Exhibit
1    BAYTEX ENERGY LTD.  ANNUAL INFORMATION
FORM  FOR THE YEAR ENDED
DECEMBER 31, 2002    MARCH 3, 2003   
   TABLE OF CONTENTS  ABBREVIATIONS AND DEFINITIONS
  3SPECIAL
  NOTE REGARDING FORWARD-LOOKING STATEMENT
  4THE
  COMPANY
  4Incorporation and
  Organization
  4General Development
  of the Company
  5BUSINESS OF THE COMPANY
  5LAND HOLDINGS
  8OIL AND GAS WELLS
  8OIL AND GAS RESERVES
  9RECONCILIATION OF RESERVES
  12DRILLING ACTIVITY
  13HISTORY
  13FUTURE COMMITMENTS
  15DIRECTORS AND OFFICERS
  OF BAYTEX
  16PERSONNEL
  17DIVIDEND RECORD
  17MARKET FOR SECURITIES
  17MANAGEMENTS
  DISCUSSION AND ANALYSIS
  18CONTROLS AND PROCEDURES
  25SELECTED FINANCIAL
  INFORMATION
  26Summary of Operating Results
  26INDUSTRY CONDITIONS
  26Regulation
  26Environmental
  28RISK
  FACTORS
  28ADDITIONAL INFORMATION
  30SCHEDULE A -
  AUDITED CONSOLIDATED FINANCIAL STATEMENTS
  32  1 
   ABBREVIATIONS AND
DEFINITIONS  In
this Annual Information Form, the abbreviations set forth below have the
following meanings:  M$
  
