January 13, 1998, by Pioneer USA relating to the $350,000,000 in aggregate principal amount of 6.50% Senior Notes Due 2008 issued under the indenture identified above as Exhibit 10.9 (incorporated by reference to Exhibit 99.5 to the Company's and Pioneer USA's Current Report on Form 8-K, File No. 001-13245, filed with the SEC on January 14, 1998). 10.14 - Guarantee dated as of January 13, 1998, by Pioneer USA relating to the $250,000,000 in aggregate principal amount of 7.20% Senior Notes Due 2028 issued under the indenture identified above as Exhibit 10.9 (incorporated by reference to Exhibit 99.6 to the Company's and Pioneer USA's Current Report on Form 8-K, File No. 001-13245, filed with the SEC on January 14, 1998). 10.15H - 1991 Stock Option Plan of Mesa Inc. ("Mesa") (incorporated by reference to Exhibit 10(v) to Mesa's Annual Report on Form 10-K for the period ended December 31, 1991). 10.16H - 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). 10.17H - Parker & Parsley Long-Term Incentive Plan, dated February 19, 1991 (incorporated by reference to Exhibit 4.1 to Parker & Parsley's Registration Statement on Form S-8, Registration No. 33-38971). 90 Exhibit Number Description 10.18H - First Amendment to the Parker & Parsley Long-Term Incentive Plan, dated August 23, 1991 (incorporated by reference to Exhibit 10.2 to Parker & Parsley's Registration Statement on Form S-1, dated February 28, 1992, Registration No. 33-46082). 10.19H - 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). 10.20H - First Amendment to the Company's Long-Term Incentive Plan, effective as of November 23, 1998 (incorporated by reference to Exhibit 10.72 to the Company's Annual Report on Form 10-K for the period ended December 31, 1999, File No. 1-13245). 10.21H - Second Amendment to the Company's Long-Term Incentive Plan, effective as of May 20, 1999 (incorporated by reference to Exhibit 10.73 to the Company's Annual Report on Form 10-K for the period ended December 31, 1999, File No. 1-13245). 10.22H - Third Amendment to the Company's Long-Term Incentive Plan, effective as of February 17, 2000 (incorporated by reference to Exhibit 10.76 to the Company's Annual Report on Form 10-K for the period ended December 31, 1999, File No. 1-13245). 10.23H - The Company's Employee Stock Purchase Plan (incorporated by reference to Exhibit 4.1 to the Company's Registration Statement on Form S-8, Registration No. 333-35165). 10.24H - First Amendment to the Company's Employee Stock Purchase Plan, dated December 9, 1998 (incorporated by reference to the Company's Annual Report on Form 10-K for the year ended December 31, 1998, File No. 001-13245). 10.25H - Second Amendment to the Company's Employee Stock Purchase Plan, dated December 14, 1999 (incorporated by reference to Exhibit 10.74 to the Company's Annual Report on Form 10-K for the period ended December 31, 1999, File No. 1-13245). 10.26H - The Company's Deferred Compensation Retirement Plan (incorporated by reference to Exhibit 4.1 to the Company's Registration Statement on Form S-8, Registration No. 333-39153). 10.27H - Omnibus Amendment to Nonstatutory Stock Option Agreements, included as part of the Parker & Parsley Long-Term Incentive Plan, dated as of November 16, 1995, between Parker & Parsley and Named Executive Officers identified on Schedule 1 setting forth additional details relating to the Parker & Parsley Long-Term Incentive Plan (incorporated by reference to Parker & Parsley's Annual Report on Form 10-K for the year ended December 31, 1995, File No. 001-10695). 10.28H - Severance Agreement, dated as of August 8, 1997, between the Company and Scott D. Sheffield, together with a schedule identifying substantially identical agreements between the Company and each of the other named executive officers identified on Schedule I for the purpose of defining the payment of certain benefits upon the termination of the officer's employment under certain circumstances (incorporated by reference to Exhibit 10.7 to the Company's Quarterly Report on Form 10-Q for the period ended September 30, 1997, File No. 001-13245). 10.29H - Indemnification Agreement, dated as of August 8, 1997, between the Company and Scott D. Sheffield, together with a schedule identifying substantially identical agreements between the Company and each of the Company's other directors and named executive officers identified on Schedule I (incorporated by reference to Exhibit 10.8 to the Company's Quarterly Report on Form 10-Q for the period ended September 30, 1997, File No. 001-13245). 10.30H* - Pioneer USA 40l(k) and Matching Plan, Amended and Restated Effective as of January 1, 2002. 91 Exhibit Number Description 10.31 - 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, dated January 13, 1998, between the Company and The Bank of New York, as trustee (incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q, filed with the SEC on May 11, 2000). 10.32 - Form of 9-5/8% Senior Notes Due 2010, dated as of April 11, 2000, in the aggregate principal amount of $425,000,000, together with Trustee's Certificate of Authentication dated April 11, 2000, establishing the terms of the 9-5/8% Senior Notes Due April 1, 2010 pursuant to the Second Supplemental Indenture identified above as Exhibit 10.31 (incorporated by reference to Exhibit 10.2 to the Company's Quarterly Report on Form 10-Q, filed with the SEC on May 11, 2000). 10.33 - Guarantee, dated as of April 11, 2000, by Pioneer USA as the subsidiary guarantor relating to the $425,000,000 aggregate principal amount of 9-5/8% Senior Notes Due April 1, 2010 issued under the Second Supplemental Indenture identified above as Exhibit 10.31 (incorporated by reference to Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q, filed with the SEC on May 11, 2000). 10.34 - $575,000,000 Credit Agreement, dated as of May 31, 2000, among the Company, as the borrower, Bank of America, N.A., as the Administrative Agent, Credit Suisse First Boston, as the Documentation Agent, the Chase Manhattan Bank, as the Syndicated Agent and certain Lenders (incorporated by reference to Exhibit 10.4 to the Company's Quarterly Report on Form 10-Q, filed with the SEC on August 9, 2000). 10.35 - Agreement and Plan of Merger dated as of November 28, 2000 by and among the Company, Pioneer USA, Parker & Parsley Employees Producing Properties 87-A, Ltd., Parker & Parsley Employees Producing Properties 87-B Ltd., P&P Employees Producing Properties 88-A, L.P., P&P Employees 89-A Conv., L.P., P&P Employees 89-B Conv., L.P., P&P Employees Private 89, L.P., P&P Employees 90-A Conv., L.P., P&P Employees 90-B Conv., L.P., P&P Employees 90-C Conv., L.P., P&P Employees Private 90, L.P., P&P Employees 90 Spraberry Private Development, L.P., P&P Employees 91-A Conv., L.P. and P&P Employees 91-B Conv., L.P. (incorporated by reference to Exhibit 10.53 to the Company's Annual Report on Form 10-K for the period ended December 31, 2000, File No. 1-13245). 10.36 - Agreement and Plan of Merger dated as of September 20, 2001, among the Company, Pioneer USA and the Parker & Parsley partnerships named therein (incorporated by reference to Exhibit 2.1 to the Company's Registration Statement on Form S-4, Registration No. 333-59094, filed with the SEC on April 17, 2001). 10.37 - Underwriting Agreement dated April 16, 2002, among the Company, Pioneer USA and Credit Suisse First Boston Corporation (incorporated by reference to Exhibit 99.1 to the Company's Current Report on Form 8-K, File No. 001-13245, filed with the SEC on April 17, 2002). 10.38 - Terms Agreement dated April 16, 2002, among the Company, Pioneer USA, Credit Suisse First Boston Corporation, Banc of America Securities LLC, J.P. Morgan Securities Inc. and Lehman Brothers Inc. as representatives of the underwriters (incorporated by reference to Exhibit 99.2 to the Company's Current Report on Form 8-K, File No. 001-13245, filed with the SEC on April 17, 2002). 10.39 - 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 (incorporated by reference to Exhibit 10.4 to the Company's Quarterly Report on Form 10-Q for the three months ended March 31, 2002, File No. 001-13245, filed with the SEC on May 14, 2002). 10.40 - Form of 7.50% Senior Notes Due 2012 of the Company (incorporated by reference to Exhibit 99.1 to the Company's Current Report on Form 8-K, File No. 001-13245, filed with the SEC on April 29, 2002). 92 Exhibit Number Description 10.41 - Guarantee dated as of April 30, 2002, by Pioneer USA relating to the $150,000,000 in aggregate principal amount of 7.50% Senior Notes Due 2012 issued under the indenture identified above as Exhibit 10.39 (incorporated by reference to Exhibit 10.6 to the Company's Quarterly Report on Form 10-Q for the three months ended March 31, 2002, File No. 001-13245, filed with the SEC on May 14, 2002). 21.1* - Subsidiaries of the registrant. 23.1* - Consent of Ernst & Young LLP. 23.2* - Consent of Netherland, Sewell & Associates, Inc. 23.3* - Consent of Gaffney, Cline & Associates, Inc. - --------------- * Filed herewith H Executive Compensation Plan or Arrangement previously filed pursuant to Item 14(c). 93 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 20, 2003 By: /s/ Scott D. Sheffield ------------------------------------------------ Scott D. Sheffield, Chairman of the Board, Chief Executive Officer, President and Assistant Secretary Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated. Signature Title Date /s/ Scott D. Sheffield Chairman of the Board, February 20, 2003 - ---------------------------- President, Chief Executive Scott D. Sheffield Officer and Assistant Secretary (principal executive officer) /s/ Timothy L. Dove Executive Vice President, February 20, 2003 - ---------------------------- Chief Financial Officer and Timothy L. Dove Assistant Secretary /s/ Richard P. Dealy Vice President and Chief February 20, 2003 - ---------------------------- Accounting Officer Richard P. Dealy /s/ James R. Baroffio Director February 20, 2003 - ---------------------------- James R. Baroffio /s/ Edison C. Buchanan Director February 20, 2003 - ---------------------------- Edison C. Buchanan /s/ R. Hartwell Gardner Director February 20, 2003 - ---------------------------- R. Hartwell Gardner /s/ James L. Houghton Director February 20, 2003 - ---------------------------- James L. Houghton /s/ Jerry P. Jones Director February 20, 2003 - ---------------------------- Jerry P. Jones /s/ Linda K. Lawson Director February 20, 2003 - ---------------------------- Linda K. Lawson /s/ Charles E. Ramsey, Jr. Director February 20, 2003 - ---------------------------- Charles E. Ramsey, Jr. /s/ Robert A. Solberg Director February 20, 2003 - ---------------------------- Robert A. Solberg 94 CERTIFICATIONS I, Scott D. Sheffield, certify that: 1. I have reviewed this annual report on Form 10-K of Pioneer Natural Resources Company (the "Company"): 2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; 3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the Company as of, and for, the periods presented in this annual report; 4. The Company's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the Company and we have: a) designed such disclosure controls and procedures to ensure that material information relating to the Company, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared; b) evaluated the effectiveness of the Company's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The Company's other certifying officer and I have disclosed, based on our most recent evaluation, to the Company's auditors and the audit committee of the Company's board of directors (or persons performing the equivalent function): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the Company's ability to record, process, summarize and report financial data and have identified for the Company's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the Company's internal controls; and 6. The Company's other certifying officer and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. February 20, 2003 /s/ Scott D. Sheffield ------------------------------------------------- Scott D. Sheffield, Chairman, President and Chief Executive Officer 95 I, Timothy L. Dove, certify that: 1. I have reviewed this annual report on Form 10-K of Pioneer Natural Resources Company (the "Company"): 2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; 3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the Company as of, and for, the periods presented in this annual report; 4. The Company's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the Company and we have: a) designed such disclosure controls and procedures to ensure that material information relating to the Company, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared; b) evaluated the effectiveness of the Company's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The Company's other certifying officer and I have disclosed, based on our most recent evaluation, to the Company's auditors and the audit committee of the Company's board of directors (or persons performing the equivalent function): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the Company's ability to record, process, summarize and report financial data and have identified for the Company's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the Company's internal controls; and 6. The Company's other certifying officer and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. February 20, 2003 /s/ Timothy L. Dove ------------------------------------------- Timothy L. Dove, Executive Vice President and Chief Financial Officer 96 Exhibit Index Page 3.1 - Amended and Restated Certificate of Incorporation of the Company (incorporated by reference to Exhibit 3.1 to the Company's Registration Statement on Form S-4, dated June 27, 1997, Registration No. 333-26951). 3.2 - Restated Bylaws of the Company (incorporated by reference to Exhibit 3.2 to the Company's Registration Statement on Form S-4, dated June 27, 1997, Registration No. 333-26951). 3.3 - Certificate of Designation of Series A Junior Participating Preferred Stock (incorporated by reference to Exhibit A to Exhibit 4.1 to the Company's Registration Statement on Form 8-A, File No. 001-13245, filed with the SEC on July 24, 2001). 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. 001-13245, filed with the SEC on July 24, 2001). 10.1 - 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. 001-10695). 10.2 - 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 10.1 (incorporated by reference to Exhibit 10.5 to the Company's Quarterly Report on Form 10-Q for the period ended September 30, 1997, File No. 001-13245). 10.3 - Second Supplemental Indenture, dated as of December 30, 1997, among Pioneer USA, a Delaware corporation, Pioneer NewSub1, Inc., a Texas corporation, and The Chase Manhattan Bank, a New York banking association, as Trustee, with respect to the indenture identified above as Exhibit 10.1 (incorporated by reference to Exhibit 10.17 to the Company's Current Report on Form 8-K, File No. 001-13245, filed with the SEC on January 2, 1998). 10.4 - Third Supplemental Indenture, dated as of December 30, 1997, among Pioneer NewSub1, Inc.(as successor to Pioneer USA), a Texas corporation, Pioneer DebtCo, Inc., a Texas corporation, and The Chase Manhattan Bank, a New York banking association, as Trustee, with respect to the indenture identified above as Exhibit 10.1 (incorporated by reference to Exhibit 10.18 to the Company's Current Report on Form 8-K, File No. 001-13245, filed with the SEC on January 2, 1998). 10.5 - Fourth Supplemental Indenture, dated as of December 30, 1997, among Pioneer DebtCo, Inc. (as successor to Pioneer NewSub1, Inc., as successor to Pioneer USA), a Texas corporation, the Company, a Delaware corporation, Pioneer USA, a Delaware corporation, and The Chase Manhattan Bank, a New York banking association, as Trustee, with respect to the indenture identified above as Exhibit 10.1 (incorporated by reference to Exhibit 10.19 to the Company's Current Report on Form 8-K, File No. 001-13245, filed with the SEC on January 2, 1998). 97 Exhibit Index Page 10.6 - Guarantee, dated as of December 30, 1997, by Pioneer USA relating to the $150,000,000 in aggregate principal amount of 8-7/8% Senior Notes due 2005 and $150,000,000 in aggregate principal amount of 8-1/4% Senior Notes due 2007 issued under the indenture identified above as Exhibit 10.1 (incorporated by reference to Exhibit 10.20 to the Company's Current Report on Form 8-K, File No. 001-13245, filed with the SEC on January 2, 1998). 10.7 - Form of 8-7/8% Senior Notes Due 2005, dated as of April 12, 1995, in the aggregate principal amount of $150,000,000, together with Officers' Certificate dated April 12, 1995, establishing the terms of the 8-7/8% Senior Notes Due 2005 pursuant to the indenture identified above as Exhibit 10.1 (incorporated by reference to Exhibit 4.2 to Parker & Parsley's Quarterly Report on Form 10-Q for the period ended June 30, 1995, File No. 001-10695). 10.8 - Form of 8-1/4% Senior Notes due 2007, dated as of August 22, 1995, in the aggregate principal amount of $150,000,000, together with Officers' Certificate dated August 22, 1995, establishing the terms of the 8-1/4% Senior Notes due 2007 pursuant to the indenture identified above as Exhibit 10.1 (incorporated by reference to Exhibit 1.2 to Parker & Parsley's Current Report on Form 8-K, dated August 17, 1995, File No. 001-10695). 10.9 - Indenture, dated January 13, 1998, between the Company and The Bank of New York, as Trustee (incorporated by reference to Exhibit 99.1 to the Company's and Pioneer USA's Current Report on Form 8-K, File No. 001-13245, filed with the SEC on January 14, 1998). 10.10 - First Supplemental Indenture, dated as of January 13, 1998, among the Company, Pioneer USA, as the Subsidiary Guarantor, and The Bank of New York, as Trustee, with respect to the indenture identified above as Exhibit 10.9 (incorporated by reference to Exhibit 99.2 to the Company's and Pioneer USA's Current Report on Form 8-K, File No. 001-13245, filed with the SEC on January 14, 1998). 10.11 - Form of 6.50% Senior Notes Due 2008 of the Company (incorporated by reference to Exhibit 99.3 to the Company's and Pioneer USA's Current Report on Form 8-K, File No. 001-13245, filed with the SEC on January 14, 1998). 10.12 - Form of 7.20% Senior Notes Due 2028 of the Company (incorporated by reference to Exhibit 99.4 to the Company's and Pioneer USA's Current Report on Form 8-K, File No. 001-13245, filed with the SEC on January 14, 1998). 10.13 - Guarantee dated as of January 13, 1998, by Pioneer USA relating to the $350,000,000 in aggregate principal amount of 6.50% Senior Notes Due 2008 issued under the indenture identified above as Exhibit 10.9 (incorporated by reference to Exhibit 99.5 to the Company's and Pioneer USA's Current Report on Form 8-K, File No. 001-13245, filed with the SEC on January 14, 1998). 10.14 - Guarantee dated as of January 13, 1998, by Pioneer USA relating to the $250,000,000 in aggregate principal amount of 7.20% Senior Notes Due 2028 issued under the indenture identified above as Exhibit 10.9 (incorporated by reference to Exhibit 99.6 to the Company's and Pioneer USA's Current Report on Form 8-K, File No. 001-13245, filed with the SEC on January 14, 1998). 10.15H - 1991 Stock Option Plan of Mesa Inc. ("Mesa") (incorporated by reference to Exhibit 10(v) to Mesa's Annual Report on Form 10-K for the period ended December 31, 1991). 98 Exhibit Index Page 10.16H - 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). 10.17H - Parker & Parsley Long-Term Incentive Plan, dated February 19, 1991 (incorporated by reference to Exhibit 4.1 to Parker & Parsley's Registration Statement on Form S-8, Registration No. 33-38971). 10.18H - First Amendment to the Parker & Parsley Long-Term Incentive Plan, dated August 23, 1991 (incorporated by reference to Exhibit 10.2 to Parker & Parsley's Registration Statement on Form S-1, dated February 28, 1992, Registration No. 33-46082). 10.19H - 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). 10.20H - First Amendment to the Company's Long-Term Incentive Plan, effective as of November 23, 1998 (incorporated by reference to Exhibit 10.72 to the Company's Annual Report on Form 10- K for the period ended December 31, 1999, File No. 1-13245). 10.21H - Second Amendment to the Company's Long-Term Incentive Plan, effective as of May 20, 1999 (incorporated by reference to Exhibit 10.73 to the Company's Annual Report on Form 10-K for the period ended December 31, 1999, File No. 1-13245). 10.22H - Third Amendment to the Company's Long-Term Incentive Plan, effective as of February 17, 2000 (incorporated by reference to Exhibit 10.76 to the Company's Annual Report on Form 10- K for the period ended December 31, 1999, File No. 1-13245). 10.23H - The Company's Employee Stock Purchase Plan (incorporated by reference to Exhibit 4.1 to the Company's Registration Statement on Form S-8, Registration No. 333-35165). 10.24H - First Amendment to the Company's Employee Stock Purchase Plan, dated December 9, 1998 (incorporated by reference to the Company's Annual Report on Form 10-K for the year ended December 31, 1998, File No. 001-13245). 10.25H - Second Amendment to the Company's Employee Stock Purchase Plan, dated December 14, 1999 (incorporated by reference to Exhibit 10.74 to the Company's Annual Report on Form 10- K for the period ended December 31, 1999, File No. 1-13245). 10.26H - The Company's Deferred Compensation Retirement Plan (incorporated by reference to Exhibit 4.1 to the Company's Registration Statement on Form S-8, Registration No. 333-39153). 10.27H - Omnibus Amendment to Nonstatutory Stock Option Agreements, included as part of the Parker & Parsley Long-Term Incentive Plan, dated as of November 16, 1995, between Parker & Parsley and Named Executive Officers identified on Schedule 1 setting forth additional details relating to the Parker & Parsley Long- Term Incentive Plan (incorporated by reference to Parker & Parsley's Annual Report on Form 10-K for the year ended December 31, 1995, File No. 001-10695). 99 Exhibit Index Page 10.28H - Severance Agreement, dated as of August 8, 1997, between the Company and Scott D. Sheffield, together with a schedule identifying substantially identical agreements between the Company and each of the other named executive officers identified on Schedule I for the purpose of defining the payment of certain benefits upon the termination of the officer's employment under certain circumstances (incorporated by reference to Exhibit 10.7 to the Company's Quarterly Report on Form 10-Q for the period ended September 30, 1997, File No. 001-13245). 10.29H - Indemnification Agreement, dated as of August 8, 1997, between the Company and Scott D. Sheffield, together with a schedule identifying substantially identical agreements between the Company and each of the Company's other directors and named executive officers identified on Schedule I (incorporated by reference to Exhibit 10.8 to the Company's Quarterly Report on Form 10-Q for the period ended September 30, 1997, File No. 001-13245). 10.30H* - Pioneer USA 40l(k) and Matching Plan, Amended and Restated Effective as of January 1, 2002. 10.31 - 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, dated January 13, 1998, between the Company and The Bank of New York, as trustee (incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q, filed with the SEC on May 11, 2000). 10.32 - Form of 9-5/8% Senior Notes Due 2010, dated as of April 11, 2000, in the aggregate principal amount of $425,000,000, together with Trustee's Certificate of Authentication dated April 11, 2000, establishing the terms of the 9-5/8% Senior Notes Due April 1, 2010 pursuant to the Second Supplemental Indenture identified above as Exhibit 10.31 (incorporated by reference to Exhibit 10.2 to the Company's Quarterly Report on Form 10-Q, filed with the SEC on May 11, 2000). 10.33 - Guarantee, dated as of April 11, 2000, by Pioneer USA as the subsidiary guarantor relating to the $425,000,000 aggregate principal amount of 9-5/8% Senior Notes Due April 1, 2010 issued under the Second Supplemental Indenture identified above as Exhibit 10.31 (incorporated by reference to Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q, filed with the SEC on May 11, 2000). 10.34 - $575,000,000 Credit Agreement, dated as of May 31, 2000, among the Company, as the borrower, Bank of America, N.A., as the Administrative Agent, Credit Suisse First Boston, as the Documentation Agent, the Chase Manhattan Bank, as the Syndicated Agent and certain Lenders (incorporated by reference to Exhibit 10.4 to the Company's Quarterly Report on Form 10-Q, filed with the SEC on August 9, 2000). 10.35 - Agreement and Plan of Merger dated as of November 28, 2000 by and among the Company, Pioneer USA, Parker & Parsley Employees Producing Properties 87-A, Ltd., Parker & Parsley Employees Producing Properties 87-B Ltd., P&P Employees Producing Properties 88-A, L.P., P&P Employees 89-A Conv., L.P., P&P Employees 89-B Conv., L.P., P&P Employees Private 89, L.P., P&P Employees 90-A Conv., L.P., P&P Employees 90-B Conv., L.P., P&P Employees 90-C Conv., L.P., P&P Employees Private 90, L.P., P&P Employees 90 Spraberry Private Development, L.P., P&P Employees 91-A Conv., L.P. and P&P Employees 91-B Conv., L.P. (incorporated by reference to Exhibit 10.53 to the Company's Annual Report on Form 10-K for the period ended December 31, 2000, File No. 1-13245). 100 Exhibit Index Page 10.36 - Agreement and Plan of Merger dated as of September 20, 2001, among the Company, Pioneer USA and the Parker & Parsley partnerships named therein (incorporated by reference to Exhibit 2.1 to the Company's Registration Statement on Form S-4, Registration No. 333-59094, filed with the SEC on April 17, 2001). 10.37 - Underwriting Agreement dated April 16, 2002, among the Company, Pioneer USA and Credit Suisse First Boston Corporation (incorporated by reference to Exhibit 99.1 to the Company's Current Report on Form 8-K, File No. 001-13245, filed with the SEC on April 17, 2002). 10.38 - Terms Agreement dated April 16, 2002, among the Company, Pioneer USA, Credit Suisse First Boston Corporation, Banc of America Securities LLC, J.P. Morgan Securities Inc. and Lehman Brothers Inc. as representatives of the underwriters (incorporated by reference to Exhibit 99.2 to the Company's Current Report on Form 8-K, File No. 001-13245, filed with the SEC on April 17, 2002). 10.39 - 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 (incorporated by reference to Exhibit 10.4 to the Company's Quarterly Report on Form 10-Q for the three months ended March 31, 2002, File No. 001-13245, filed with the SEC on May 14, 2002). 10.40 - Form of 7.50% Senior Notes Due 2012 of the Company (incorporated by reference to Exhibit 99.1 to the Company's Current Report on Form 8-K, File No. 001-13245, filed with the SEC on April 29, 2002). 10.41 - Guarantee dated as of April 30, 2002, by Pioneer USA relating to the $150,000,000 in aggregate principal amount of 7.50% Senior Notes Due 2012 issued under the indenture identified above as Exhibit 10.39 (incorporated by reference to Exhibit 10.6 to the Company's Quarterly Report on Form 10-Q for the three months ended March 31, 2002, File No. 001-13245, filed with the SEC on May 14, 2002). 21.1* - Subsidiaries of the registrant. 23.1* - Consent of Ernst & Young LLP. 23.2* - Consent of Netherland, Sewell & Associates, Inc. 23.3* - Consent of Gaffney, Cline & Associates, Inc. - --------------- * Filed herewith H Executive Compensation Plan or Arrangement previously filed pursuant to Item 14(c). 101
                                                                 EXHIBIT 10.30H