  thousands of
  Canadian dollars
  
  mmcf
  
  1,000,000
  cubic feetMM$
  
  millions of
  Canadian dollars
  
  bcf
  
  1,000,000,000
  cubic feetbbl
  
  barrels
  
  mcf/d
  
  1,000 cubic
  feet per daymbbl
  
  1,000
  barrels
  
  mcfe
  
  1,000 cubic
  feet equivalentmmbbl
  
  1,000,000
  barrels
  
  mmcf/d
  
  1,000,000
  cubic feet per daybbl/d
  
  barrels per
  day
  
  boe
  
  barrels of
  oil equivalentstb
  
  stock tank
  barrels
  
  mboe
  
  1,000
  barrels of oil equivalentmstb
  
  1,000 stock
  tank barrels
  
  mmboe
  
  1,000,000
  barrels of oil equivalentNGL
  
  natural gas
  liquids
  
  boe/d
  
  barrels of
  oil equivalent per daymcf
  
  1,000 cubic
  feet
  
  m3
  
  cubic metreGJ
  
  gigajoule  Note:for the purposes of this document, 6 mcf of natural gas and 1 bbl of
NGL each equal 1 bbl of oil  In
this Annual Information Form, the capitalized terms set forth below have the
following meanings:  ABCA means the Business Corporations
Act, R.S.A. 2000, c. B-9, together with any amendments thereto and
all regulations promulgated thereunder;  API means American Petroleum Institute;  ARTC means the Alberta royalty tax credit;  Baytex or the Company means
Baytex Energy Ltd.;  Common
Shares means common shares in the
share capital of the Company;  Dorset means Dorset Exploration Ltd.;  GAAP means Canadian generally accepted
accounting principles  OGY means OGY Petroleums Ltd.;  Outtrim
Report means the independent
engineering evaluation of Baytexs crude oil and natural gas reserves prepared
by Outtrim Szabo Associates Ltd. (Outtrim), independent oil and gas reservoir
engineers of Calgary, Alberta, dated March 3, 2003 and effective December 31, 2002;  TSX means The Toronto Stock Exchange; and  Triumph means Triumph Energy Corporation.  In
this Annual Information Form, references to dollars and $ are to the
currency of Canada, unless otherwise indicated.  2 
   SPECIAL NOTE
REGARDING FORWARD-LOOKING STATEMENT  Baytex
Energy Ltd. (Baytex or the Company) is hereby providing cautionary
statements identifying important factors that could cause the Companys actual
results to differ materially from those projected in forward-looking statements
made in this Annual Information Form. 
Any statements that express, or involve discussions as to, expectations,
beliefs, plans, objectives, assumptions or future events or performance (often,
but not always, through the use of words or phrases such as will likely
result, are expected to, will continue, is anticipated, estimated,
intends, plans, projection and outlook) are not historical facts and
may be forward-looking and may involve estimates, assumptions and uncertainties
which could cause actual results or outcomes to differ materially from those
expressed in the forward looking statements. 
Accordingly, any such statements are qualified in their entirety by
reference to, and are accompanied by, the factors discussed throughout this
Annual Information Form.  Among the key
factors that have a direct bearing on the Companys results of operation are
the nature of the Companys involvement in the business of exploration,
development and production of oil and natural gas reserves, fluctuations in
pricing of oil and natural gas, fluctuations in interest rates and the
fluctuation of the exchange rate between the Canadian dollar and the United
States dollar.  These and other factors
are discussed herein under Managements Discussion and Analysis, incorporated
by reference from the Companys 2002 Annual Report and included elsewhere in
this Annual Information Form.  Because
actual results or outcomes could differ materially from those expressed in any
forward-looking statements of the Company made by or on behalf of the Company,
investors should not place undue reliance on any such forward-looking
statements.  Further, any forward-looking
statement speaks only as of the date on which such statement is made, and the
Company undertakes no obligation to update any forward-looking statement or
statements to reflect events or circumstances after the date on which such
statement is made or to reflect the occurrence of unanticipated events, except
as required by applicable securities laws. 
New factors emerge from time to time, and it is not possible for
management to predict all of such factors and to assess in advance the impact
of each such factor on the Companys business or the extent to which any
factor, or combination of factors, may cause actual results to differ
materially from those contained in any forward-looking statements.  THE COMPANY  Incorporation and Organization  The
Company was incorporated under the ABCA on June 3, 1993.  On August 5, 1993, the Company filed
Articles of Amendment to delete the private company restrictions
thereunder.  On October 13, 1993,
Articles of Amendment were filed to amend the Companys capital structure to
create Class A Shares and Class B Non-Voting Shares.  On October 21, 1997, the Company filed
Articles of Amalgamation to amalgamate with its wholly owned subsidiary,
Dorset.  On May 28, 1999, the Company
filed Articles of Amendment to eliminate the Class B Shares of the Company
and to change the designation of the Class A shares in the share capital of the
Company from Class A Shares to Common Shares.  On January 1, 2002, the Company filed Articles of Amalgamation to
amalgamate with its wholly owned subsidiaries OGY and Triumph.  Baytex
has two active wholly owned subsidiaries, Baytex Exploration Ltd. and Baytex
Resources Ltd., both of which were incorporated pursuant to the provisions of
the ABCA.  In addition, on January 1,
2001, Baytex formed a general partnership named Baytex Energy Partnership (the
Baytex Partnership) with both of these subsidiaries.  Each partner has contributed substantially
all of its producing properties to the Baytex Partnership.  In this Annual Information Form, unless
otherwise specified or the context otherwise requires, reference to the
Company" or Baytex" includes these subsidiaries and partnership
interests.  The
Companys principal office is located at Suite 2200, 205 - 5th
Avenue S.W., Calgary, Alberta, T2P 2V7. 
Its registered office is located at Suite 1400, 350 - 7th
Ave. S.W., Calgary, Alberta, T2P 3N9.  3 
   General Development of the Company  In
May of 2000, Baytex acquired all of the issued and outstanding shares of
Bellator Exploration Inc. (Bellator), a public oil and gas company, the
shares of which were listed on the TSX. 
The total consideration paid by Baytex for Bellator was $39.9 million in
cash and 8.8 million Baytex common shares. 
The operations of Bellator were concentrated on conventional heavy oil
production in western Saskatchewan. 
Throughout the remainder of 2000, the Company focused its attention on
the development of its new heavy oil assets drilling in excess of 270 heavy oil
wells.  In
May 2001, Baytex acquired all of the issued and outstanding shares of OGY, a
public oil and gas company, the shares of which were listed on the TSX.  The total consideration paid by Baytex for
OGY was $50.7 million in cash and 1.2 million Baytex common shares.  The operations of OGY concentrated on light
oil and natural gas in central Alberta.  Also
in May 2001, Baytex acquired all of the issued and outstanding shares of
Triumph, a public oil and gas company, the shares of which were listed on the
TSX.  The total consideration paid for
Triumph was $82.3 million in cash and 4.9 million Baytex common shares.  The operations of Triumph were focused on
the exploration and development of natural gas in Central Alberta and light oil
and natural gas in East Central and Southern Alberta.  Additional
heavy oil assets were also acquired in the Cold Lake, Alberta and Carruthers,
Saskatchewan areas in three separate property acquisitions in 2001 and 2002 for
total cash consideration of $73.4 million.  The
Company has also executed a plan to strengthen its balance sheet over the last
18 months with the divestiture of certain light oil and natural gas
assets.  This plan included the sale of
light oil and natural gas assets in the fourth quarter of 2001 and first
quarter of 2002 for total proceeds of $101 million and was later augmented in
the first quarter of 2003 with the completion of the sale of natural gas assets
in the Ferrier/OChiese area for proceeds of $133.3 million.  In
concert with this acquisition and divestiture program, the Company has
continued to execute a successful exploration and development drilling program
on its natural gas assets in Alberta and on its heavy oil assets in
Saskatchewan and Alberta.  This program
has included the drilling of 365 (327.5 net) total wells in 2001 and 2002, that
have resulted in 169 (157.8 net) oil wells, 132 (110.2 net) gas wells and 6
(4.9 net) service wells for a success rate of 84%.  In
October 2002, the Company signed a five-year crude oil supply agreement with a
U.S. refining company.  This agreement
calls for the delivery, beginning in January 2003, of up to 16,000 bbl per day
of heavy oil production at a fixed Lloyd Blend differential of 29 percent of
West Texas Intermediate price.  This
pricing arrangement effectively removes the additional pricing volatility
associated with heavy oil on two-thirds of the corporate heavy oil
production.  This contract forms part of
the Company's risk management policy and will help to protect the Company's
cash flow from dramatic swings in commodity prices in the future.  BUSINESS OF THE COMPANY  The
Company has focused our operations in our main geographical regions by
organizing our technical staff into three districts.  These districts are focused on taking advantage of the vast
amount of technical and operating information that we have in our core areas to
evaluate potential prospects, identify strategic acquisitions and to develop
and operate our existing properties in an efficient and low-cost manner.  4 
   The
following table sets forth the Companys average daily oil and natural gas
production by district for the years ended December 31, 2002 and 2001.  Year Ended December 31,2002
  
  2001Light Crude 
  Oil and 
  NGL (bbl/d)
  
  Heavy 
  Crude Oil 
  (bbl/d)
  
  Natural 
  Gas 
  (mmcf/d)
  
  Light Crude 
  Oil and 
  NGL (bbl/d)
  
  Heavy 
  Crude Oil 
  (bbl/d)
  
  Natural 
  Gas
  (mmcf/d)Heavy Oil District
  
  
  
  23,967
  
  10.5
  
  368
  
  26,533
  
  11.5Plains District
  
  2,124
  
  
  
  43.8
  
  3,721
  
  
  
  35.5Northern District
  
  1,030
  
  
  
  18.3
  
  1,063
  
  
  
  23.8Total
  
  3,154
  
  23,967
  
  72.6
  
  5,152
  
  26,533
  
  70.8  Heavy Oil District  The
Heavy Oil District includes the Company's lands in Saskatchewan and those lands
in Alberta from Range 1 to 11 west of the fourth Meridian and north of Township
50.  It accounts for 66 percent of the
Companys total production.  With its
low cost structure and less competitive environment, heavy oil provides Baytex
with a superior return on capital investment. 
The Companys expertise in heavy oil operations has resulted in a low
drilling risk, averaging a 94% drilling success rate over the last four years,
as well as finding, development and operating cost that are below those of
other commodities.  Baytexs
heavy oil operations consist of cold conventional production from wells with
multi-zone potential.  Production is
mainly from vertical and slant wells using progressive cavity pump technology
to generate large volumes of sand and oil from one of the Cummings, Colony,
McLaren, Waseca, Sparky, Rex and Lloydminster formations.  Production from these wells usually averages
between 40 and 100 bbls per day of sour, lower gravity crude ranging from 12 to
18 API.  Once produced, the oil is
trucked or pipelined to markets in Canada and the United States for upgrading
into lighter grades of crude or refined into petroleum products.  After
enduring the widest heavy oil differentials in history during the fourth
quarter of 2001, the first quarter of 2002 saw a significant narrowing of the
heavy oil price differential and the return to profitability of the Companys
heavy oil operations.  With improved
heavy oil economics early in 2002, Baytex accelerated its drilling program and
concurrently initiated a workover program to reactivate production that was
shut-in near the end of 2001.  Focus was
turned to the development of the property acquired in 2001 at Cold Lake,
Alberta along with continued development of existing properties at Baldwinton,
Buzzard, Lashburn, Marsden and Silverdale in Saskatchewan.  During
2002, production in the Heavy Oil District averaged 25,710 barrels of oil
equivalent per day made up of 23,937 bbl per day of heavy oil and 10.5 mmcf per
day of natural gas.  The Company drilled
119 (113.1 net) wells in this district resulting in 103 (97.7 Net) oil wells, 3
(2.5 net) gas wells, 2 service wells and 11 (10.9 net) dry and abandoned wells
for a success rate of 91percent.  Total
capital expenditures for the year were $101.6 million including property acquisitions
of $41.5 million.  Total undeveloped
land in the Heavy Oil District at year-end 2002 was 315,596 net acres valued
independently at $25.4 million.  The
Companys pilot VAPEX (vapour extraction) project continued throughout 2002
with the injection of solvent into a low productivity heavy oil reservoir in
the Carruthers, Saskatchewan area.  This
research and development project is based on injecting a propane, butane and
natural gas mixture into the reservoir to reduce the viscosity of the heavy
oil, thereby improving both the production rate and ultimate recovery of oil
from the reservoir.  To date, Baytex
have seen positive results with the breakthrough of solvent at the producing
wells and enhanced production rates from three barrels per day to the 25
barrels per day range.  The Company
intends to continue this project throughout 2003 in order to gain further
understanding on the effectiveness of this enhanced recovery technique.  If successful, this technique could
significantly increase recoverable reserves at Carruthers and could also be key
to unlocking additional value from several of the Companys heavy oil
reservoirs.  5 
   Heavy
oil pricing has continued to be strong into the first quarter of 2003, allowing
aggressive development of our heavy oil assets.  Baytex has budgeted approximately $80 million for heavy oil
capital spending in 2003, including the drilling of 165 wells.  Activity will be focused on the development
of our Ardmore, Alberta property along with continued infill drilling at
adjacent Cold Lake, Alberta and development drilling throughout Baytexs
Saskatchewan properties.  Plains District  The
Plains District includes the Company's lands in Alberta south of Township 50
and west of the fourth Meridian.  After
completing the sale of light oil assets in the first quarter of 2002, Baytex
focused its attention on the development of natural gas in the core areas of
Ferrier/OChiese, Leahurst and Richdale within the Plains District.  During
2002, this district produced an average of 9,418 barrels of oil equivalent per
day consisting of 43.8 million cubic feet per day of natural gas and 2,124
barrels per day of light oil and natural gas liquids.  A total of 42 (31.0 net) wells were drilled in the area resulting
in one (0.4 net) oil well, 34 (23.6 net) gas wells and seven (7.0 net) dry and
abandoned wells for a success rate of 83 percent.  Total capital expenditures during the year included $48.0 million
in exploration and development activities and net dispositions of $52.0
million.  The Plains District contains
268,363 net undeveloped acres valued independently at $13.3 million at December
31, 2002.  The
Companys development program at Ferrier/OChiese included the drilling of 18
(9.3 net) wells resulting in 17 (8.9 net) gas wells and one (0.4 net) oil
well.  Production in this area increased
30 percent during the year, reaching 3,300 barrels of oil equivalent per day in
the first quarter of 2003.  Despite the
success in this area, the opportunity to capitalize on high natural gas prices
prompted the Company to pursue the sale of its assets in this area in January
2003.  This process has resulted in the
sale of a majority of the producing assets in the Ferrier/OChiese area in
March 2003 for proceeds of $133.3 million. 
Baytex has retained certain exploratory lands and the relatively
undeveloped Cow Lake property in this area for future exploration and
development purposes.  Leahurst,
a property the Company has been involved in since 1993, and Richdale continued
to provide shallow natural gas development opportunities during the year.  Baytex successfully completed 11 (10.3 net)
Mannville/Belly River natural gas wells and maintained production levels in excess
of 16 million cubic feet per day throughout the year.  Baytex was also successful in identifying natural gas targets
through the use of 3-D seismic programs. 
The Company has identified a current inventory of 50 locations that can
be drilled on lands in these areas.  At
Bon Accord in central Alberta, Baytex has successfully identified five
locations with multi-zone, natural gas potential in the Ellerslie and Sparky
formations.  The Company is also
pursuing low-pressure, in-fill natural gas locations in this area.  Success in these projects will better
utilize the large processing and transportation infrastructure that Baytex
operates in this area.  The
budget for this district for 2003 includes the drilling of 40 natural gas
wells, including 20 development locations in Leahurst and Richdale.  Capital spending of $40 million is planned
for this district.  Northern District  The
Northern District is situated in Northwestern Alberta and Northeastern British
Columbia and includes all of the Company's lands north of Township 50 and west
of the fifth Meridian.  Baytexs
Northern District demonstrated its ability to provide high impact gas plays
during 2002 with the discovery of a Slave Point natural gas well in the
Hamburg/Chinchaga area.  This discovery
has been followed up with another successful well in early 2003.  The Company is planning to construct an
eight million cubic feet per day gas plant in the area that is targeted to be
on stream by mid-summer 2003.  During
the year, the Northern District achieved average production of 4,086 barrels of
oil equivalent per day including 18.3 million cubic feet per day of natural gas
and 1,030 bbl per day of light oil and natural gas liquids.  Drilling in this district included 25 (23.8
net) wells resulting in one (0.5 net) oil well, 15 (14.8 net) gas wells, one
(0.5 net) service well and eight (8.0 net) dry and abandoned wells for a
success rate of 68 percent.  Capital
expenditures in the Northern District totalled $28.9 million, including
property acquisitions of $0.6 million.  At
Tangent/Dawson, Baytex continues to pursue natural gas opportunities in the
Bluesky and Notikewin formations. 
During 2002, five (5.0 net) working interest wells were drilled in this
area resulting in five  6 
   natural gas
wells.  Three of these wells have been
tied-in to a third party natural gas facility and are producing at a combined
2.5 million cubic feet per day.  The
remaining two wells will be brought on stream as soon as additional pipeline
and facility capacity is available.  Baytex is also pursuing light oil opportunities in this area.  Three wells are planned for 2003 testing
Slave Point, Beaverhill Lake and Granite Wash light oil targets.  The
Company continued to pursue development opportunities in our mature gas
producing areas at Goodfish/Lafond and Nina/Darwin in northern Alberta with
eight Bluesky gas wells drilled in 2002. 
These wells were tied in during the 2003 winter season, together with
the drilling of six additional development wells.  These activities will successfully replace production declines in
these areas in 2003 and set up further development opportunities for next
winters program.  The Company has plans
to spend $30 million in the Northern District in 2003 including the drilling of
19 wells.   The Northern District
continues to focus on finding opportunities within its 597,935 net acres of
undeveloped land independently valued at $37.7 million at year-end 2002.  LAND HOLDINGS  The
undeveloped land holdings of the Company have been independently evaluated as
at December 31, 2002, and are set forth in the following table:  Undeveloped
  