                       PIONEER NATURAL RESOURCES USA, INC.

                            401(k) AND MATCHING PLAN

             (Amended and Restated Effective as of January 1, 2002)
              ----------------------------------------------------







                       PIONEER NATURAL RESOURCES USA, INC.
                            401(k) AND MATCHING PLAN

             (Amended and Restated Effective as of January 1, 2002)
              ----------------------------------------------------


                                TABLE OF CONTENTS

                                                                           Page

PREAMBLE      .............................................................  1

ARTICLE I.    DEFINITIONS AND CONSTRUCTION.................................  1
              Section 1.1   Definitions  ..................................  1
              Section 1.2   Construction ..................................  9

ARTICLE II.   ELIGIBILITY AND PARTICIPATION................................  9
              Section 2.1   Eligibility  ..................................  9
              Section 2.2   Participation..................................  9

ARTICLE III.  CONTRIBUTIONS, LIMITATIONS AND FORFEITURES................... 10
              Section 3.1   Pre-Tax and Pre-Tax Bonus Contributions........ 10
              Section 3.2   Matching Contributions......................... 11
              Section 3.3   Catch-Up Contributions......................... 11
              Section 3.4   After-Tax Contributions........................ 12
              Section 3.5   Payment of Contributions....................... 12
              Section 3.6   Return of Employer Contributions............... 12
              Section 3.7   Nondiscrimination Testing...................... 13
              Section 3.8   Application of Forfeitures..................... 17
              Section 3.9   Rollover Contributions......................... 17

ARTICLE IV.   TRUST FUND................................................... 18
              Section 4.1   Trust and Trustee.............................. 18
              Section 4.2   Trust Investment Options....................... 18
              Section 4.3   Valuation and Adjustment of Accounts........... 19

ARTICLE V.    VESTING...................................................... 19
              Section 5.1   Fully Vested Accounts.......................... 19
              Section 5.2   Vesting of Employer Account.................... 19
              Section 5.3   Special Vesting Provisions..................... 20

ARTICLE VI.   VALUATIONS, DISTRIBUTIONS.................................... 21
              Section 6.1   Time of Distribution........................... 21
              Section 6.2   Distribution of Retirement and Disability
                            Benefits....................................... 22



                                         (i)





              Section 6.3   Distribution of Death Benefit.................. 24
              Section 6.4   Distribution of Separation from
                            Employment Benefit............................. 25
              Section 6.5   Forfeitures  .................................. 26
              Section 6.6   In-Service Withdrawals......................... 28
              Section 6.7   Distributions to Minors and Persons Under
                            Legal Disability............................... 29
              Section 6.8   Benefits Payable to Missing Participant or
                            Beneficiary.................................... 29
              Section 6.9   Plan Loans   .................................. 30
              Section 6.10  Qualified Domestic Relations Orders............ 30
              Section 6.11  Transfer of Eligible Rollover Distribution..... 31

ARTICLE VII.  PLAN ADMINISTRATION.......................................... 32
              Section 7.1   401(k) and Matching Plan Committee............. 32
              Section 7.2   Powers, Duties and Liabilities of
                            the Committee.................................. 33
              Section 7.3   Rules, Records and Reports..................... 33
              Section 7.4   Administration Expenses and Taxes.............. 33

ARTICLE VIII. AMENDMENT AND TERMINATION.................................... 34
              Section 8.1   Amendment    .................................. 34
              Section 8.2   Termination  .................................. 34
              Section 8.3   Benefit Plan Design Committee.................. 34

ARTICLE IX.   TOP-HEAVY PROVISIONS......................................... 35
              Section 9.1   Top-Heavy Definitions.......................... 35
              Section 9.2   Minimum Contribution Requirement............... 36
              Section 9.3   Minimum Vesting Schedule....................... 36

ARTICLE X.    MISCELLANEOUS GENERAL PROVISIONS............................. 37
              Section 10.1  Spendthrift Provision.......................... 37
              Section 10.2  Claims Procedure............................... 37
              Section 10.3  Maximum Contribution Limitation................ 37
              Section 10.4  Employment Noncontractual...................... 38
              Section 10.5  Limitations on Responsibility.................. 38
              Section 10.6  Merger or Consolidation........................ 38
              Section 10.7  Applicable Law................................. 39
              Section 10.8  USERRA Compliance.............................. 39


                                      (ii)





                       PIONEER NATURAL RESOURCES USA, INC.
                            401(k) AND MATCHING PLAN

             (Amended and Restated Effective as of January 1, 2002)
              ----------------------------------------------------

         THIS 401(k) AND MATCHING PLAN, a profit sharing plan, made and executed
by PIONEER NATURAL RESOURCES USA, INC., a Delaware corporation (the "Company"),

                          W I T N E S S E T H T H A T :

         WHEREAS,  the Company has  heretofore maintained for the benefit of its
employees a qualified profit sharing plan known as the Pioneer Natural Resources
USA, Inc.  401(k) Plan and a  qualified money purchase pension plan known as the
Pioneer Natural Resources USA, Inc. Matching Plan; and

         WHEREAS,  effective as of  12:01 a.m. on  January 1,  2002, the Company
merged the Pioneer Natural Resources  USA, Inc.  Matching Plan with and into the
Pioneer Natural Resources, Inc. 401(k) Plan; and

         WHEREAS,  the  Company  now  desires to  restate  the  Pioneer  Natural
Resources  USA,  Inc.  401(k) Plan to  accommodate such merger,  change the plan
name, update the plan for tax compliance,  incorporate prior amendments and make
certain other changes;

         NOW, THEREFORE, in consideration of the premises and pursuant to the
authority  reserved  thereunder,  the Pioneer Natural Resources USA, Inc. 401(k)
Plan is hereby amended by  restatement in its entirety,  effective as of January
1, 2002, as the Pioneer Natural  Resources USA, Inc. 401(k) and Matching Plan to
read as follows:


                                   ARTICLE I.

                          DEFINITIONS AND CONSTRUCTION

         Section  1.1   Definitions.    Unless  the  context  clearly  indicates
otherwise, when used in this Plan:

                 (a) "Account" means a Participant's After-Tax Account, Employer
         Employer Account,  Matching Plan Account,  Mesa After-Tax Account, Mesa
         Premium Account,  Mesa Profit-Sharing Account,  Pre-Tax Account,  Prior
         Plan  Employer  Account,  Prior  Plan  Pre-Tax Account  and/or Rollover
         Account,  as the  context requires.  The  Committee  may  establish and
         maintain  separate subaccounts  within a  Participant's  Accounts if it
         deems such to be necessary for the proper administration of the Plan.


                                       -1-








                 (b) "Affiliated Company" means any corporation or organization,
         other than  an Employer,  which is a  member of a  controlled  group of
         corporations  (within the meaning of  Section 414(b) of the Code) or of
         an affiliated  service group  (within the meaning of  Section 414(m) of
         the Code) with respect  to which an Employer is also a member,  and any
         other incorporated or unincorporated trade or business which along with
         an  Employer  is  under  common  control  (within  the  meaning  of the
         regulations  from  time to time  promulgated  by the  Secretary  of the
         Treasury pursuant to  Section 414(c) of the Code);  provided,  however,
         that for the  purposes of Section 10.3 of the Plan,  Section 414(b) and
         (c) of the Code  shall be applied as  modified by Section 415(h) of the
         Code.

                 (c)  "After-Tax Account"  means  the  account  established  and
         maintained  under this  Plan by the Committee to record a Participant's
         interest under this Plan  attributable to  After-Tax Contributions made
         to this Plan.

                 (d)  "After-Tax  Contribution"  means a  contribution made by a
         Participant to this Plan pursuant to Section 3.4.

                 (e) "Basic Compensation"  means the sum of  (i) the base salary
         or wages  and any  overtime payable by an  Employer to an  Employee for
         personal services  rendered to the  Employer but  excluding any  amount
         payable pursuant to an Employer's salary continuation program, (ii) any
         contributions  made  by an  Employer on  behalf  of the  Employee  to a
         qualified cash or  deferred arrangement  (within the meaning of Section
         401(k) of the Code) maintained by such Employer, including any Catch-Up
         Contributions and  Total Pre-Tax  Contributions  made by an Employer to
         this Plan on behalf of such Employee,  (iii) any compensation reduction
         amounts elected by such  Employee for the purchase of benefits pursuant
         to a cafeteria plan  (within the meaning of Section 125(d) of the Code)
         maintained by an  Employer,  and (iv) any elective amounts that are not
         includible  in the gross  income of an  Employee by  reason of  Section
         132(f)(4) of the Code; provided, however,  that the Basic  Compensation
         of an  Employee  taken into  account  under the  Plan for any Plan Year
         shall  not  exceed  $200,000  (as  adjusted  to  take into  account any
         cost-of-living increases  authorized pursuant to  Section 401(a)(17)(B)
         of the Code).