  ValueNet
  AcresGross
  (1)
  
  Net
  (2)
  
  MM
  $Heavy Oil District
  
  323,577
  
  315,596
  
  25.4Plains District
  
  346,548
  
  268,363
  
  13.3Northern District
  
  715,063
  
  597,935
  
  37.7Total
  
  1,385,188
  
  1,181,894
  
  76.4  
 Notes: (1)   Gross
means the total number of acres in which the Company has an interest. (2)   Net refers to the aggregate of the
percentage interests of the Company in the gross acres.  OIL AND GAS WELLS  The
following table summarizes Baytexs interests as at December 31, 2002 in oil
and natural gas wells which are producing or which are considered capable of
production.  All significant
non-producing natural gas wells are within 10 kilometres of an existing
pipeline.  Producing
  Wells
  
  Non-Producing
  WellsOil
  
  Natural
  Gas
  
  Oil
  
  Natural
  GasGross(1)
  
  Net(2)
  
  Gross(1)
  
  Net(2)
  
  Gross(1)
  
  Net(2)
  
  Gross(1)
  
  Net(2)Alberta
  
  309
  
  241
  
  386
  
  283
  
  180
  
  151
  
  240
  
  189Saskatchewan
  
  850
  
  799
  
  49
  
  45
  
  333
  
  316
  
  33
  
  32British Columbia
  
  
  
  
  
  
  
  
  
  
  
  
  
  8
  
  5Total
  
  1,159
  
  1,040
  
  435
  
  328
  
  513
  
  467
  
  281
  
  226  
 Notes: (1)Gross
refers to all wells in which Baytex owns a working interest. (2)Net
refers to the aggregate of the percentage working interests of Baytex in the
gross wells, before the deduction of royalties.  7 
   OIL AND GAS RESERVES  Outtrim
has prepared the Outtrim Report evaluating the proved and probable additional
crude oil, NGL and natural gas reserves of Baytexs properties as of December
31, 2002.  In preparing its report,
Outtrim obtained information from Baytex including land data, well information,
geological information, reservoir studies, estimates of on-stream dates,
contract information, current hydrocarbon product prices, operating cost data,
capital budget forecasts, financial data and future operating plans.  Other engineering, geological or economic
data required by Outtrim was obtained from public records, other operators and
from Outtrims non-confidential files. 
Outtrim did not conduct a field inspection.  The
following tables, based on the Outtrim Report, show the estimates as at the
dates indicated of Baytexs crude oil, natural gas and NGL reserves and the
present value of estimated future cash flow, including ARTC, for these reserves
using escalated and constant prices and costs as indicated.  The
present worth of estimated future cash flow is stated after provisions for
estimated future capital expenditures and abandonment costs for the wells net
of salvage value and prior to provision for income taxes.  CRUDE OIL AND
NATURAL GAS RESERVES AND
PRESENT WORTH OF ESTIMATED FUTURE CASH FLOW  ESCALATED
DOLLAR ECONOMICS  Remaining ReservesLight Crude Oil
  
  Heavy Crude Oil
  
  Natural Gas
  
  NGLsReserve Category
  
  Gross
  
  Net
  
  Gross
  
  Net
  
  Gross
  
  Net
  
  Gross
  
  Netmstb
  
  mstb
  
  mstb
  
  mstb
  
  mmcf
  
  mmcf
  
  mbbl
  
  mbblProved DevelopedProducing
  
  3,144
  
  2,830
  
  29,372
  
  26,054
  
  97,805
  
  78,599
  
  2,880
  
  1,973Non-Producing
  
  222
  
  195
  
  34,833
  
  29,223
  
  32,840
  
  25,985
  
  801
  
  545Proved Undeveloped
  
  403
  
  303
  
  36,709
  
  33,052
  
  20,830
  
  14,818
  
  1,010
  
  668Total Proved
  
  3,769
  
  3,328
  
  100,914
  
  88,329
  
  151,475
  
  119,402
  
  4,691
  
  3,186Probable Additional
  
  2,344
  
  1,991
  
  48,942
  
  43,143
  
  52,061
  
  41,793
  
  1,508
  
  1,020Total Before Risk
  
  6,113
  
  5,319
  
  149,856
  
  131,472
  
  203,536
  
  161,195
  
  6,199
  
  4,206Reduction Due to Risk
  
  (1,172
  )
  (995
  )
  (24,471
  )
  (21,571
  )
  (26,030
  )
  (20,896
  )
  (754
  )
  (510
  )Total After Risk
  
  4,941
  
  4,324
  
  125,385
  
  109,901
  
  177,506
  
  140,299
  
  5,445
  
  3,696  Present Value of Future Cash Flow Before Income
  Taxes Discounted at Rates ofReserve Category
  
  0%
  
  10%
  
  15%
  
  20%M$
  
  M$
  
  M$
  
  M$Proved DevelopedProducing
  
  754,267
  
  524,318
  
  470,119
  
  429,424Non-Producing
  
  502,901
  
  238,603
  
  187,455
  
  153,931Proved Undeveloped
  
  492,632
  
  254,201
  
  197,069
  
  157,181Total Proved
  
  1,749,800
  
  1,017,122
  
  854,643
  
  740,536Probable Additional
  
  802,190
  
  362,704
  
  277,104
  
  220,324Total Before Risk
  
  2,551,990
  
  1,379,826
  
  1,131,747
  
  960,860Reduction Due to Risk
  
  (401,095
  )
  (181,352
  )
  (138,552
  )
  (110,162
  )Total After Risk
  
  2,150,895
  
  1,198,474
  
  993,195
  
  850,698  8 
   CONSTANT
DOLLAR ECONOMICS  Remaining ReservesLight Crude Oil
  
  Heavy Crude Oil
  
  Natural Gas
  
  NGLsReserve Category
  
  Gross
  
  Net
  
  Gross
  
  Net
  
  Gross
  
  Net
  
  Gross
  
  Netmstb
  
  mstb
  
  mstb
  
  mstb
  
  mmcf
  
  mmcf
  
  mbbl
  
  mbblProved DevelopedProducing
  
  3,144
  
  2,829
  
  29,366
  
  25,928
  
  97,795
  
  78,977
  
  2,880
  
  1,977Non-Producing
  
  222
  
  195
  
  34,822
  
  29,318
  
  32,821
  
  26,161
  
  799
  
  546Proved Undeveloped
  
  403
  
  302
  
  36,677
  
  32,805
  
  20,830
  
  14,924
  
  1,010
  
  668Total Proved
  
  3,769
  
  3,326
  
  100,865
  
  88,051
  
  151,446
  
  120,062
  
  4,689
  
  3,191Probable Additional
  
  2,330
  
  1,977
  
  48,932
  
  42,987
  
  52,063
  
  42,077
  
  1,508
  
  1,023Total Before Risk
  
  6,099
  
  5,303
  
  149,797
  
  131,038
  
  203,509
  
  162,139
  
  6,197
  
  4,214Reduction Due to Risk
  
  (1,165
  )
  (988
  )
  (24,466
  )
  (21,493
  )
  (26,031
  )
  (21,038
  )
  (754
  )
  (511
  )Total After Risk
  
  4,934
  
  4,315
  
  125,331
  
  109,545
  
  177,478
  
  141,101
  
  5,443
  
  3,703   Present Value of Future Cash Flow Before Income
  Taxes Discounted at Rates ofReserve Category
  