                 (f)  "Catch-Up  Contribution" means a pre-tax contribution made
         by an Employer on behalf of a Participant pursuant to Section 3.3.

                 (g)  "Code"  means  the  Internal  Revenue  Code  of  1986,  as
         amended.

                 (h)  "Committee" means the  401(k) and  Matching Plan Committee
         appointed  by the  Board of Directors of the  Company to administer the
         Plan.

                 (i)  "Company" means  Pioneer Natural  Resources  USA,  Inc., a
         Delaware corporation, and any successor thereto.


                                       -2-








                 (j)  "Compensation"  means  the  sum of  (i)  wages  within the
         meaning  of  Section  3401(a) of the  Code and  all  other  payments of
         remuneration  to  an  Employee by an  Employer  (in  the  course of the
         Employer's trade  or business)  for  which the Employer  is required to
         furnish  the  Employee a  written  statement  under  Sections  6041(d),
         6051(a)(3) and 6052  of the Code,  but determined without regard to any
         rules that limit the remuneration included in wages based on the nature
         or location of the employment or the  services  performed  (such as the
         exception  for agricultural labor in  Section 3401(a)(2)  of the Code),
         (ii) any contributions made by an Employer on behalf of the Employee to
         a qualified cash or deferred arrangement (within the meaning of Section
         401(k) of the Code) maintained by such Employer, including any Catch-Up
         Contributions and  Total Pre-Tax  Contributions made  by an Employer to
         this Plan on behalf of such Employee,  (iii) any compensation reduction
         amounts elected by such  Employee for the purchase of benefits pursuant
         to a cafeteria plan  (within the meaning of Section 125(d) of the Code)
         maintained by an Employer,  and (iv)  any elective amounts that are not
         includible  in the  gross income of an  Employee  by reason of  Section
         132(f)(4) of the Code; provided,  however,  that except for purposes of
         determining  whether an  Employee is a Highly Compensated Employee or a
         Key Employee  (within the meaning of Section 9.1(c)),  the Compensation
         of an  Employee  taken  into  account  under the Plan for any Plan Year
         shall  not  exceed  $200,000  (as adjusted  to take  into  account  any
         cost-of-living  increases authorized  pursuant to Section 401(a)(17)(B)
         of the Code).

                 (k)  "Covered  Employee"  means  any  Employee  other  than  an
         individual who is  (i) a member  of a  collective  bargaining unit with
         which an Employer negotiates and with respect to whom no coverage under
         this Plan has been provided by collective bargaining agreement,  (ii) a
         nonresident  alien with  respect to the  United States who  receives no
         earned income from  an Employer  which constitutes income  from sources
         within the United States,  (iii) a  temporary or  seasonal  Employee as
         determined in accordance with the Employer's normal personnel policies,
         (iv)  not  treated  by an  Employer at  the time of the  performance of
         services as  an  employee for federal  tax purposes,  regardless of any
         subsequent reclassification by an Employer,  any governmental agency or
         account, or (v) treated as a leased employee by an Employer.

                 (l)  "Employee" means any individual employed by an Employer.

                 (m)  "Employer"  shall  include   the  Company  and  a ny other
         incorporated or unincorporated trade or business which may subsequently
         adopt this  Plan with the  consent  of the  Board of  Directors  of the
         Company.

                 (n)  "Employer  Account"  means  the  account  established  and
         maintained under this Plan by  the Committee to record a  Participant's
         interest under this  Plan  attributable to  (i) any amounts credited to
         his or her  Employer Account under the  Superseded Plan as in effect on
         December 31, 2001, and (ii) any Matching Contributions made to the Plan
         for the Participant on or after January 1, 2002.


                                       -3-








                 (o) "Employment Date" means the date an Employee first performs
                 an Hour of Service.

                 (p) "Highly Compensated Employee" means for a Plan Year:

                           (1) any Employee who  during such Plan Year or during
                  the preceding  Plan Year was at any time a 5-percent owner (as
                  defined in  Section 416(i)(1) of  the Code)  of an Employer or
                  Affiliated Company; or

                           (2) any Employee  who during the  preceding Plan Year
                  received  Compensation  greater than  $80,000  (as adjusted to
                  take  into account  any  cost-of-living  increases  authorized
                  pursuant to  Section 414(q)(1) of the  Code) and who is in the
                  group consisting  of the top 20%  (when ranked on the basis of
                  Compensation  received  during  such  preceding  year)  of all
                  Employees, except those excluded pursuant to Section 414(q)(5)
                  of the Code.

         Solely  for  purposes  of  this  definition,  (i)  an  employee  of  an
         Affiliated Company shall be deemed to be an Employee, (ii) compensation
         received from an Affiliated Company shall be deemed to be Compensation,
         and  (iii) a  nonresident alien  who receives  no earned income from an
         Employer  or  Affiliated Company which  constitutes income from sources
         within the United States shall not be considered an Employee.

                 (q) "Hour of Service"  means an  hour for  which an Employee is
         directly   or  indirectly  compensated  or  entitled   to  compensation
         (including  back  pay,  regardless  of  mitigation  of  damages)  by an
         Employer for the  performance of  duties for an Employer or for reasons
         (such as vacation,  sickness or disability)  other than the performance
         of duties for an  Employer.  An Employee will be  credited  with  eight
         Hours of  Service per day  for any customary  work period  during which
         such Employee is on leave of absence authorized by his or her Employer.
         Leaves of absence shall be granted by an Employer to its Employees on a
         uniform, nondiscriminatory basis. In no event shall more than 501 Hours
         of  Service be  credited on  account of any  single  continuous  period
         during which the individual performs no duties.  An Employee's Hours of
         Service shall be credited  to the appropriate Plan Years or eligibility
         computation  period  determined in  accordance  with the  provisions of
         Section 2530.200b-2(b) and (c) of the Department of Labor  Regulations,
         which are  incorporated herein by this reference.  In determining Hours
         of Service for  the purposes of this Plan,  periods of employment by an
         Affiliated Company and services performed as a leased employee  (within
         the meaning of Section 414(n) of the Code) of an Employer or Affiliated
         Company shall be deemed to be periods of employment by an Employer.

                 (r)  "Investment  Fund"  means  any  fund  authorized  for  the
         investment of Trust assets pursuant to Section 4.2.


                                       -4-








                 (s)  "Matching  Contribution" means a  contribution  made by an
         Employer to  the Plan for a Participant pursuant to Section 3.2.

                 (t) "Matching Plan Account"  means the account  established and
         maintained under  this Plan by the Committee  to record a Participant's
         interest under this  Plan attributable to  matching  contributions made
         for such Participant pursuant to the provisions of the Matching Plan as
         in effect on December 31, 2001.

                 (u)  "Matching  Plan" means the  Pioneer Natural Resources USA,
         Inc. Matching Plan,  as in effect from time to time prior to January 1,
         2002.

                 (v)  "Mesa After-Tax Account" means the account established and
         maintained  under this  Plan by the Committee to record a Participant's
         interest under  this Plan  attributable to  his or her  accrued benefit
         derived from after-tax contributions to the Mesa Profit-Sharing Plan as
         in effect on September 30, 1997.

                 (w)  "Mesa Premium Account"  means the account  established and
         maintained under this Plan by the  Committee to record a  Participant's
         interest under this Plan  attributable to  Employer  contributions made
         for such  Participant  pursuant to the  provisions of the  Mesa Premium
         Plan as in effect on September 30, 1997.

                 (x)  "Mesa Premium Plan"  means the Mesa Employees Premium Plan
         and Trust Agreement  as in effect from time to time prior to October 1,
         1997.

                 (y) "Mesa Profit-Sharing Account" means the account established
         and  maintained  under   this  Plan   by  the  Committee  to  record  a
         Participant's  interest  under  this  Plan  attributable  to his or her
         accrued benefit derived from employer contributions to the Mesa Profit-
         Sharing Plan as in effect on September 30, 1997.

                 (z) "Mesa  Profit-Sharing Plan"  means the  Mesa Profit-Sharing
         Plan and  Trust Agreement  as in  effect  from  time to  time  prior to
         October 1, 1997.

                 (aa) "Non-Highly  Compensated  Employee"  means for a Plan Year
         any  Employee who  is not a Highly  Compensated Employee  for such Plan
         Year.

                 (bb) The  "Normal  Retirement  Date" of a Participant means the
         day such Participant attains the age of 65 years.

                 (cc) "One Year Break in Service"  means a  12-consecutive-month
         Period of Severance during which an Employee fails to complete a single
         Hour of Service.

                 (dd) "Participant"  means any  individual who was a participant
         in either the Superseded Plan or the  Matching Plan or  who has elected
         to participate in this Plan pursuant to Section 2.2,  and whose  Vested
         Interest under this Plan has not been fully distributed.


                                       -5-








                 (ee) "Period of Service" means,  for purposes of determining a
         Participant's Vested Interest in his or her Employer Account,  the sum,
         rounded  downward to the  nearest  whole year,  of each  period of time
         commencing with an Employee's  Employment Date or Reemployment Date and
         ending  on the  first  date  thereafter a  Period of  Severance  begins
         (except as provided in  subsection (ff)  of this Section in the case of
         an Employee's  maternity or  paternity leave of  absence).  Included in
         such sum to be  credited to an  Employee shall  be each  period of time
         during  which the  Employee is on an  authorized  leave of  absence for
         reasons of vacation,  sickness,  layoff or another occasion  designated
         and applied by an Employer or Affiliated Company on a nondiscriminatory
         basis,  but  in no event  exceeding one  year  in length.  A  Period of
         Service  also  includes  any  Period  of  Severance  of  less  than  12
         consecutive  months.  If an  Employee who  has no  vested right  to any
         amount credited to his or her Employer Account or Matching Plan Account
         incurs a One Year Break in Service,  such Employee shall forfeit his or
         her prior  Period of Service  unless he or  she completes an additional
         one-year Period of Service before the number  of his or her consecutive
         One Year  Breaks in  Service  equals  five.  Solely for the  purpose of
         determining the Period of Service  completed by a  Covered Employee who
         was in the employ of  Colorado Interstate  Gas Company on  May 1, 2001,
         periods  of  employment  by  Colorado   Interstate  Gas  Company  or  a
         subsidiary  thereof  prior to May 1,  2001,  shall be  considered to be
         periods of employment by an Employer.

                  Any provision of this Plan to the contrary notwithstanding, if
         a Participant participated  in the Superseded  Plan prior to October 1,
         1997,  the  Period of Service  completed  by such  Participant prior to
         January 1,  1998,  shall be (i)  such  Participant's  years of  Vesting
         Service determined under the  Retirement Savings Plan for  Employees of
         Parker & Parsley as of June 27,  1996,  (ii) plus one year for the Plan
         Year  ending  December  31,  1996,   if  during  such  Plan  Year  such
         Participant completed  a Year of  Service under the  Retirement Savings
         Plan for Employees of  Parker & Parsley as in effect at the end of such
         year,  (iii) plus one year for the  Plan Year ending December 31, 1997,
         if such Participant  either (A)  completed a year of Vesting Service as
         of September 30, 1997,  under the Superseded  Plan as in effect on such
         date or (B) completed a one-year Period  of Service under the foregoing
         provisions of this  definition  during the entire  such Plan Year.  For
         purposes of clause  (ii) of the preceding sentence, a Participant shall
         be credited  with a  number of  Hours of  Service  applying the monthly
         equivalency method set forth in Labor Reg. ss. 2530.200b-3(e)(1)(iv) to
         any fractional  part of a year credited to such  Participant as of June
         28, 1996.

                 (ff)  "Period of Severance"  means a  period of time commencing
         with the  date an  Employee  ceases to be  employed  by an  Employer or
         Affiliated  Company for reasons of  Retirement,  Permanent  Disability,
         death, being discharged, or voluntarily ceasing employment, or with the
         first  anniversary of  the date  of his  or her  absence for  any other
         reason, and ending with the date such Employee resumes  employment with
         an Employer or  Affiliated Company;  provided, however, that solely for



                                       -6-








         purposes  of determining  whether an  Employee incurs a  One Year Break
         in Service,  the Period of Severance of an  Employee who is absent from
         work due to the pregnancy of the Employee,  the birth of a child of the
         Employee, the placement of a child with the Employee in connection with
         the adoption of  such child by such Employee,  or caring for such child
         for a period  beginning immediately  following such  birth or placement
         shall not  commence until the  second anniversary of the  first date of
         such absence and the  period between the first and second anniversaries
         of the first date of such  absence shall be considered neither a Period
         of Service nor a Period of Severance.

                 (gg) "Permanent  Disability"  means  the  total  and  permanent
         incapacity of a Participant to  perform the usual  duties of his or her
         employment with an  Employer or Affiliated Company as determined by the
         Committee. Such incapacity shall be deemed to exist when certified by a
         physician acceptable to the Committee.

                 (hh) "Pioneer Stock"  means the common stock of Pioneer Natural
         Resources Company, a Delaware corporation, and any successor thereto.

                 (ii) "Plan"  means  this  Pioneer  Natural  Resources USA, Inc.
         401(k) and Matching Plan (Amended and Restated  Effective as of January
         1, 2002), as in effect from time to time.

                 (jj) "Plan Year" means the calendar year.

                 (kk) "Pre-Tax  Account"  means   the  account  established  and
         maintained under  this Plan by the  Committee to record a Participant's
         interest  under this Plan attributable to (i) Pre-Tax Contributions and
         Pre-Tax  Bonus  Contributions  made by an  Employer on  behalf of  such
         Participant  and  (ii)  any  amounts  credited  to his or her  Employee
         Pre-Tax Contribution Account under the Superseded  Plan as in effect on
         September 30, 1997.

                 (ll) "Pre-Tax Bonus Contribution" means a  contribution made by
         an Employer to this Plan on behalf of a Participant pursuant to Section
         3.1(b).

                 (mm) "Pre-Tax Contribution"  means a  contribution  made  by an
         Employer to this Plan on  behalf of a  Participant pursuant  to Section
         3.1(a).

                 (nn)  "Prior  Plan   Employer   Account"   means   the  account
         established and maintained under this Plan by the Committee to record a
         Participant's  interest  under  this Plan  attributable to any  amounts
         credited to  his or her  BOUSA  Employer Matching  Contribution Account
         under the Retirement Savings Plan for Employees of  Parker & Parsley as
         in effect on June 27, 1996.

                 (oo) "Prior Plan Pre-Tax Account" means the account established
         and  maintained  under   this  Plan  by  the   Committee  to  record  a
         Participant's  interest  under  this  Plan  attributable to any amounts

                                       -7-








         credited to  his or her  Plan A Salary Deferral Contribution Account or
         his or  her BOUSA  Plan Salary Deferral  Contribution Account under the
         Retirement Savings  Plan for Employees of Parker & Parsley as in effect
         on June 27, 1996.

                 (pp) "Qualified  Joint and  Survivor Annuity"  means an annuity
         which is  payable  for the  life  of the  Participant  with a  survivor
         annuity payable for the  life of his  or her spouse equal to 50% of the
         amount of  the annuity  payable  during the  life of  the  Participant;
         provided,  however,  that  in  the  case  of a  Participant  who is not
         married, a Qualified Joint and Survivor  Annuity means an annuity which
         is payable for the life of the Participant.  "Alternate Qualified Joint
         and Survivor Annuity" means an annuity which is payable for the life of
         the Participant with a  survivor annuity payable for the life of his or
         her spouse equal to  75% or 100% of the  amount of the  annuity payable
         during the life of the Participant.

                 (qq)  "Qualified  Preretirement  Survivor  Annuity"   means  an
         annuity which is  payable for the life of the  Participant's  surviving
         spouse.

                 (rr)  "Reemployment  Date"  means  the  date  an Employee first
         performs an Hour of Service following a Period of Severance.

                 (ss)  "Retirement"  means  the  termination  of a Participant's
         employment  with an Employer or  Affiliated Company  on or after his or
         her Normal Retirement Date  for any reason other than death or transfer
         to the employment of another Employer or Affiliated Company.

                 (tt)  "Rollover  Account"  means  the  account  established and
         maintained under this Plan by  the Committee to record a  Participant's
         interest  under  this  Plan   attributable  to  (i)  Rollover  Property
         contributed by such  Participant to this  Plan pursuant to Section 3.9,
         (ii) any  amounts credited to his  or her Rollover Contribution Account
         under the Superseded Plan as in effect on September 30, 1997, and (iii)
         any amounts  credited to  his or her  Rollover  Account  under the Mesa
         Profit-Sharing Plan as in effect on September 30, 1997.

                 (uu)  "Rollover  Property"  means  property the  value of which
         would be excluded from the gross income of the transferor under Section
         402(c), 403(a)(4) or 408(d)(3) of the Code if transferred to the Plan.