  0%
  
  10%
  
  15%
  
  20%M$
  
  M$
  
  M$
  
  M$Proved DevelopedProducing
  
  935,825
  
  651,697
  
  579,963
  
  525,994Non-Producing
  
  627,470
  
  309,531
  
  244,459
  
  201,133Proved Undeveloped
  
  646,756
  
  352,494
  
  278,720
  
  226,383Total Proved
  
  2,210,051
  
  1,313,722
  
  1,103,142
  
  953,510Probable Additional
  
  1,001,966
  
  482,939
  
  374,153
  
  300,743Total Before Risk
  
  3,212,017
  
  1,796,661
  
  1,477,295
  
  1,254,253Reduction Due to Risk
  
  (500,983
  )
  (241,469
  )
  (187,076
  )
  (150,371
  )Total After Risk
  
  2,711,034
  
  1,555,192
  
  1,290,219
  
  1,103,882  
 Notes: (1)Gross
reserves mean the total working and royalty interest share of remaining
recoverable reserves owned by the Company before deductions of royalties
payable to others. Net reserves mean the Companys gross reserves less all royalties
payable to others.  (2)Probable additional cash flows presented in the Outtrim Report are
prepared at full value assuming that the quantities and values of the forecast
production are unrisked. For the purpose of determining the values presented in
these tables, a risk factor of 50% has been applied to the probable additional
reserves and cash flows.  (3)Proved Reserves are those reserves estimated as recoverable under current
technology and anticipated economic conditions for the escalated dollar
economics and existing economic conditions for the constant dollar economics,
from that portion of a reservoir which can be reasonably evaluated as
economically productive on the basis of analysis of drilling, geological,
geophysical and engineering data, including the reserves to be obtained by
enhanced recovery processes demonstrated to be economical and technically
successful in the subject reservoir.  (a)Proved Producing Reserves are those developed reserves that are actually on production or, if
not producing, that could be recovered from existing wells or facilities and
where the reason for the current non-producing status is the choice of the
owner rather than the lack of markets or some other reasons. An illustration of
such a situation is where a well or zone is capable but is shut in because its
deliverability is not required to meet contract commitments.  (b)Proved Non-Producing Reserves are those developed reserves that are not currently producing
either due to lack of facilities and/or markets.  (c)Proved Undeveloped Reserves are proved reserves which are expected to be recovered from new
wells on undrilled acreage, or from existing wells where a relatively major
expenditure is required for recompletion. Reserves on undrilled acreages are
limited to those drilling units offsetting productive units, which are
reasonably certain of production when drilled.  9 
   (4)Probable Additional Reserves are those reserves which analysis of drilling, geological,
geophysical and engineering data does not demonstrate to be proved under current
technology and anticipated economic conditions for the escalated dollar
economics and existing economic conditions for the constant dollar economics,
but where such analysis suggests the likelihood of their existence and future
recovery. Probable additional reserves to be obtained by the application of
enhanced recovery processes will be the increased recovery over and above that
estimated in the proved category which can be realistically estimated for the
pool on the basis of enhanced recovery process which can be reasonably expected
to be instituted in the future.  (5)Price Forecast  OUTRIM
SZABO ASSOCIATES LTD. PRICE FORECAST
EFFECTIVE DATE DECEMBER 31, 2002 Oil
Prices  YEAR
  
  OIL FIELD 
  COSTS 
  INFLATION %
  
  EXCHANGE 
  $CDN/$US
  
  WTI @ 
  Cushing 
  $US/bbl
  
  EDM. OIL 
  PRICE D2S2 
  $/bbl
  
  HEAVY OIL 
  25 API 
  HARDISTY 
  $bbl
  
  HEAVY OIL 
  12 API 
  HARDISTY 
  $bbl2003
  
  0.0
  
  0.640
  
  26.00
  
  39.73
  
  31.23
  
  25.732004
  
  1.5
  
  0.640
  
  23.35
  
  35.56
  
  29.06
  
  24.062005
  
  1.5
  
  0.640
  
  21.63
  
  32.88
  
  26.88
  
  22.132006
  
  1.5
  
  0.640
  
  21.96
  
  33.37
  
  27.87
  
  23.122007
  
  1.5
  
  0.640
  
  22.29
  
  33.87
  
  28.37
  
  23.622008
  
  1.5
  
  0.640
  
  22.62
  
  34.38
  
  28.88
  
  24.132009
  
  1.5
  
  0.640
  
  22.96
  
  34.89
  
  29.39
  
  24.642010
  
  1.5
  
  0.640
  
  23.31
  
  35.42
  
  29.92
  
  25.172011
  
  1.5
  
  0.640
  
  23.66
  
  35.95
  
  30.45
  
  25.702012
  
  1.5
  
  0.640
  
  24.01
  
  36.49
  
  30.99
  
  26.24  escalated oil and NGL prices at 1.5% per year
thereafter  Natural Gas Prices  Alberta Plant Gate PriceYEAR
  
  TCGSL 
  $/mcf
  
  PAN 
  ALBERTA 
  $/mcf
  
  PRO GAS 
  $/mcf
  
  DIRECT 
  $/mcf
  
  SPOT 
  $/mcf2003
  
  5.35
  
  4.60
  
  5.31
  
  5.51
  
  5.662004
  
  4.82
  
  4.22
  
  4.79
  
  4.95
  
  5.072005
  
  4.44
  
  3.99
  
  4.42
  
  4.54
  
  4.632006
  
  4.53
  
  4.23
  
  4.51
  
  4.59
  
  4.652007
  
  4.61
  
  4.46
  
  4.61
  
  4.65
  
  4.682008
  
  4.72
  
  4.72
  
  4.72
  
  4.72
  
  4.722009
  
  4.77
  
  4.77
  
  4.77
  
  4.77
  
  4.772010
  
  4.83
  
  4.83
  
  4.83
  
  4.83
  
  4.832011
  
  4.88
  
  4.88
  
  4.88
  
  4.88
  
  4.882012
  
  4.94
  
  4.94
  
  4.94
  
  4.94
  
  4.94  escalated natural gas prices at 1.5% per year
thereafter  (6)Product prices in the constant price evaluations are based on actual
prices received for oil and natural gas liquids and natural gas for December
2002.  The constant price assumptions assume the
continuance of current laws, regulations and operating costs in effect on the
effective date of the Outtrim Report. In addition, operating and capital costs
have not been increased on an inflationary basis.  (7)ARTC varies from a maximum of 75% of $2.0 million when the oil
price is below US $15 per barrel to a minimum of 25% of $2.0 million when
the oil price is above US$30 per barrel. For the cash flow projection, the ARTC
program was assumed to stay in place for a period of 10 years.  (8)Outtrim estimates the total capital costs, including abandonment
costs, net to Baytex to achieve the estimated future net proved and probable
production revenues set out in the Outtrim Report are as follows:  10 
   Year
  
  Escalated
  Price
  Case ($ millions)
  
  Constant
  Price 
  Case ($ millions)2003
  
  81
  
  812004
  
  64
  
  632005
  
  84
  
  81Thereafter
  
  72
  
  59Total discounted at 0%
  
  301
  
  284Total discounted at 10%
  
  221
  
  216Total discounted at 15%
  
  201
  
  197Total discounted at 20%
  
  186
  
  183
  (9)Cash flow is income derived from the sale of net reserves, less all
capital costs, production taxes, and operating costs and before provision for
income taxes and administrative overhead costs.  RECONCILIATION OF RESERVES  A reconciliation
of the Companys oil and gas reserves for the two-year period ended
December 31, 2002 is set out below:  Crude
  Oil and NGLS (mmbls)
  
  Natural
  Gas (mmcf)Proved
  
  Probable
  
  Total
  
  Proved
  
  Probable
  
  TotalDecember 31, 2000
  
  105,022
  
  48,038
  
  153,060
  
  98,048
  
  30,202
  
  128,250Discoveries and extensions
  
  11,049
  
  4,054
  
  15,103
  
  19,705
  
  3,421
  
  23,126Acquisitions
  
  12,832
  
  7,241
  
  20,073
  
  61,162
  
  18,050
  
  79,212Dispositions
  
  (7,593
  )
  (5,809
  )
  (13,402
  )
  (6,527
  )
  (1,725
  )
  (8,252
  )Revisions of prior estimates
  
  477
  
  (1,190
  )
  (713
  )
  (11,887
  )
  (7,181
  )
  (19,068
  )Production
  
  (11,566
  )
  
  
  (11,566
  )
  (25,848
  )
  
  
  (25,848
  )December 31, 2001
  
  110,221
  
  52,334
  
  162,555
  
  134,653
  
  42,767
  
  177,420Discoveries and extensions
  
  8,588
  
  5,059
  
  13,647
  
  53,443
  
  13,114
  
  66,557Acquisitions
  
  6,675
  
  2,364
  
  9,039
  
  1,738
  
  447
  
  2,185Dispositions
  
  (6,104
  )
  (3,449
  )
  (9,553
  )
  (19,721
  )
  (4,118
  )
  (23,839
  )Revisions of prior estimates
  
  (107
  )
  (3,514
  )
  (3,621
  )
  7,844
  
  (149
  )
  7,695Production
  
  (9,899
  )
  
  
  (9,899
  )
  (26,482
  )
  
  
  (26,482
  )December 31, 2002
  
  109,374
  
  52,794
  
  162,168
  
  151,475
  
  52,061
  
  203,536  11 
   DRILLING ACTIVITY  The
following table summarizes the Companys drilling results for the years ended
December 31, 2002 and 2001.  Year ended December 31,2001
  
  2002Gross(1)
  
  Net(2)
  
  Gross(1)
  
  Net(2)Oil
  
  106
  
  99.6
  
  63
  
  58.2Natural Gas
  
  51
  
  39.9
  
  81
  
  70.3Service
  
  3
  
  2.5
  
  3
  
  2.4Dry & Abandoned
  
  26
  
  25.9
  
  32
  
  28.7Total
  
  186
  
  167.9
  
  179
  
  159.6  
 Notes:  (1)Gross refers to all wells in which the Company has either a
working interest or a royalty interest.  (2)Net refers to the aggregate of the percentage working interests of
the Company in the gross wells, before the deduction of royalties. HISTORY  The following tables show the Companys
average working interest sales volume before deduction of royalties payable to
others, average netbacks received and net oil and gas capital expenditures
incurred for each of the last eight fiscal quarters and the years then ended:  Average
Daily Sales  Three
  Months EndedDec 31, 2002
  
  Sept 30, 2002
  
  June 30, 2002
  
  Mar 31, 2002
  
  TotalLight/medium crude oil and NGL (bbl/d)
  
  2,909
  
  2,999
  
  2,904
  
  3,818
  
  3,154Heavy crude oil (bbl/d)
  