                 (vv) "Superseded Plan" means the Pioneer Natural Resources USA,
         Inc. 401(k) Plan,  as in effect from  time to  time prior to January 1,
         2002.  Prior to August 7,  1997,  the Superseded  Plan was known as the
         Retirement Savings Plan for Employees of Parker & Parsley.


                                       -8-








                 (ww)  "Total  Pre-Tax  Contributions"  means  the  sum  of  the
         Pre-Tax Contributions and Pre-Tax Bonus Contributions made on behalf of
         a Participant.

                 (xx)  "Trust"  means  the  trust  fund  established pursuant to
         Section 4.1.

                 (yy)  "Trustee"  means the  individual or  corporate trustee or
         trustees  from time to time appointed and acting as trustee or trustees
         of the Trust established pursuant to the Plan.

                 (zz)  "Valuation Date" means each business day.

                 (aaa)  The "Vested  Interest" of a  Participant  means the then
         vested  portion  of  the  amount  credited  to  the  Accounts  of  such
         Participant at the particular point in time in question.

         Section 1.2 Construction.  The titles to the  Articles and the headings
of the Sections in this Plan are placed herein for convenience of reference only
and in case of any conflict the text of this instrument, rather than such titles
or headings,  shall control.  Whenever a noun or pronoun is used in this Plan in
plural form and there  be only one person or entity within the scope of the word
so used, or in singular form and  there be more than one person or entity within
the scope  of the  word so used,  such noun or  pronoun shall  have a  plural or
singular meaning as appropriate under the circumstance.


                                   ARTICLE II.

                          ELIGIBILITY AND PARTICIPATION

         Section 2.1 Eligibility. Each participant in either the Superseded Plan
or the Matching Plan on December 31,  2001,  shall continue as a  Participant in
this Plan as of January 1, 2002.  Each other Covered Employee shall be  eligible
to become a participant in this Plan on the first day of the first pay period in
the calendar  month next following  his or her Employment Date. If a Participant
ceases  to be a  Covered Employee,  such Participant shall  remain a Participant
under  this Plan  but no contributions  shall be made to the  Plan on his or her
behalf while he or she is not a Covered Employee.

         Section 2.2 Participation.  Each  Covered  Employee  who is eligible to
participate  in the Plan may elect,  on a form  prescribed by the  Committee, to
participate in this  Plan on  the first  day of  the first  pay  period  in  the
calendar month following the filing of such election. Any Participant who ceases
to be a Covered Employee shall thereupon cease to  be eligible to participate in
the Plan;  provided,  however,  that  if  any  such  Participant  is  thereafter
reemployed as a Covered Employee, he or she shall be eligible to elect to resume
participating in the Plan as of the date of such reemployment.


                                       -9-








                                  ARTICLE III.

                   CONTRIBUTIONS, LIMITATIONS AND FORFEITURES

         Section 3.1 Pre-Tax and Pre-Tax Bonus Contributions.

                  (a)  Each  Participant may  elect to have his or her  Employer
         make a Pre-Tax Contribution to  the Plan on his or her  behalf for each
         pay period  in an amount equal to at least 2% and not in excess of 30%,
         of his  or her  Basic  Compensation  for  that  pay  period.  All  such
         contributions shall be made by uniform payroll deductions pursuant to a
         compensation reduction agreement  which authorizes  the Employer to pay
         such contributions to the Trustee on behalf of the Participant.

                  (b) In addition, each Participant may elect to have his or her
         Employer  make a Pre-Tax  Bonus Contribution  to the Plan on his or her
         behalf in an  amount equal  to at least 2% and not in excess of 30%, of
         the bonus payable to such Participant under the Employer's annual bonus
         program.

                  (c) The  Committee  shall  establish  and  maintain  for  each
         Participant  a Pre-Tax Account.  All  amounts  attributable to  Pre-Tax
         Contributions and  Pre-Tax  Bonus Contributions made  by an Employer on
         behalf  of such  Participant  pursuant  to  this  Section 3.1  shall be
         credited to such Participant's Pre-Tax Account.

                  (d) A Participant may change the applicable percentage of such
         payroll (or  bonus)  deductions as  of the  first  day of the first pay
         period  of  any  calendar  month,  or at  any  time  suspend his or her
         election   to  have   Pre-Tax  Contributions   and/or   Pre-Tax   Bonus
         Contributions made  to the Plan,  provided that written  notice of such
         change  or  suspension  is  delivered  to  the  Committee  within  such
         reasonable period of  time prior  to the effective date  thereof as the
         Committee may require.

                  (e)   Any   provision   of   this   Plan   to   the   contrary
         notwithstanding,  the amount of Total Pre-Tax Contributions made to the
         Plan by an Employer on behalf of a Participant for a calendar year when
         added to the amount of any  other elective deferrals within the meaning
         of Section 402(g)(3) of the Code made  with respect to such Participant
         pursuant to any  other plan, contract or  arrangement of an Employer or
         Affiliated  Company for such  calendar year shall not exceed the dollar
         limitation contained in Section 402(g) of  the Code in  effect for such
         calendar year, except to the extent permitted under  Section 3.3 of the
         Plan and Section 414(v) of the Code,  if applicable.  If the percentage
         of Total Pre-Tax Contributions elected by a Participant results in such
         contributions equaling the  limitation imposed by Section 402(g) of the
         Code prior  to the  end of a  calendar  year, then such election by the
         Participant  shall  be  deemed  to be  an  election to  make  After-Tax
         Contributions  to the  Plan  at the  time  such  dollar  limitation  is
         exceeded  unless   otherwise  elected  by  the  Participant;  provided,
         however, that to the extent permitted by Section 414(v) of the Code and
         the  regulations thereunder,  such election shall first be deemed to be


                                      -10-








         an election  to make  Catch-Up Contributions to the Plan.  In the event
         such contributions are not timely recharacterized and the limitation of
         this  subsection  (e) is exceeded with  respect to a  Participant for a
         Plan Year,  then if  such  Participant  notifies  the Committee  of the
         amount of Total Pre-Tax  Contributions that  exceeded  such  limitation
         within such  reasonable period  of time  prior to  the  first  April 15
         following  such  year as the  Committee may  prescribe in its  absolute
         discretion,  the  excess  Total  Pre-Tax  Contributions (along with any
         income  allocable  thereto for  such year,  but  not for the gap period
         following such year) shall be distributed to such  Participant no later
         than such  April 15.  A Participant will be deemed  to have so notified
         the Committee of excess elective deferrals for a calendar year if,  and
         only to the  extent,  such  excess  arises on  account of Total Pre-Tax
         Contributions  made to this Plan  and elective  deferrals made to other
         plans maintained by an Employer or Affiliated Company for such calendar
         year.  Any such excess  deferrals distributed to a Participant shall be
         distributed first from any Pre-Tax Bonus Contributions and then, to the
         extent necessary, from  Pre-Tax Contributions.  The income allocable to
         any excess  Total Pre-Tax Contributions for a Participant for a taxable
         year shall be  determined by multiplying the amount of income allocable
         to such Participant's Pre-Tax Account for such year by a fraction,  the
         numerator of which is the amount of excess Total Pre-Tax  Contributions
         for such  year and  the denominator  of which  is the sum of the amount
         credited to such Participant's  Pre-Tax Account  as of the beginning of
         such  year  plus  the   amount of   such  Participant's  Total  Pre-Tax
         Contributions for such year.  If any  portion of a Pre-Tax Contribution
         is  distributed or  recharacterized pursuant  to this  subsection,  any
         portion  of a  Matching  Contribution  (along with any income allocable
         thereto)  made to  this Plan  for such  Participant  that  matches  the
         distributed or recharacterized Pre-Tax Contribution shall be forfeited.

                  (f)  An  Employer  may  amend  or  revoke  any   Participant's
         compensation reduction agreement at any time during a Plan Year if such
         amendment or  revocation is deemed  by such Employer to be necessary or
         appropriate to ensure that all applicable limitations,  including those
         set forth in Sections 3.1(e), 3.7 and 10.3 are met for such year.

         Section 3.2  Matching  Contributions.  For each pay period an  Employer
shall make to the Plan for  each Participant in its  employ and allocate to such
Participant's  Employer Account a  Matching Contribution equal to 200 percent of
the  Pre-Tax Contributions made  by the  Employer on  such  Participant's behalf
during  such  pay  period  which  are  not in  excess of  five  percent  of such
Participant's  Basic  Compensation  for  such  pay  period.  The Committee shall
establish and maintain an  Employer Account for each Participant.  All  Matching
Contributions made for  a Participant pursuant to this Section shall be credited
to such Participant's Employer Account.

         Section 3.3  Catch-Up Contributions. All  Employees who are eligible to
make Pre-Tax Contributions to this Plan and who have  attained age 50 before the
close of the Plan Year shall be eligible to make Catch-Up Contributions pursuant
to a compensation reduction agreement and in accordance with, and subject to the
limitations of, Section 414(v) of the Code and the regulations thereunder.  Such
Catch-Up  Contributions  shall not be  taken into  account for  purposes  of the
provisions of the Plan implementing the required limitations  of Sections 402(g)
and 415 of the Code.  The Plan shall not be  treated as  failing to  satisfy the


                                      -11-








provisions  of the Plan  implementing  the  requirements  of Section  401(k)(3),
401(k)(11),  401(k)(12), 410(b), or 416 of the Code, as applicable, by reason of
the making of such Catch-Up Contributions.

         Section 3.4 After-Tax Contributions.

                  (a)  Each   Participant   may  elect  to  make  an   After-Tax
         Contribution  to the Plan  for each pay period in an amount which, when
         combined with any  Pre-Tax Contributions  made to the Plan on behalf of
         such  Participant for  that  pay  period,  shall not  exceed 50% of the
         Compensation of such Participant during such pay period.

                  (b)  The  Committee  shall  establish  and  maintain  for each
         Participant an After-Tax Account. All amounts attributable to After-Tax
         Contributions made  by a Participant pursuant to this Section 3.4 shall
         be credited to such Participant's After-Tax Account.

                  (c) After-Tax Contributions may be made in whole or in part by
         uniform payroll  deductions  which  the  Participant  shall in  writing
         authorize his or her Employer to withhold and pay over to the  Trustee.
         A Participant may  change  the  applicable  percentage of  such payroll
         deductions as of the first day of the  first pay period of any calendar
         month,  or at any  time suspend his or her  election to  have After-Tax
         Contributions  made to the Plan,  provided that written  notice of such
         change  or  suspension  is  delivered  to  the  Committee  within  such
         reasonable period  of time prior  to the effective  date thereof as the
         Committee may require.

                  (d) At any time and from time to time during a Plan Year,  the
         Company may limit the After-Tax  Contributions made by a Participant or
         suspend the  making of  After-Tax Contributions  if the Company, in its
         absolute  discretion,  deems  such  to be  necessary or  appropriate to
         ensure  that all  applicable limitations,  including those set forth in
         Sections 3.7 and 10.3, are satisfied for such year.

         Section 3.5 Payment of Contributions.  Pre-Tax Contributions,  Catch-Up
Contributions and After-Tax Contributions made to the Plan by an Employer for or
on behalf of Participants  for a pay period shall be paid to the Trustee in cash
as soon as  practicable  after such pay period ends,  but no later than the 15th
business day after the end of the month in which such pay period  ends.  Pre-Tax
Bonus  Contributions made to the Plan on behalf of Participants shall be paid to
the Trustee in cash as soon as practicable  after the bonus payment is made, but
no later than the 15th day of the month after the end of the month in which such
bonus payment is made. Matching  Contributions made to the Plan for a pay period
shall be paid to the Trustee as soon as  practicable,  but no later than 30 days
after the end of the month in which such pay period ends.

         Section 3.6 Return of  Employer  Contributions.  Contributions  made to
this Plan are conditioned  upon being currently  deductible under Section 404 of
the Code.  Any provision of this Plan to the contrary  notwithstanding,  upon an
Employer's  request,  any such contribution or portion thereof made to this Plan
by  such  Employer  which  (i)  was  made  under  a  mistake  of  fact  which is

                                      -12-








subsequently discovered,  or (ii) is disallowed as a deduction under Section 404
of the Code,  shall be  returned to such  Employer to the extent not  previously
distributed to Participants or their beneficiaries;  provided, however, that the
amounts  returnable to an Employer  pursuant to this Section shall be reduced by
any Trust losses  allocable  thereto and shall be returned to such Employer only
if such  return is made  within  one year  after  the  mistaken  payment  of the
contribution or the date of the  disallowance of the deduction,  as the case may
be.  Except as provided in this  Section,  no  contribution  made by an Employer
pursuant to this Plan shall ever revert to or be recoverable by any Employer.

         Section 3.7  Nondiscrimination Testing.

                 (a) Any provision of this Plan to the contrary notwithstanding,
         if for any Plan  Year the actual deferral  percentage for  the group of
         Highly   Compensated  Employees  eligible  to  elect  to  have  Pre-Tax
         Contributions or Pre-Tax Bonus Contributions made during such Plan Year
         fails to satisfy one of the following tests:

                           (1) the actual deferral  percentage for said group of
                  Highly Compensated  Employees is not  more than 1.25 times the
                  actual deferral percentage for the preceding Plan Year for all
                  Non-Highly Compensated Employees eligible during the preceding
                  Plan Year  to elect  to have  Pre-Tax Contributions or Pre-Tax
                  Bonus Contributions made on their behalf, or

                           (2) the excess of the  actual deferral percentage for
                  said group  of Highly  Compensated  Employees  over the actual
                  deferral  percentage  for  the  preceding  Plan  Year  for all
                  Non-Highly Compensated Employees eligible during the preceding
                  Plan Year to elect  to have  Pre-Tax  Contributions or Pre-Tax
                  Bonus Contributions made on their  behalf is not more than two
                  percentage points, and the actual deferral percentage for said
                  group of  Highly Compensated  Employees is  not more  than two
                  times  the actual  deferral percentage  for the preceding year
                  for all  Non-Highly Compensated  Employees eligible during the
                  preceding Plan  Year to elect to have Pre-Tax Contributions or
                  Pre-Tax Bonus Contributions made on their behalf,

         then the actual deferral  percentage of Participants who are members of
         said group of Highly Compensated Employees shall be reduced by reducing
         the actual deferral percentages  of the  Highly  Compensated  Employees
         with the largest individual actual deferral percentages  to the largest
         uniform  actual   deferral  percentage   (commencing  with  the  Highly
         Compensated  Employee  with the  largest actual deferral percentage and
         reducing his or her actual deferral  percentage to the extent necessary
         to satisfy  one of  the above tests or  to lower such  actual  deferral
         percentage to the actual deferral percentage of the  Highly Compensated
         Employee  with  the  next  largest  actual  deferral  percentage,   and
         repeating this process  as necessary) that permits  the actual deferral
         percentage for  said group of  Highly Compensated Employees  to satisfy
         one of said  tests.  For purposes  of this  subsection  (a),  the  term
         "actual deferral percentage"  for a specified  group of Employees for a


                                      -13-








         Plan Year  means the  average of the ratios  (calculated separately for
         each  Employee  in  such group and  after any  distributions  to Highly
         Compensated Employees  required to  satisfy the  limitation  imposed by
         Section 402(g)  of the  Code) of  (i) the  aggregate  amount  of  Total
         Pre-Tax  Contributions made  on behalf  of each  such Employee for that
         year, to (ii) the amount of such Employee's  Compensation for that year
         or, in the  Committee's discretion,  only for such portion of that year
         during which the  Employee was eligible to participate in the Plan.  If
         two or  more  plans that  include  cash or  deferred  arrangements  are
         considered  as one  plan for purposes of Section 401(a)(4) or 410(b) of
         the Code  (other than  for purposes  of the  average benefit percentage
         test),  the cash or deferred arrangements  included in such plans shall
         be treated as one arrangement for purposes of this subsection (a). If a
         Highly  Compensated Employee is a  participant in  two or  more cash or
         deferred arrangements of an Employer,  then for purposes of determining
         the actual  deferral ratio of such Employee,  all such cash or deferred
         arrangements (other than those that may not be permissively aggregated)
         shall be treated as one cash or deferred arrangement.

                  (b) The aggregate  amount of any  Total  Pre-Tax Contributions
         which may not  be credited to Pre-Tax Accounts for a  Plan Year because
         of  the  limitation  contained  in  subsection  (a)  of  this  Section,
         calculated by adding together the dollar amount of excess contributions
         determined in  subsection (a) of  this Section for each affected Highly
         Compensated  Employee,  shall  be  distributed  to  Highly  Compensated
         Employees (along with any income allocable to such excess contributions
         for such  Plan Year,  but not  for the  gap period following  such Plan
         Year) no later than the last day of the Plan Year immediately following
         such year  (and, if practicable,  within 2 1/2  months after the end of
         such year). The amount of Total Pre-Tax Contributions to be distributed
         to a particular Highly Compensated  Employee shall be determined on the
         basis of the amount of Total Pre-Tax Contributions made for each Highly
         Compensated  Employee  commencing with the  Highly Compensated Employee
         with the largest  amount of  Total Pre-Tax  Contributions for such Plan
         Year and reducing his  or her Total Pre-Tax Contributions to the extent
         necessary  to  lower  such  amount  to  the  amount  of  Total  Pre-Tax
         Contributions of  the Highly Compensated Employee with the next largest
         amount of  Total Pre-Tax Contributions,  and repeating  this process as
         necessary to distribute such aggregate amount; provided,  however, that
         the amount of Total Pre-Tax Contributions to be distributed shall first
         be reduced  by any  excess  deferrals  to  be  distributed  pursuant to
         Section  402(g) of  the Code.  Any such excess  contribution  shall  be
         distributed  first  from any  Pre-Tax  Contributions  and then,  to the
         extent necessary,   from  Pre-Tax  Bonus   Contributions.   The  income
         allocable to any such excess contributions for a Participant for a Plan
         Year shall be determined  by multiplying the amount of income allocable
         to such Participant's Pre-Tax Account for such year by a fraction,  the
         numerator  of which is the  amount of the excess contributions for such
         year and the denominator  of which is the sum of the amount credited to
         such Participant's  Pre-Tax Account  as of  the beginning  of such year
         plus the amount  of such Participant's Total Pre-Tax  Contributions for
         such year.  Any provision of this Plan to the contrary notwithstanding,
         Total Pre-Tax  Contributions otherwise  distributable  pursuant to this
         subsection  (b) to a  Participant  who is  eligible  to  make  Catch-Up


                                      -14-








         Contributions to the  Plan shall,  to the  extent permitted  by Section
         414(v)  of the  Code and  the regulations  thereunder,  be treated as a
         Catch-Up Contribution. If any portion of a Pre-Tax Contribution made by
         an  Employer  on  behalf  of  a  Participant  is  distributed  to  such
         Participant or  is treated as  a Catch-Up Contribution  pursuant to the
         foregoing  provisions of this subsection (b), any portion of a Matching
         Contribution  (along with any income  allocable  thereto) made for such
         Participant  that  matches  the  distributed  Pre-Tax  Contribution  or
         recharacterized Catch-Up Contribution shall be forfeited.

                 (c) Any provision of this Plan to the contrary notwithstanding,
         if for  any Plan  Year the  contribution  percentage for  the  group of
         Highly Compensated  Employees  eligible to  receive  an  allocation  of
         Matching Contributions or to make  After-Tax  Contributions to the Plan
         for such Plan Year fails to satisfy one of the following tests:

                           (1) the contribution  percentage  for  said  group of
                  Highly Compensated Employees is not  more than  1.25 times the
                  contribution  percentage  for the  preceding Plan Year for all
                  Non-Highly  Compensated  Employees  eligible for the preceding
                  Plan Year to receive an allocation of  Matching  Contributions
                  or make After-Tax Contributions, or

                           (2) the excess  of the  contribution  percentage  for
                  said  group  of   Highly   Compensated   Employees  over   the
                  contribution  percentage for  the preceding  Plan Year for all
                  Non-Highly  Compensated  Employees eligible for  the preceding
                  Plan Year to  receive an  allocation of Matching Contributions
                  or   make  After-Tax  Contributions  is  not  more  than   two
                  percentage  points,  and the  contribution percentage for said
                  group of  Highly  Compensated  Employees is  not more than two
                  times the contribution percentage for the  preceding Plan Year
                  for all  Non-Highly  Compensated  Employees  eligible  for the
                  preceding  Plan  Year to  receive  an  allocation  of Matching
                  Contributions or make After-Tax Contributions,

         then the  contribution  percentage of Participants  who are  members of
         said group of Highly Compensated Employees shall be reduced by reducing
         the contribution  percentages of the Highly Compensated  Employees with
         the largest  individual contribution percentages to the largest uniform
         contribution  percentage   (commencing   with  the  Highly  Compensated
         Employee  with the largest contribution  percentage and reducing his or
         her contribution  percentage to the  extent necessary to satisfy one of
         the  above  tests  or  to  lower such  contribution  percentage  to the
         contribution  percentage  of the  Highly Compensated Employee  with the
         next  largest contribution  percentage,  and repeating  this process as
         necessary) that  permits the contribution percentage for  said group of
         Highly Compensated Employees to satisfy one of said tests. For purposes
         of this  subsection  (c),  the  term  "contribution  percentage"  for a
         specified group  of Employees for  a Plan Year means the average of the
         ratios (calculated separately for each Employee in such group and after
         application  of the  reduction  provisions of  subsection  (a)  and the
         forfeiture provisions of subsection  (b) of this  Section) of  (i)  the
         aggregate amount  of After-Tax Contributions and Matching Contributions


                                      -15-








         made by or  for such Employee  (and,  at the election of the Committee,
         the Total Pre-Tax  Contributions made on  behalf of  such Employee) for
         that year,  to (ii) the amount of such Employee's Compensation for that
         year or,  in the Committee's discretion,  only for such portion of that
         year during which the Employee was eligible to participate in the Plan.
         If two  or more  plans to  which  matching  contributions  or  employee
         after-tax  contributions  are  made  are  considered as  one  plan  for
         purposes of Section 410(b) of the Code  (other than for purposes of the
         average  benefit percentage  test),  such plans shall be treated as one
         plan for purposes of determining  the contribution percentages for this
         subsection (c).  If a  Highly Compensated Employee  is a participant in
         two or more plans to which matching contributions or employee after-tax
         contributions  are   made,   then  for  purposes  of  determining   the
         contribution ratio of such Employee,  all such  plans (other than those
         that may not be permissively aggregated) shall be treated as one plan.

                  (d) The aggregate  amount of  any  Matching  Contributions and
         After-Tax  Contributions  which  may  not be credited to  Participant's
         Accounts  for a  Plan  Year  because  of the  limitation  contained  in
         subsection  (c)  of this  Section,  calculated  by adding  together the
         dollar  amount  of   excess  aggregate   contributions   determined  in
         subsection  (c) of this  Section for each  affected Highly  Compensated
         Employee,  shall be forfeited if forfeitable,  but if not  forfeitable,
         distributed to such Highly Compensated Employees (along with any income
         allocable to such  excess aggregate  contributions for such  Plan Year,
         but not for the  gap period following such Plan Year) no later than the
         last day  of the  Plan Year  immediately  following  such year (and, if
         practicable,  within  2 1/2 months  after  the end of  such year).  The
         amount to be  distributed  to a  particular Highly Compensated Employee
         shall   be  determined  on  the   basis  of  the  amount  of   Matching
         Contributions  and  After-Tax  Contributions  made by  or for each such
         Highly Compensated  Employee  commencing  with the  Highly  Compensated
         Employee  with  the  largest  amount  of  Matching  Contributions   and
         After-Tax  Contributions  for such Plan Year and reducing  first his or
         her   After-Tax  Contributions   and  then,   if  necessary,   Matching
         Contributions to the extent necessary to lower such total amount to the
         amount of  Matching Contributions and  After-Tax  Contributions  of the
         Highly  Compensated Employee with the next  largest amount of  Matching
         Contributions  and After-Tax Contributions,  and repeating this process
         as necessary to distribute such aggregate amount.  The income allocable
         to any such excess aggregate contributions for a Participant for a Plan
         Year shall be determined  by multiplying the amount of income allocable
         to such Participant's Employer Account or After-Tax Account,  whichever
         is applicable,  for such year by a fraction,  the numerator of which is
         the amount of the excess  aggregate contributions for such year and the
         denominator  of  which  is  the  sum  of  the  amount  credited to such
         Participant's  Employer  Account  or  After-Tax  Account,  whichever is
         applicable,  as of  the beginning  of such  year  plus  the  amount  of
         Matching Contributions or After-Tax Contributions, as applicable,  made
         for such Participant for such year.

                  (e)   Any   provision  of   this  Section   to  the   contrary
         notwithstanding, the Company in its discretion may cause the provisions
         of subsections (a) and (c)  of this Section to be satisifed without use

                                      -16-








         of the  corrective provisions  set forth in  subsections (b) and (d) of
         this  Section   by   requiring   each  Employer  to  make  a  qualified
         non-elective contribution  and/or a  qualified matching contribution to
         the Plan  to be  allocated  to the  Pre-Tax Accounts (with respect to a
         contribution  intended  to  be  taken  into  account  for  purposes  of
         determining the  actual deferral percentage pursuant to subsection (a))
         or the Employer Accounts (with respect to a contribution intended to be
         taken  into  account  for  purposes  of  determining  the  contribution
         percentage  pursuant to  subsection (c)) of those Participants who were
         Non-Highly Compensated  Employees  in the  employ of  (or on authorized
         leave of absence from) an Employer on the last day of such Plan Year. A
         qualified  non-elective contribution shall be allocated to the eligible
         Participants in the proportion that the Basic Compensation of each such
         eligible Participant  while both a  Participant and a  Covered Employee
         during that year bears to the  Basic Compensation of all  such eligible
         Participants  while both Participants and Covered Employees during that
         year.  A  qualified  matching contribution  shall be  allocated  to the
         eligible Participants in the proportion that the Pre-Tax  Contributions
         made with respect to each such eligible  Participant for such Plan Year
         bears to  the  Pre-Tax  Contributions  made with  respect  to  all such
         eligible Participants for such Plan Year.

                 (f) Any provision of this Plan to the contrary notwithstanding,
         the  determination   of  the   actual   deferral  percentage  and   the
         contribution  percentage  required   by  this  Section  for  Non-Highly
         Compensated  Employees  for the  preceding Plan  Year shall be  made in
         accordance  with  Sections  401(k)  and  401(m) of  the  Code  and  any
         regulations or other authorities issued thereunder.

         Section 3.8  Application of Forfeitures.  As soon as  practicable after
the  valuation  of all  Accounts  at the  end of each  Plan  Year,  all  amounts
forfeited  during that Plan Year shall first be applied to restore any forfeited
Accounts  required to be restored  pursuant  to  Sections  6.5 and 6.8,  and any
forfeitures  in excess of the amount  needed to restore any such  Account may be
applied to pay  administrative  expenses in  accordance  with  Section  7.4. Any
remaining  forfeitures  for such Plan Year, if any,  shall be used to reduce the
amount of the earliest subsequent  Matching  Contributions an Employer otherwise
would be required to make to the Plan.

         Section 3.9  Rollover Contributions. With the consent of and subject to
such  reasonable  conditions and limitations as may be imposed by the Committee,
any Covered  Employee  (regardless  of whether he or she is a  Participant)  may
contribute  Rollover Property in cash to the Plan. Each contribution of Rollover
Property  shall be credited  to the  Covered  Employee's  Rollover  Account.  An
Employee  who is not a  Participant,  but for whom a  Rollover  Account is being
maintained,  shall be accorded all of the rights and privileges of a Participant
under  the Plan  except  that no  contributions  (other  than  contributions  of
Rollover  Property)  shall be made for or on behalf of such Employee until he or
she meets the eligibility and participation  requirements of Article II. Subject
to the  Committee's  consent,  the Plan will accept (i) a direct  rollover of an
eligible rollover  distribution  from: (A) a qualified plan described in Section
401(a) or 403(a) of the Code, including after-tax employee contributions, (B) an
annuity contract  described in Section 403(b) of the Code,  excluding  after-tax
employee contributions, or (C) an eligible plan under Section 457(b) of the Code


                                      -17-








which is maintained by a state,  political subdivision of a state, or any agency
or  instrumentality  of a state or political  subdivision of a state;  or (ii) a
Participant  contribution  of an  eligible  rollover  distribution  from:  (A) a
qualified plan described in Section 401(a) or 403(a) of the Code, (B) an annuity
contract  described in Section 403(b) of the Code, or (C) an eligible plan under
Section 457(b) of the Code which is maintained by a state, political subdivision
of a state, or any agency or instrumentality of a state or political subdivision
of a state.  The Plan will accept a  Participant  rollover  contribution  of the
portion  of a  distribution  from an  individual  retirement  account or annuity
described in Section  408(a) or 408(b) of the Code that is eligible to be rolled
over and would otherwise be includible in gross income of the Participant.


                                   ARTICLE IV.

                            TRUST FUND AND VALUATIONS

         Section 4.1  Trust and Trustee.  All of the  contributions  paid to the
Trustee pursuant to this Plan and the Superseded Plan,  together with the income
therefrom  and the  increments  thereof,  shall be held in trust by the  Trustee
under the terms and  provisions  of the  separate  trust  agreement  between the
Trustee and the  Company,  a copy of which is attached  hereto and  incorporated
herein by this  reference for all purposes,  establishing  a trust fund known as
the PIONEER  NATURAL  RESOURCES  USA,  INC.  401(k) AND  MATCHING  TRUST for the
exclusive benefit of the Participants and their beneficiaries.

         Section 4.2  Trust  Investment  Options.  All  amounts  credited  to  a
Participant's  Accounts  may be invested in Pioneer  Stock and/or one or more of
the Investment Funds at the direction of such Participant in accordance with the
provisions of this Section.  The assets of the Trust (other than Pioneer  Stock)
shall be divided into such number and kind of separate  and distinct  Investment
Funds as the Committee in its absolute  discretion  shall authorize from time to
time. The assets of the Trust allocated to a particular Investment Fund shall be
invested by the Trustee and/or one or more investment managers duly appointed in
accordance with the provisions of the trust agreement establishing the Trust, as
the case may be, in such  type of  property  acceptable  to the  Trustee  as the
Trustee is directed to acquire and hold for such Investment  Fund. Upon becoming
a  Participant  in the  Plan,  each  Participant  shall  direct,  in the  manner
prescribed  by the  Committee  in its  absolute  discretion,  that  all  amounts
credited to his or her Accounts under the Plan shall be invested,  in percentage
multiples  authorized by the Committee,  in one or more of the Investment Funds.
Subject to such  conditions  and  limitations  as the  Committee in its absolute
discretion may prescribe from time to time for  application to all  Participants
on a uniform  basis, a Participant  may change his or her  investment  direction
with respect to future  contributions  or redirect the investment of the amounts
credited to his or her Accounts provided that notice of such change is delivered
to or in the manner directed by the Committee  within such reasonable  period of
time prior to the effective date thereof as the Committee may require.


                                      -18-








         Section 4.3  Valuation and Adjustment of Accounts. As of each Valuation
Date,  the Trustee  shall  determine  the fair market value of all assets of the
Trust with the value of the  assets of each  Investment  Fund  being  separately
determined.  On the  basis  of  such  valuations  and in  accordance  with  such
procedures as may be specified from time to time by the  Committee,  the portion
of each Account  invested in a particular  Investment  Fund shall be adjusted by
the  Committee to reflect its  proportionate  share of the income  collected and
accrued,  realized  and  unrealized  profits and losses,  expenses and all other
transactions  attributable to that particular  Investment Fund for the valuation
period then ended. All cash dividends,  stock dividends,  stock splits and other
amounts  received  by the  Trustee  with  respect to  Pioneer  Stock held for an
Account (including the forfeiture account  established  pursuant to Section 6.5)
shall be credited to such Account. The amount of any distribution, withdrawal or
forfeiture  shall  be  determined  on the  basis of the  most  recent  valuation
preceding the date of  distribution,  withdrawal or forfeiture,  as the case may
be.


                                   ARTICLE V.

                                     VESTING

         Section 5.1   Fully  Vested  Accounts.   The   amounts  credited  to  a
Participant's  After-Tax Account,  Mesa After-Tax Account, Mesa Premium Account,
Mesa Profit-Sharing Account, Pre-Tax Account, Prior Plan Employer Account, Prior
Plan Pre-Tax Account, and Rollover Account shall be fully vested at all times.

         Section 5.2  Vesting of Employer Account.

                  (a) The amounts credited  to the Employer Account and Matching
         Plan Account  of a  Participant  shall  become  fully  vested  upon the
         occurrence of any of the  following events while  the Participant is in
         the employ  of (or on  authorized leave of absence from) an Employer or
         Affiliated Company:  (i)  the  completion of  an Hour of Service by the
         Participant on  or after the date  he  or she attains age 60,  (ii) the
         Participant's death,  or (iii) the  Participant's Permanent Disability.
         Unless sooner vested pursuant to the preceding sentence,  and except as
         provided in subsection (b) of this Section and Section 5.3, the amounts
         credited to a Participant's Employer Account and Matching  Plan Account
         shall vest in accordance with the following schedule:


                     Period of Service
                  Completed by Participant             Percentage Vested
                  ------------------------             -----------------
                                                 
                      Less than 1 year                        None
                           1 year                              25%
                           2 years                             50%
                           3 years                             75%
                      4 or more years                          100%
-19- (b) If a Participant makes an in-service withdrawal under Section 6.6 from his or her Employer Account at a time when the Participant is not fully vested, the Participant's vested amount in such account on any date thereafter shall be an amount X determined by the following formula: X = P(AB + D) - D. For purposes of this formula, P is the Participant's vested percentage under the Plan's vesting schedule on the relevant date, AB is the account balance on the relevant date and D is the amount of the Participant's in-service withdrawal. Section 5.3 Special Vesting Provisions. (a) Any provision of this Plan to the contrary notwithstanding, the amounts credited to the Employer Account and/or Matching Plan Account of a Participant who is specifically designated by the Vice President Administration of the Company as being involuntarily terminated in connection with the divestiture program and corporate restructuring announced on February 10, 1998, shall become fully vested and nonforfeitable on the date of such involuntary termination. (b) Any provision of this Plan to the contrary notwithstanding, the amounts credited to the Employer Account and/or Matching Plan Account of a Participant who is specifically designated by the Vice President Administration of the Company as being involuntarily terminated in connection with the corporate restructuring announced on November 11, 1998, shall become fully vested and nonforfeitable on the date of such involuntary termination. (c) Any provision of this Plan to the contrary notwithstanding, the amounts credited to the Matching Plan Account of a Participant who is specifically designated by the Vice President Administration of the Company as being involuntarily terminated in connection with the sale by the Company of the Plum Creek Plant, Leon County, Texas, to a third party shall become fully vested and nonforfeitable on the date of such involuntary termination. (d) Any provision of this Plan to the contrary notwithstanding, the amounts credited to the Matching Plan Account of a Participant who is specifically designated by the Vice President - Administration and Risk Management of the Company as being involuntarily terminated in connection with one of the following events shall become fully vested and nonforfeitable on the date of such involuntary termination: (i) the transfer of operations of the Howard Parker/Joe Parsley Joint Venture wells to a third party; (ii) the sale of Iatan Field properties to a third party; -20- (iii) the reorganization of Offshore Operations effective September 22, 1999; (iv) the restructuring and consolidation of the Domestic Reservoir Engineering Department effective February 15, 2000; or (v) the sale of NationsBank building, Midland, Texas. (e) Any provision of this Plan to the contrary notwithstanding, the amounts credited to the Matching Plan Account of a Participant who is specifically designated by the Vice President - Administration and Risk Management of the Company as being involuntarily terminated in connection with the implementation of the TOW Production System technology, shall become fully vested and nonforfeitable on the date of such involuntary termination. ARTICLE VI. VALUATIONS, DISTRIBUTIONS AND WITHDRAWALS Section 6.1 Time of Distribution. (a) Distribution to a Participant or beneficiary under this Article shall be made or commence being made no later than 60 days after the close of the Plan Year in which the latest of the following occurs: (i) the Participant's Normal Retirement Date, (ii) the tenth anniversary of the year in which the Participant commenced participation in the Plan, or (iii) the Participant's separation from the employment of an Employer for any reason other than his or her transfer to the employment of another Employer or Affiliated Company. (b) Any provision of this Plan to the contrary notwithstanding, in the case of a Participant who is a five-percent owner (as defined in Section 416(i) of the Code), distribution to such Participant under the Plan shall be made or commence being made no later than April 1 of the calendar year following the calendar year in which the Participant attains age 70 1/2. Distributions that commence being made pursuant to the preceding sentence to a Participant who has not separated from the employment of an Employer or Affiliated Company shall be made pursuant to Section 6.2 as if the Participant had terminated employment at such time and shall be made in accordance with the minimum distribution requirements of Section 401(a)(9) of the Code and such regulations thereunder as may be applicable from time to time (or for periods prior to the effective date of final regulations under Section 401(a)(9) of the Code, pursuant to the regulations that were proposed on January 17, 2001); provided, however, that if the Participant elects to waive the normal form of payment in accordance with Section 6.2, the alternative form of distribution shall be the minimum amounts required to be distributed pursuant to Section 401(a)(9) of the Code and such -21- regulations thereunder as may be applicable from time to time (or for periods prior to the effective date of final regulations under Section 401(a)(9) of the Code pursuant to regulations that were proposed on January 17, 2001), with any amount remaining upon the termination of the Participant's employment or the death of the Participant to be paid in accordance with Section 6.2 or Section 6.3, whichever is applicable. Further, any other Participant who attained age 70 1/2 prior to January 1, 1999, and who elected to continue to receive distributions prior to such Participant's termination of employment shall be entitled receive an annual distribution in accordance with the preceding sentence (or may elect a larger or smaller amount for such annual distribution) unless and until such Participant revokes such election. Any provision of this Plan to the contrary notwithstanding, no distribution shall be made from this Plan that would violate Section 401(k) of the Code. (c) Subject to the provisions of this Article requiring that distributions and withdrawals be made in the form of an annuity contract, distributions and withdrawals shall be made in cash, except that amounts credited to an Account that are invested in Pioneer Stock may, at the election of the Participant, be distributed in the form of Pioneer Stock with cash in lieu of fractional shares. (d) Any provision of this Plan to the contrary notwithstanding, (i) all distributions from the Plan shall be made in accordance with Section 401(a)(9) of the Code and the regulations thereunder, and (ii) all optional forms of benefit under the Plan, the Superseded Plan, the Matching Plan, the Mesa Premium Plan, and the Mesa Profit-Sharing Plan that are protected benefits under Section 411(d)(6) of the Code shall continue to be optional forms of benefit for Participants to whom such optional forms of benefit apply notwithstanding any subsequent amendment purporting to revise or delete any such optional form of benefit, except to the extent that such optional forms of benefit may be deleted in accordance with applicable law. Section 6.2 Distribution of Retirement and Disability Benefits. (a) Except as otherwise provided in this Section, upon the Retirement or termination of employment on account of Permanent Disability of a Participant, the Vested Interest of such Participant shall be distributed to such Participant by the Trustee at the direction of the Committee in a single distribution; provided, however, that if such Participant's Vested Interest exceeds $5,000, he or she may elect to receive his or her Vested Interest in monthly, quarterly or annual installment distributions over a period of two or more years with the first such installment to be payable within 90 days after the end of the Plan Year in which the Participant's employment terminates. Such installment payments may be made over a period of years not to exceed one or a combination of the following periods: (i) the life of the Participant, (ii) the lives of the Participant and his or her designated beneficiary, (iii) a period certain not extending beyond the life expectancy of the Participant, and (iv) a period certain not extending beyond the joint life and last survivor expectancy of the Participant and his or her designated beneficiary. Any provision of -22- Section 6.3 to the contrary notwithstanding, if a Participant who elected installment payments dies prior to the distribution of the entire amount of his or her Vested Interest, the remaining portion thereof shall be distributed to his or her beneficiary or beneficiaries, as determined in accordance with Section 6.3(a), in a single distribution within 90 days after the end of the Plan Year during which the Participant died. Notwithstanding the foregoing provisions of this Section 6.2, no distribution shall be made upon a Participant's termination of employment on account of Permanent Disability prior to his or her Normal Retirement Date unless (i) such Participant elects to receive such distribution or (ii) such Participant's Vested Interest does not exceed $5,000. For purposes of determining whether the value of a Participant's Vested Interest exceeds or does not exceed $5,000, the value of a Participant's Vested Interest shall be determined without regard to the value of the Participant's Rollover Account. (b) Except as otherwise provided in this subsection (b), upon the Retirement or termination of employment on account of Permanent Disability of a Participant whose Vested Interest exceeds $5,000, such Participant's Matching Plan Account, Mesa Premium Account, Prior Plan Employer Account and Prior Plan Pre-Tax Account shall be distributed to him or her by the Trustee at the direction of the Committee in the form of a Qualified Joint and Survivor Annuity contract to be purchased from a company selected by the Committee and commencing in payment as soon as practicable. Not more than 90 days prior to the date such annuity contract is to commence in payment, the Committee shall provide such Participant with a written explanation of (i) the terms and conditions of the Qualified Joint and Survivor Annuity, (ii) his or her right to make, and the effect of, an election to waive the Qualified Joint and Survivor Annuity form of benefit, (iii) the rights of his or her spouse with respect to the receipt and waiver of the Qualified Joint and Survivor Annuity, and (iv) the right to make, and the effect of, a revocation of an election to waive the Qualified Joint and Survivor Annuity. The written explanation shall be required at least 30 days prior to the date the Qualified Joint and Survivor Annuity contract is to commence in payment; provided, however, that a Participant may elect (with any applicable spousal consent) to waive such requirement if the distribution to the Participant commences no earlier than 8 days after such explanation is provided. After receiving the written explanation, the Participant may elect at any time during the 90-day period ending on the date the annuity contract is to commence in payment to waive the Qualified Joint and Survivor Annuity form of benefit and also may revoke any such election during such period. Any such election to waive a Qualified Joint and Survivor Annuity form of benefit by a married Participant will be effective only if the spouse of such Participant consents in writing within the 90-day period preceding such date to both the election and the optional form of benefit selected by the Participant and such consent is witnessed by a notary public. Any amount payable from the Matching Plan Account, Mesa Premium Account, Prior Plan Employer Account or Prior Plan Pre-Tax Account upon the Retirement or Permanent Disability of a Participant who has elected to waive the Qualified Joint and Survivor Annuity form of benefit as provided above shall be distributed to such Participant by the Trustee at the direction of the Committee in accordance with subsection (a) of this Section; provided, however, that a Participant who has an amount -23- payable from his or her Matching Plan Account or Mesa Premium Account may, in addition to the optional forms available under subsection (a), elect to have such amounts paid in the form of an Alternate Qualified Joint and Survivor Annuity. For purposes of determining whether the value of a Participant's Vested Interest exceeds $5,000, the value of a Participant's Vested Interest shall be determined without regard to the value of the Participant's Rollover Account. Section 6.3 Distribution of Death Benefit. (a) Except as otherwise provided in this Section, upon the death of a Participant, the Vested Interest of such Participant shall be distributed by the Trustee at the direction of the Committee to such Participant's beneficiary or beneficiaries determined in accordance with this subsection (a). Any amount payable under the Plan upon the death of a married Participant shall be distributed to the surviving spouse of such Participant unless such Participant designates otherwise with the written consent of his or her spouse which is witnessed by a notary public. Any amount payable under the Plan upon the death of a Participant who is not married or who is married but has designated, as provided above, a beneficiary other than his or her spouse, shall be distributed to the beneficiary or beneficiaries designated by such Participant. Such designation of beneficiary or beneficiaries shall be made in writing on a form prescribed by the Committee and, when filed with or as directed by the Committee, shall become effective and remain in effect until changed by the Participant by the filing of a new beneficiary designation form with the Committee. If an unmarried Participant fails to so designate a beneficiary, or in the event all of a Participant's designated beneficiaries are individuals who predecease such Participant, then the Committee shall direct the Trustee to distribute the amount payable under the Plan to such Participant's surviving spouse, if any, but if none, to such Participant's estate. All distributions under this subsection (a) shall be made in a single distribution as soon as practicable following a Participant's death; provided, however, that if the Participant's Vested Interest exceeds $5,000, he or she may elect (or if the Participant does not elect, his or her designated beneficiary may elect) that distribution be made in monthly, quarterly or annual installments over a period of two or more years with the first such installment to be payable within 90 days after the end of the Plan Year in which the Participant died. Installment payments may be made only to an individual over a period of years not to exceed one or a combination of the following periods: (i) the life of the Participant's designated beneficiary, or (ii) a period certain not extending beyond the life expectancy of the Participant's designated beneficiary. For purposes of determining whether the value of a Participant's Vested Interest exceeds $5,000, the value of a Participant's Vested Interest shall be determined without regard to the value of the Participant's Rollover Account. (b) Any provision of subsection (a) of this Section to the contrary notwithstanding, except as otherwise provided in this subsection (b), upon the death of a married Participant whose Vested Interest exceeds $5,000, such Participant's Matching Plan Account, Mesa Premium Account, Prior Plan Employer Account and Prior Plan Pre-Tax -24- Account shall be distributed to his or her surviving spouse in the form of a Qualified Preretirement Survivor Annuity contract to be purchased from a company selected by the Committee and commencing in payment on the date that would have been such Participant's Normal Retirement Date if he or she were still living. The Committee shall provide each such married Participant with a written explanation of the Qualified Preretirement Survivor Annuity provided above, including the Participant's right to waive the distribution of such Qualified Preretirement Survivor Annuity with the consent of his or her spouse and to revoke any such waiver, within whichever of the following periods ends last: (i) the period beginning with the first day of the Plan Year in which the Participant attains the age of 32 and ending with the close of the Plan Year preceding the Plan Year in which the Participant attains the age of 35, (ii) the one-year period after the individual becomes a Participant, or (iii) the one-year period after separation from employment in the case of a Participant who separates before attaining age 35. Each married Participant may elect at any time prior to such Participant's death to waive the Qualified Preretirement Survivor Annuity form of benefit provided above so that his or her entire benefit may be paid to his or her designated beneficiary. No election to waive the Qualified Preretirement Survivor Annuity will be effective upon the Participant's death unless such election designates a beneficiary that cannot be changed without spousal consent, the Participant's surviving spouse consents in writing to such election and such consent is witnessed by a notary public. A spousal consent will be valid only with respect to the spouse who signs the consent and such consent shall be irrevocable. A married Participant may revoke any such election to waive the Qualified Preretirement Survivor Annuity at any time prior to his or her death. The amount payable under the Plan upon the death of a married Participant who has elected, as provided above, to waive the Qualified Preretirement Survivor Annuity shall be distributed in accordance with subsection (a) of this Section. The surviving spouse of any deceased Participant may elect in writing after the Participant's death to receive the entire benefit otherwise payable to such surviving spouse in accordance with this subsection (a) of this Section. For purposes of determining whether the value of a Participant's Vested Interest exceeds $5,000, the value of a Participant's Vested Interest shall be determined without regard to the value of the Participant's Rollover Account. Section 6.4 Distribution of Separation from Employment Benefit. (a) Except as otherwise provided in this Section, if a Participant separates from the employment of an Employer or Affiliated Company for any reason other than his or her Retirement, Permanent Disability, death or transfer to the employment of another Employer or Affiliated Company, the Accounts of such Participant shall be retained in trust and shall continue to be credited with applicable earnings as provided in Section 4.3, and the Vested Interest of such Participant shall be distributed to him or her by the Trustee at the direction of the Committee in accordance with Section 6.2(a) as soon as practicable after his or her Normal Retirement Date (or, if the Participant dies prior to such date, the Vested Interest of such Participant shall be distributed upon his or her death in accordance with Section 6.3); provided, however, that (i) each such Participant shall have the right -25- to elect on a form prescribed by the Committee to receive an early distribution of his or her Vested Interest as soon as practicable and (ii) the Committee shall require an early distribution of any such Participant's Vested Interest which does not exceed $5,000 in the form of a single distribution. The Vested Interest of a Participant who elects to receive an early distribution shall be distributed to him or her in the same manner as provided in Section 6.2(a) for a distribution upon Retirement or Permanent Disability. Any provision of this Plan to the contrary notwithstanding, for purposes of this Article a Participant shall not be treated as having separated from the employment of an Employer or Affiliated Company prior to such time that a distribution can be made to such Participant in accordance with Section 401(k) of the Code and the regulations thereunder. For purposes of determining whether the value of a Participant's Vested Interest exceeds $5,000, the value of a Participant's Vested Interest shall be determined without regard to the value of the Participant's Rollover Account. (b) Any provision of subsection (a) of this Section to the contrary notwithstanding, except as otherwise provided in this subsection (b), if a Participant's whose Vested Interest exceeds $5,000 separates from the employment of an Employer or Affiliated Company for any reason other than his or her Retirement, Permanent Disability, death or transfer to the employment of another Employer or Affiliated Company, such Participant's Matching Plan Account, Mesa Premium Account, Prior Plan Employer Account and/or Prior Plan Pre-Tax Account shall be distributed to such Participant by the Trustee at the direction of the Committee upon such Participant's Normal Retirement Date by payment of the entire amount in the form of a Qualified Joint and Survivor Annuity contract to be purchased from a company selected by the Committee and commencing in payment as soon as practicable thereafter (or, if the Participant dies prior to his or her Normal Retirement Date, the Vested Interest of such Participant under the Plan shall be distributed upon his or her death in accordance with Section 6.3); provided, however, that each such Participant shall have the right to elect on a form prescribed by the Committee to receive an early distribution of the amount credited to his or her Matching Plan Account, Mesa Premium Account, Prior Plan Employer Account and/or Prior Plan Pre-Tax Account as soon as practicable after such election. If a Participant elects under this subsection (b) to receive an early distribution, such distribution shall be made in the form of (i) a Qualified Joint and Survivor Annuity contract to be purchased from a company selected by the Committee and commencing in payment as soon as practicable following such election, or (ii) upon satisfaction of the notice and waiver requirements of Section 6.2(b), in accordance with subsection (a) of this Section. Section 6.5 Forfeitures. (a) Unless sooner forfeited as provided below, any unvested portion of the Accounts of a Participant who separates from the employment of an Employer or Affiliated Company for any reason other than his or her Retirement, Permanent Disability, death or transfer to the employment of another Employer or Affiliated Company shall be -26- forfeited upon the earlier of the date of such Participant's death or the date such Participant incurs five consecutive One Year Breaks in Service unless such Participant is reemployed by an Employer or Affiliated Company prior to such date. (b) If a Participant receives a complete distribution of his or her Vested Interest under Section 6.4 by the close of the second Plan Year following the Plan Year in which his or her separation from employment occurred, any portion of such Participant's Accounts which is not vested at the time of such distribution shall be forfeited at such time. If a Participant who separates from the employment of an Employer or Affiliated Company for any reason other than his or her Retirement, Permanent Disability, death or transfer to the employment of another Employer or Affiliated Company, is not entitled to receive any distribution from the Plan due to the fact that such Participant has no Vested Interest, such Participant shall be deemed to have received a distribution from the Plan of his or her entire Vested Interest under the Plan and any amount credited to such Participant's Accounts shall be forfeited at the time of such separation from employment. If a Participant, any portion of whose Accounts is forfeited pursuant to this subsection (b), is reemployed as a Covered Employee prior to incurring five consecutive One Year Breaks in Service, the amount so forfeited shall be restored to such individual's Accounts, out of current-year forfeitures or, if such forfeitures are insufficient, by an additional Employer contribution; provided, however, that no amount shall be restored to the Accounts of an individual who previously received a distribution of the vested portion of such Accounts unless he or she repays to the Plan, while a Covered Employee and within five years of the date of such reemployment, the full amount previously distributed from such Accounts for crediting to his or her Accounts. (c) If a Participant who has not yet incurred five consecutive One Year Breaks in Service receives a distribution under Section 6.4 after the end of the second Plan Year following the year in which his or her separation from employment occurred, any portion of such Participant's Accounts which is not vested at the time of such distribution shall be retained in such Account and shall be forfeited upon the earlier of the date of such Participant's death or the date such Participant incurs five consecutive One Year Breaks in Service unless such Participant is reemployed by an Employer or Affiliated Company prior to such date. If a Participant receives a distribution from the Plan after the end of the second Plan Year following the year in which his or her separation from employment occurred and is reemployed by an Employer or Affiliated Company prior to incurring five consecutive One Year Breaks in Service, then the unvested balance in his or her Accounts shall be transferred to a segregated account for such Participant and the amount that the Participant is entitled to receive from such segregated account as of any later date shall be an amount equal to X, which amount shall be determined in accordance with the following formula: X = P(AB + D) - D, where P is the Participant's vested percentage at such later date, AB is the amount in his or her segregated account at such later date, and D is the amount distributed to the Participant in connection with his or her earlier separation from employment. -27- (d) All amounts forfeited under the Plan shall be credited to a forfeiture account and invested by the Trustee at the direction of the Committee in its discretion until such forfeited amounts and any earnings attributable thereto are applied in accordance with Section 3.8. Section 6.6 In-Service Withdrawals. (a) A Participant in the employ of an Employer may make -- (i) a withdrawal of all or a portion (in multiples of 10% or in whole dollar amounts) of the total amount credited to his or her After-Tax Account, Mesa After-Tax Account or Rollover Account; (ii) if the Participant has attained the age of 59 1/2, a withdrawal of all or a portion (in multiples of 10% or in whole dollar amounts) of the total vested amount credited to his or her Accounts (other than his or her Matching Plan Account and Mesa Premium Account); or (iii) a hardship withdrawal of such amount as the Committee shall determine to be necessary to satisfy an immediate and heavy financial need of such Participant from his or her Pre-Tax Account and Prior Plan Pre-Tax Account, other than earnings credited to either such Account for any period of time after December 31, 1988, and qualified nonelective contributions allocated to either such Account; provided, however, that (i) no withdrawal may be made unless notice of such withdrawal is delivered to or in the manner prescribed by the Committee by the withdrawing Participant within such period of time prior to the effective date thereof as the Committee may prescribe in its discretion, (ii) no withdrawal may be made by a Participant to whom a loan from the Trust is then outstanding unless the Committee is satisfied that such loan will remain nontaxable and fully secured by the withdrawing Participant's Vested Interest following such withdrawal, and (iii) withdrawals from the Prior Plan Pre-Tax Account and Prior Plan Employer Account may be made only pursuant to the notice and consent requirements of Section 6.2(b). The Committee shall direct the Trustee to distribute any withdrawn amount to such Participant as soon as practicable following the effective date of the withdrawal. Any withdrawal from an Account pursuant to this Section shall be taken proportionally from each Investment Fund in which such Account is invested. The Committee may prescribe uniform and nondiscriminatory rules and procedures limiting the number of times that a Participant may make withdrawals during a Plan Year and the minimum amount that a Participant may withdraw on any single occasion. (b) A hardship withdrawal will be considered to be made on account of an immediate and heavy financial need of a Participant only if the Committee determines that such withdrawal is on account of (i) expenses for medical care described in Section 213(d) of the Code -28- previously incurred by such Participant or his or her spouse or dependents (as defined in Section 152 of the Code) or necessary for such individuals to obtain such care, (ii) costs directly related to the purchase of a principal residence for such Participant (excluding mortgage payments), (iii) payment of tuition and related educational fees for the next 12 months of post-secondary education for such Participant or his or her spouse, children or dependents (as so defined), or (iv) payments necessary to prevent the eviction of such Participant from his or her principal residence or foreclosure on the mortgage of such residence. (c) A hardship withdrawal will be considered to be necessary to satisfy an immediate and heavy financial need of a Participant only if the Committee determines that (i) the amount of such withdrawal is not in excess of the amount of such need plus any amounts necessary to pay any federal, state or local income taxes or penalties reasonably anticipated to result from the withdrawal, and (ii) such Participant has obtained all distributions and withdrawals, other than hardship withdrawals, and all nontaxable loans currently available under all plans maintained by the Employers. (d) Any provision of this Plan to the contrary notwithstanding, if a Participant makes a hardship withdrawal, (i) no Pre-Tax Contributions or Pre-Tax Bonus Contributions shall be made on behalf of such Participant for 6 months after receipt of such withdrawal and no contributions shall be made by or on behalf of such Participant to any other deferred compensation plan maintained by an Employer or Affiliated Company for 6 months after receipt of such withdrawal and (ii) the Total Pre-Tax Contributions made on behalf of such Participant for the calendar year immediately following the calendar year of such withdrawal shall not exceed the amount by which the limitation under Section 402(g) of the Code for such next calendar year exceeds the amount of the Total Pre-Tax Contributions made on behalf of such Participant for the calendar year of such withdrawal. Section 6.7 Distributions to Minors and Persons Under Legal Disability. If any distribution under the Plan becomes payable to a minor or other person under a legal disability, such distribution may be made to the duly appointed guardian or other legal representative of the estate of such minor or person under legal disability. Section 6.8 Benefits Payable to Missing Participant or Beneficiary. If the Committee cannot locate a Participant or beneficiary entitled to a distribution under this Plan within a period of three years after such Participant or beneficiary becomes entitled to the distribution, the amounts credited to the Accounts of such Participant or beneficiary shall be forfeited; provided, however, that if a claim for any such forfeited amounts is subsequently made by any person entitled to the distribution, such forfeited amounts shall be restored (without adjustment for earnings or appreciation) out of current-year forfeitures, or if such forfeitures are insufficient, by an additional Employer contribution. -29- Section 6.9 Plan Loans. (a) Subject to such conditions and limitations as the Committee may from time to time prescribe for application to all Participants and beneficiaries on a uniform basis, at the request of a Participant or beneficiary of a deceased Participant who is a party in interest (within the meaning of Section 3(14) of the Employee Retirement Income Security Act of 1974, as amended) with respect to the Plan (hereinafter called the "Borrower"), the Committee shall direct the Trustee to loan to such Borrower from his or her Accounts (other than the Borrower's Matching Plan Account and Mesa Premium Account) an amount of money which, when added to the total outstanding balance of all other loans to such Borrower from the Plan or from a qualified employer plan (within the meaning of Section 72(p) of the Code) maintained by an Employer or Affiliated Company, does not exceed the lesser of (i) $50,000 (reduced, however, by the excess, if any, of the highest total outstanding balance of all such other loans during the one-year period ending on the day before the date such loan is made, over the outstanding balance of all such other loans on the date such loan is made), or (ii) one-half of such Participant's Vested Interest under the Plan (or, in the case of a loan to a beneficiary, one-half of such beneficiary's Accounts). (b) Any such loan made to a Borrower shall be evidenced by a promissory note or other evidence of indebtedness payable to the Trustee, shall bear a reasonable rate of interest, shall be secured by one-half of the Participant's vested interest under the Plan (or, in the case of a loan to a beneficiary, by one-half of such beneficiary's Accounts), shall be repayable in substantially equal payments no less frequently than quarterly and shall be repayable within five years or, in the case of a loan that is to be used to acquire any dwelling unit which within a reasonable period of time is to be used as the principal residence of the Participant, within such period greater than five years as shall be determined by the Committee in its absolute discretion. (c) Any provision of this Plan to the contrary notwithstanding, (i) the promissory note or other evidence of indebtedness evidencing any such loan shall be held by the Trustee as a segregated investment allocated to and made solely for the benefit of the Account of the Borrower from which such loan was made, and (ii) no loan shall be made to a married Participant from a Prior Plan Pre-Tax Account or Prior Plan Employer Account unless the spouse of such Participant consents in writing thereto within the 90-day period preceding the date such loan is made and such consent is witnessed by a notary public. Section 6.10 Qualified Domestic Relations Orders. Any provision of this Plan to the contrary notwithstanding: (a) The Committee shall establish and maintain for each alternate payee named with respect to a Participant under a domestic relations order which is determined by the Committee to be a qualified domestic relations order (as defined in Section 414(p) of the Code) -30- such separate Accounts as the Committee may deem to be necessary or appropriate to reflect such alternate payee's interest in the Accounts of such Participant. Such alternate payee's Accounts shall be credited with the alternate payee's interest in the Participant's Accounts as determined under such qualified domestic relations order. The alternate payee may change investment direction with respect to his or her Account balances in accordance with Section 4.2 in the same manner as the Participant. (b) Except to the extent otherwise provided in the qualified domestic relations order naming an alternate payee with respect to a Participant, (i) the alternate payee may designate a beneficiary on a form prescribed by and filed with or as directed by the Committee, (ii) if no such beneficiary is validly designated or if the designated beneficiary is a person who predeceases the alternate payee, the beneficiary of the alternate payee shall be the alternate payee's estate, and (iii) the beneficiary of the alternate payee shall be accorded under the Plan all of the rights and privileges of the beneficiary of a Participant. (c) An alternate payee named with respect to a Participant shall be entitled to receive a distribution from the Plan in accordance with the qualified domestic relations order naming such alternate payee. Such distribution may be made only in a form provided under the Plan and shall include only such amounts as are vested. If a qualified domestic relations order so provides, a lump sum distribution of the total vested amount credited to the alternate payee's Accounts may be made to the alternate payee at any time prior to the date the Participant named in such qualified domestic relations order attains his or her earliest retirement age (as defined in Section 414(p)(4)(B) of the Code). To the extent provided by a qualified domestic relations order, the alternate payee named with respect to a Participant may make withdrawals (other than hardship withdrawals) from his or her Accounts in accordance with Article VI in the same manner as the Participant with respect to whom such alternate payee was named under said qualified domestic relations order. (d) If a portion of any unvested amount credited to the Employer Account or Matching Plan Account of a Participant named in the qualified domestic relations order is credited to the Employer Account or Matching Plan Account, whichever is applicable, of the alternate payee named in such qualified domestic relations order, the portion credited to the alternate payee's Employer Account or Matching Plan Account shall vest and/or be forfeited at the same time and in the same manner as the Participant's Employer Account or Matching Plan Account, whichever is applicable. Section 6.11 Transfer of Eligible Rollover Distribution. If a Participant is entitled to receive an eligible rollover distribution (as defined in Section 402(c) of the Code and the regulations thereunder) from the Plan, such Participant may elect to have the Committee direct the Trustee to transfer the entire amount of such distribution directly to any of the following "eligible retirement plans" specified by such Participant: an individual retirement account described in Section 408(a) of the Code, an individual retirement annuity described in Section 408(b) of the Code (other than an -31- endowment contract), a defined contribution plan qualified under Section 401(a) of the Code the terms of which permit rollover contributions or an annuity plan described in Section 403(a) of the Code. If the surviving spouse of a deceased Participant is entitled to receive an eligible rollover distribution from the Plan, such surviving spouse may elect to have the Committee direct the Trustee to transfer the entire amount of such distribution directly to either an individual retirement account described in Section 408(a) of the Code or an individual retirement annuity described in Section 408(b) of the Code (other than an endowment contract) specified by such surviving spouse. If an alternate payee under a qualified domestic relations order (as defined in Section 414(p) of the Code) is the spouse or former spouse of the Participant specified in the qualified domestic relations order, this Section shall apply to such alternate payee as if the alternate payee were a Participant. A distributee of an eligible rollover distribution who is entitled to make an election under this Section may specify that some portion less than the entire amount of such distribution be transferred in accordance with this Section. The preceding provisions of this Section to the contrary notwithstanding, (i) an "eligible retirement plan" shall also mean an annuity contract described in Section 403(b) of the Code and an eligible plan under Section 457(b) of the Code which is maintained by a state, political subdivision of a state, or any agency or instrumentality of a state or political subdivision of a state and which agrees to separately account for amounts transferred into such plan from this Plan, (ii) the definition of "eligible retirement plan" shall also apply in the case of a distribution to a surviving spouse, or to a spouse or former spouse who is the alternate payee under a qualified domestic relations order, as defined in Section 414(p) of the Code, (iii) any amount that is distributed on account of hardship shall not be an eligible rollover distribution and the distributee may not elect to have any portion of such a distribution paid directly to an eligible retirement plan, and (iv) a portion of a distribution shall not fail to be an eligible rollover distribution merely because the portion consists of after-tax employee contributions which are not includible in gross income, provided that such portion may be transferred only to an individual retirement account or annuity described in Section 408(a) or (b) of the Code, or to a qualified defined contribution plan described in Section 401(a) or 403(a) of the Code that agrees to separately account for amounts so transferred, including separately accounting for the portion of such distribution which is includible in gross income and the portion of such distribution which is not so includible. ARTICLE VII. PLAN ADMINISTRATION Section 7.1 401(k) and Matching Plan Committee. The plan administrator of the Plan shall be a 401(k) and Matching Plan Committee composed of at least three individuals appointed by the Board of Directors of the Company. Each member of the Committee so appointed shall serve in such office until his or her death, resignation or removal by the Board of Directors of the Company. The Board of Directors of the Company may remove any member of the Committee at any time by giving written notice thereof to the members of the Committee. Vacancies shall likewise be filled from time to time by the Board of Directors of the -32- Company. The members of the Committee shall receive no remuneration from the Plan for their services as Committee members. Section 7.2 Powers, Duties and Liabilities of the Committee. The Committee shall have discretionary and final authority to interpret and implement the provisions of the Plan, including without limitation authority to determine eligibility for benefits under the Plan, and shall perform all of the duties and exercise all of the powers and discretion granted to it under the terms of the Plan. The Committee shall act by a majority of its members at the time in office and such action may be taken either by a vote at a meeting or in writing without a meeting. The Committee may by such majority action authorize any one or more of its members to execute any document or documents on behalf of the Committee, in which event the Committee shall notify the Trustee in writing of such action and the name or names of its member or members so authorized to act. Every interpretation, choice, determination or other exercise by the Committee of any discretion given either expressly or by implication to it shall be conclusive and binding upon all parties directly or indirectly affected, without restriction, however, on the right of the Committee to reconsider and redetermine such actions. In performing any duty or exercising any power herein conferred, the Committee shall in no event perform such duty or exercise such power in any manner which discriminates in favor of Highly Compensated Employees. The Employers shall indemnify and hold harmless each member of the Committee against any claim, cost, expense (including attorneys' fees), judgment or liability (including any sum paid in settlement of a claim with the approval of the Employers) arising out of any act or omission to act as a member of the Committee appointed under this Plan, except in the case of willful misconduct. Section 7.3 Rules, Records and Reports. The Committee may adopt such rules and procedures for the administration of the Plan as are consistent with the terms hereof, and shall keep adequate records of the Committee's proceedings and acts and of the status of the Participants' Accounts. The Committee may employ such agents, accountants and legal counsel (who may be agents, accountants or legal counsel for an Employer) as may be appropriate for the administration of the Plan. The Committee shall at least annually provide each Participant with a report reflecting the status of his or her Accounts in the Trust and shall cause such other information, documents or reports to be prepared, provided and/or filed as may be necessary to comply with the provisions of the Employee Retirement Income Security Act of 1974 or any other law. Section 7.4 Administration Expenses and Taxes. Unless otherwise paid by the Employers in their absolute discretion, the Committee shall direct the Trustee to pay all reasonable and necessary expenses (including the fees of agents, accountants and legal counsel) incurred by the Committee in connection with the administration of the Plan. Should any tax of any character (including transfer taxes) be levied upon the Trust assets or the income therefrom, such tax shall be paid from and charged against the assets of the Trust. -33- ARTICLE VIII. AMENDMENT AND TERMINATION Section 8.1 Amendment. The Board of Directors of the Company shall have the right and power at any time and from time to time to amend this Plan, in whole or in part, on behalf of all Employers. Any such amendment made by the Board of Directors of the Company shall be made by or pursuant to a resolution duly adopted by the Board of Directors of the Company, and shall be evidenced by such resolution or by a written instrument executed by such person as the Board of Directors of the Company shall authorize for such purpose. With the consent of the Board of Directors of the Company and subject to such procedure as it may prescribe, the Board of Directors of each Employer shall have the right and power at any time and from time to time to amend this Plan, in whole or in part, with respect to the Plan's application to the Participants of the particular amending Employer and the assets held in the Trust for their benefit, or to transfer such assets or any portion thereof to a new trust for the benefit of such Participants. However, in no event shall any amendment or new trust permit any portion of the trust fund to be used for or diverted to any purpose other than the exclusive benefit of the Participants and their beneficiaries, nor shall any amendment or new trust reduce a Participant's Vested Interest under the Plan. Section 8.2 Termination. The Board of Directors of the Company shall have the right and power at any time to terminate this Plan on behalf of all Employers, or to terminate this Plan as it applies to the Participants who are or were employees of any particular Employer, by giving written notice of such termination to the Committee and Trustee. Any provision of this Plan to the contrary notwithstanding, upon the termination or partial termination of the Plan as to any Employer, or in the event any Employer should completely discontinue making contributions to the Plan without formally terminating it, all amounts credited to the Accounts of the affected Participants of that particular Employer shall be fully vested. Section 8.3 Benefit Plan Design Committee. Any action permitted to be taken by the Board with respect to the amendment of this Plan may be taken by the Benefit Plan Design Committee. The Benefit Plan Design Committee shall be composed of at least two individuals appointed by the Board of Directors of the Company. Each member of the Benefit Plan Design Committee so appointed shall serve in such office until his or her death, resignation or removal by the Board. The Board may remove any member of the Benefit Plan Design Committee at any time by giving written notice thereof to the members of the Benefit Plan Design Committee. Vacancies shall likewise be filled from time to time by the Board. The Benefit Plan Design Committee shall act by a majority of its members at the time in office and such action may be taken either by a vote at a meeting or in writing without a meeting. -34- ARTICLE IX. TOP-HEAVY PROVISIONS Section 9.1 Top-Heavy Definitions. Unless the context clearly indicates otherwise, when used in this Article: (a) "Top-Heavy Plan" means this Plan if, as of the Determination Date, the aggregate of the Accounts of Key Employees under the Plan exceeds 60% of the aggregate of the Accounts of all Participants and former Participants under the Plan. The aggregate of the Accounts of any Participant or former Participant shall include any distributions (other than related rollovers or transfers from the Plan within the meaning of regulations under Section 416(g) of the Code) made from such individual's Accounts during the one-year period ending on the Determination Date, but shall not include any unrelated rollovers or transfers (within the meaning of regulations under Section 416(g) of the Code) made to such individual's Accounts after December 31, 1983; provided, however, that in the case of a distribution made for a reason other than separation from service, death, or disability, this provision shall be applied by substituting "five-year period" for "one-year period". The Account of any Participant or former Participant who (i) is not a Key Employee for the Plan Year in question but who was a Key Employee in a prior Plan Year, or (ii) has not completed an Hour of Service during the one-year period ending on the Determination Date, shall not be taken into account. The determination of whether the Plan is a Top-Heavy Plan shall be made after aggregating all other plans of an Employer and any Affiliated Company qualifying under Section 401(a) of the Code in which a Key Employee is a participant or which enables such a plan to meet the requirements of Section 401(a)(4) or 410 of the Code, and after aggregating any other plan of an Employer or Affiliated Company, which is not already aggregated, if such aggregation group would continue to meet the requirements of Sections 401(a)(4) and 410 of the Code and if such permissive aggregation thereby eliminates the top-heavy status of any plan within such permissive aggregation group. For purposes of determining the aggregate of the Accounts of any Participant or former Participant, the distributions included, as provided above, shall include distributions under a terminated plan which, had it not been terminated, would have been aggregated with the Plan under Section 416(g)(2)(A)(i) of the Code. The determination of whether this Plan is a Top-Heavy Plan shall be made in accordance with Section 416(g) of the Code. (b) "Determination Date" means, for purposes of determining whether the Plan is a Top-Heavy Plan for a particular Plan Year, the last day of the preceding Plan Year. (c) "Key Employee" means any Employee or former Employee (including a beneficiary of such Employee or former Employee) who at any time during the Plan Year that includes the Determination Date is: -35- (1) an officer of an Employer having Compensation for such Plan Year greater than $130,000 (as adjusted under Section 416(i)(1) of the Code for Plan Years beginning after December 31, 2002); (2) a 5% owner of the Employer; or (3) a 1% owner of the Employer having Compensation for such Plan Year of more than $150,000. The determination of who is a Key Employee will be made in accordance with Section 416(i)(1) of the Code and the applicable regulations and other guidance of general applicability issued thereunder. (d) "Non-Key Employee" means any Employee or former Employee (including a beneficiary of such Employee or former Employee) who is not a Key Employee. Section 9.2 Minimum Contribution Requirement. Any provision of this Plan to the contrary notwithstanding, if the Plan is a Top-Heavy Plan for any Plan Year, then the Employers will contribute to the Employer Account of each Non-Key Employee who is both eligible to participate and in the employ of an Employer on the last day of such Plan Year, an amount which, when added to the total amount of Matching Contributions and forfeitures otherwise allocable under the Plan to such Non-Key Employee for such year, shall equal the lesser of (i) 3% of such Non-Key Employee's Compensation for such year or (ii) the amount of contributions (including Total Pre-Tax Contributions) and forfeitures (expressed as a percentage of Compensation) allocable under the Plan for or on behalf of the Key Employee for whom such percentage is the highest for the Plan Year after taking into account contributions under other defined contribution plans maintained by the Employer in which a Key Employee is a participant (as well as any other plan of an Employer which enables such a plan to meet the requirements of Section 401(a)(4) or 410 of the Code); provided, however, that no minimum contribution shall be made for a Non-Key Employee under this Section for any Plan Year if the Employer maintains another qualified plan under which a minimum benefit or contribution is being accrued or made for such Plan Year for the Non-Key Employee in accordance with Section 416(c) of the Code. A Non-Key Employee who is not a Participant, but for whom a contribution is made pursuant to this Section, shall be accorded all of the rights and privileges of a Participant under the Plan except that no contributions (other than contributions pursuant to this Section) shall be made for or on behalf of such Non-Key Employee until he or she meets the eligibility and participation requirements of Article II. Section 9.3 Minimum Vesting Schedule. Any provision of this Plan to the contrary notwithstanding, if the Plan is a Top-Heavy Plan for any Plan Year, then effective as of the first day of such Plan Year with respect to Participants who complete an Hour of Service on or after such day, the vesting schedule provided in Section 5.2 shall be applied to that portion of such Participants' Employer Account which is attributable to any amounts credited to -36- his or her Employer Nonelective Contribution Account under the Superseded Plan as in effect on September 30, 1997, as if to read as follows: Period of Service Completed by Participant Percentage Vested ------------------------ ----------------- Less than 3 years None 3 or more years 100%
ARTICLE X. MISCELLANEOUS GENERAL PROVISIONS Section 10.1 Spendthrift Provision. No right or interest of any Participant or beneficiary under the Plan may be assigned, transferred or alienated, in whole or in part, either directly or by operation of law, and no such right or interest shall be liable for or subject to any debt, obligation or liability of such Participant or beneficiary; provided, however, that nothing herein shall prevent the payment of amounts from a Participant's Accounts under the Plan in accordance with the terms of a court order which the Committee has determined to be a qualified domestic relations order (as defined in Section 414(p) of the Code). Section 10.2 Claims Procedure. If any person (hereinafter called the "Claimant") feels that he or she is being denied a benefit to which he or she is entitled under the Plan, such Claimant may file a written claim for said benefit with any member of the Committee. Within 60 days of the receipt of such claim the Committee shall determine and notify the Claimant as to whether he or she is entitled to such benefit. Such notification shall be in writing and, if denying the claim for benefit, shall set forth the specific reason or reasons for the denial, make specific reference to the pertinent provisions of the Plan, and advise the Claimant that he or she may, within 60 days of the receipt of such notice, in writing request to appear before the Committee for a hearing to review such denial. Any such hearing shall be scheduled at the mutual convenience of the Committee or its designated representative and the Claimant, and at such hearing the Claimant and/or his or her duly authorized representative may examine any relevant documents and present evidence and arguments to support the granting of the benefit being claimed. The final decision of the Committee with respect to the claim being reviewed shall be made within 60 days following the hearing thereon and the Committee shall in writing notify the Claimant of its final decision, again specifying the reasons therefor and the pertinent provisions of the Plan upon which such decision is based. The final decision of the Committee shall be conclusive and binding upon all parties having or claiming to have an interest in the matter being reviewed. Section 10.3 Maximum Contribution Limitation. Any provision of this Plan to the contrary notwithstanding (except to the extent permitted under Section 3.3 of the Plan and Section 414(v) of the Code, if applicable), the sum of (i) the Employer contributions, (ii) the forfeitures, and (iii) the -37- Participant contributions (excluding rollover contributions and employee contributions to a simplified employee pension allowable as a deduction, each within the meaning specified in Section 415(c)(2) of the Code), allocated to a Participant with respect to a Plan Year shall in no event exceed the lesser of $40,000 (as adjusted for increases in the cost-of-living under Section 415(d) of the Code) or 100% of such Participant's Compensation for that year. For the purposes of applying the limitation imposed by this Section, each Employer and its Affiliated Companies shall be considered a single employer, and all defined contribution plans (meaning plans providing for individual accounts and for benefits based solely upon the amounts contributed to such accounts and any forfeitures, income, expenses, gains and losses allocated to such accounts) described in Section 415(k) of the Code, whether or not terminated, maintained by an Employer or its Affiliated Companies shall be considered a single plan. If the total amount allocable to a Participant's Accounts for a particular Plan Year would, but for this sentence, exceed the foregoing limitation, such Participant's After-Tax Contributions shall first be distributed and then, to the extent necessary, Total Pre-Tax Contributions shall be distributed first from any Pre-Tax Bonus Contributions and then from Pre-Tax Contributions. Any Matching Contributions corresponding to any distributed Pre-Tax Contributions shall be credited to a suspense account and thereafter reallocated (prior to the allocation of subsequent forfeitures and the making of any additional contributions to the Plan) to reduce the earliest subsequent Matching Contributions an Employer would otherwise be required to make to the Plan pursuant to Section 3.2 for such year and the next succeeding Plan Year. No adjustment shall be made to such suspense account to reflect income, profits and losses, expenses or other transactions affecting the Plan. Any Pre-Tax Contributions or Pre-Tax Bonus Contributions distributed to a Participant pursuant to this Section shall not be taken into account in determining such Participant's actual deferral percentage for purposes of Section 3.7. Section 10.4 Employment Noncontractual. The establishment of this Plan shall not enlarge or otherwise affect the terms of any Employee's employment with an Employer and an Employer may terminate the employment of any Employee as freely and with the same effect as if this Plan had not been adopted. Section 10.5 Limitations on Responsibility. The Employers do not guarantee or indemnify the Trust against any loss or depreciation of its assets which may occur, nor guarantee the payment of any amount which may become payable to a Participant or his or her beneficiaries pursuant to the provisions of this Plan. All payments to Participants and their beneficiaries shall be made by the Trustee at the direction of the Committee solely from the assets of the Trust and the Employers shall have no legal obligation, responsibility or liability for any such payments. Section 10.6 Merger or Consolidation. In no event shall this Plan be merged or consolidated into or with any other plan, nor shall any of its assets or liabilities be transferred to any other plan, unless each Participant would be entitled to receive a benefit if the plan in which he or she then participates terminated immediately following such merger, consolidation or transfer, which is equal to or greater than the benefit he or she would have been entitled to receive if the Plan had been terminated immediately prior to such merger, consolidation or transfer. -38- Section 10.7 Applicable Law. This Plan shall be governed and construed in accordance with the internal laws (and not the principles relating to conflicts of laws) of the State of Texas except where superseded by federal law. Section 10.8 USERRA Compliance. Notwithstanding any provision of this Plan to the contrary, contributions, benefits and service credit with respect to qualified military service will be provided in accordance with Section 414(u) of the Code. IN WITNESS WHEREOF, this restatement has been executed as of this ____ day of December, 2001, to be effective as of January 1, 2002. PIONEER NATURAL RESOURCES USA, INC. By______________________________________________ Larry Paulsen, Vice President - Administration -39-
                                                                   EXHIBIT 21.1


                           SUBSIDIARIES OF THE COMPANY

State or Jurisdiction
   of Organization                          Subsidiaries
- ---------------------   ------------------------------------------------------
Delaware                Bridge Oil (U.S.A.) Inc.
Delaware                DMLP Co.
Netherlands             D, P & D Investments B.V.
Delaware                Mesa Environmental Ventures Co.
Texas                   Mesa Offshore Royalty Partnership
Delaware                Parker & Parsley Argentina, Inc.
Australia               Parker & Parsley Petroleum Australia Holdings Pty
                          Limited
Australia               Parker & Parsley Petroleum Australia Pty Limited
Delaware                Pioneer International Resources Company
Texas                   Pioneer Natural Gas Company
Delaware                Pioneer Natural Resources Alaska, Inc.
Cayman Islands          Pioneer Natural Resources Anaguid Ltd.
Argentina               Pioneer Natural Resources (Argentina) S.A.
Cayman Islands          Pioneer Natural Resources Borj El Khadra Ltd.
Canada                  Pioneer Natural Resources Canada Inc.
Cayman Islands          Pioneer Natural Resources (Cayman) Ltd.
Texas                   Pioneer Natural Resources  Scholarship Foundation
South Africa            Pioneer Natural Resources South Africa (Pty) Limited
Argentina               Pioneer Natural Resources (Tierra Del Fuego) S.A.
Cayman Islands          Pioneer Natural Resources Tunisia Ltd.
Delaware                Pioneer Natural Resources USA, Inc.
Bahamas                 Pioneer Resources Africa, Ltd.
Bahamas                 Pioneer Resources Gabon - Olowi Ltd.
Texas                   Pioneer Uravan, Inc.
Delaware                Westpan NGL LP
Delaware                Westpan Properties, Inc.
Nevada                  Westpan Resources Company
Delaware                Westpan Resources LP


                        Partnerships that Pioneer Natural Resources USA, Inc.
                        is the managing general partner

Delaware                Parker & Parsley 87-A Conv., Ltd.
Delaware                Parker & Parsley Private Investment 88, L.P.
Delaware                Parker & Parsley Private Investment 89, L.P.
Delaware                Parker & Parsley 90 Spraberry Private Development, L.P.
Texas                   Midkiff Development Drilling Program, Ltd.










                                                                   EXHIBIT 23.1



                         CONSENT OF INDEPENDENT AUDITORS


We consent to the incorporation by reference in the Registration Statements (No.
333-88438,  No. 333-35087,  No. 333-35165,  No.  333-39153,  No. 333-39249,  No.
33-44851,  No. 333-35085 and No. 333-35175) on Form S-8 and (No. 333-88478,  No.
333-42315,  No.  333-44439  and No. 333-  39381) on Form S-3 of Pioneer  Natural
Resources  Company and the related  Prospectuses of our report dated January 24,
2003, with respect to the consolidated  financial  statements of Pioneer Natural
Resources Company included in this Annual Report on Form 10-K for the year ended
December 31, 2002.


                                           Ernst & Young LLP



Dallas, Texas
February 19, 2003









                                                                   EXHIBIT 23.2



            CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS


We  hereby  consent  to the  incorporation  by  reference  in  the  Registration
Statements (No.  333-88438,  No. 333-35087,  No. 333-35165,  No. 333-39153,  No.
333-39249,  No. 33-44851,  No. 333-35085 and No. 333-35175) on Form S-8 and (No.
333-88478,  No.  333-42315,  No.  333-44439  and No.  333- 39381) on Form S-3 of
Pioneer Natural Resources Company and the related  Prospectuses of the reference
of Netherland,  Sewell & Associates,  Inc. in the Annual Report on Form 10-K for
the year ended December 31, 2002 of Pioneer  Natural  Resources  Company and its
subsidiaries, filed with the Securities and Exchange Commission.


                                  NETHERLAND, SEWELL & ASSOCIATES, INC.


                                  By:  Frederic D. Sewell
                                       --------------------------------------
                                       Frederic D.  Sewell
                                       Chairman and Chief Executive Officer


Dallas, Texas
February 17, 2003







                                                                   EXHIBIT 23.3



                  CONSENT OF GAFFNEY, CLINE & ASSOCIATES, INC.


As the  independent  reserve  engineers for Pioneer  Natural  Resources  Company
(Pioneer),  Gaffney, Cline & Associates,  Inc. (GCA) hereby confirms that it has
granted and not  withdrawn  its  consent to the  reference  in the  Registration
Statements (No.  333-88438,  No. 333-35087,  No. 333-35165,  No. 333-39153,  No.
333-39249,  No. 33-44851,  No. 333-35085 and No. 333-35175) on Form S-8 and (No.
333-88478,  No.  333-42315,  No.  333-44439  and No.  333-39381)  on Form S-3 as
disclosed by Pioneer in its Form 10-K submission to the United States Securities
and Exchange Commission for the period ending December 31, 2002.




                                         GAFFNEY, CLINE & ASSOCIATES, INC.





Houston, Texas
February 19, 2003











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