  25,009
  
  23,504
  
  24,498
  
  22,838
  
  23,967Total crude oil and NGL (bbl/d)
  
  27,918
  
  26,503
  
  27,402
  
  26,656
  
  27,121Natural gas (mmcf/d)
  
  71.8
  
  71.3
  
  73.3
  
  73.7
  
  72.6  Three
  Months EndedDec 31, 2001
  
  Sept 30, 2001
  
  June 30, 2001
  
  Mar 31, 2001
  
  TotalLight/medium crude oil and NGL (bbl/d)
  
  5,808
  
  6,077
  
  4,782
  
  3,911
  
  5,152Heavy crude oil (bbl/d)
  
  24,528
  
  29,078
  
  26,545
  
  25,970
  
  26,533Total crude oil and NGL (bbl/d)
  
  30,336
  
  35,155
  
  31,327
  
  29,881
  
  31,685Natural gas (mmcf/d)
  
  75.9
  
  78.2
  
  71.3
  
  57.6
  
  70.8  12 
   Crude
Oil and NGL Operating Netbacks ($ per bbl)  Three
  Months EndedDec 31, 2002
  
  Sept 30, 2002
  
  June 30, 2002
  
  Mar 31, 2002
  
  TotalSales revenue(1)
  
  25.72
  
  29.00
  
  26.54
  
  23.46
  
  26.19Royalties(2)
  
  (3.80
  )
  (4.90
  )
  (3.84
  )
  (3.03
  )
  (3.89
  )Operating costs(3)
  
  (6.11
  )
  (5.98
  )
  (5.84
  )
  (5.96
  )
  (5.97
  )Operating Netback
  
  15.81
  
  18.12
  
  16.86
  
  14.47
  
  16.33Crude oil pricesLight/medium crude oil and NGL
  
  37.67
  
  37.36
  
  34.53
  
  27.58
  
  33.86Heavy crude oil
  
  26.09
  
  31.03
  
  26.64
  
  21.58
  
  26.39  Three
  Months EndedDec 31, 2001
  
  Sept 30, 2001
  
  June 30, 2001
  
  Mar 31, 2001
  
  TotalSales revenue(1)
  
  15.31
  
  23.98
  
  18.01
  
  16.30
  
  18.63Royalties(2)
  
  (1.61
  )
  (3.85
  )
  (2.31
  )
  (2.17
  )
  (2.53
  )Operating costs(3)
  
  (5.74
  )
  (5.72
  )
  (6.15
  )
  (5.55
  )
  (5.79
  )Operating Netback
  
  7.96
  
  14.41
  
  9.55
  
  8.58
  
  10.31Crude oil pricesLight/medium crude oil and NGL
  
  25.41
  
  35.37
  
  37.53
  
  38.65
  
  33.65Heavy crude oil
  
  10.39
  
  23.75
  
  16.77
  
  14.62
  
  16.69  
 Notes: (1)After
inclusion of financial derivative contracts.  (2)After
inclusion of ARTC.  (3)Operating
costs are expenses incurred in the operation of producing properties and
include items such as field staff salaries, power, fuel, chemicals, repairs and
maintenance, property taxes, processing and treating fees, overhead fees and
other costs.  Natural
Gas Operating Netbacks ($ per mcf)  Three
  Months EndedDec 31, 2002
  
  Sept 30, 2002
  
  June 30, 2002
  
  Mar 31, 2002
  
  TotalSales revenue(1)
  
  5.22
  
  3.65
  
  3.79
  
  3.44
  
  4.03Royalties(2)
  
  (1.04
  )
  (0.71
  )
  (0.64
  )
  (0.68
  )
  (0.77
  )Operating costs(3)
  
  (0.62
  )
  (0.61
  )
  (0.60
  )
  (0.60
  )
  (0.61
  )Operating Netback
  
  3.56
  
  2.33
  
  2.55
  
  2.16
  
  2.65  Three
  Months EndedDec 31, 2001
  
  Sept 30, 2001
  
  June 30, 2001
  
  Mar 31, 2001
  
  TotalSales revenue(1)
  
  3.09
  
  3.35
  
  5.11
  
  6.83
  
  4.42Royalties(2)
  
  (0.60
  )
  (0.75
  )
  (1.48
  )
  (1.85
  )
  (1.11
  )Operating costs(3)
  
  (0.69
  )
  (0.70
  )
  (0.56
  )
  (0.57
  )
  (0.64
  )Operating Netback
  
  1.80
  
  1.90
  
  3.07
  
  4.41
  
  2.67  
 Notes: (1)After
inclusion of financial derivative contracts.  (2)After
inclusion of ARTC.  (3)Operating
costs are expenses incurred in the operation of producing properties and
include items such as field staff salaries, power, fuel, chemicals, repairs and
maintenance, property taxes, processing and treating fees, overhead fees and
other costs.  13 
   Net
Oil and Gas Capital Expenditures ($000s)  Three
  Months EndedDec 31, 2002
  
  Sept 30, 2002
  
  June 30, 2002
  
  Mar 31, 2002
  
  TotalExploration and land (including drilling)
  
  7,346
  
  6,522
  
  5,857
  
  8,960
  
  28,685Development
  
  25,052
  
  20,705
  
  23,941
  
  28,619
  
  98,317Other
  
  2,100
  
  2,574
  
  2,712
  
  1,947
  
  9,333Acquisitions, net of dispositions
  
  32,748
  
  471
  
  3,277
  
  (46,363
  )
  (9,867
  )67,246
  
  30,272
  
  35,787
  
  (6,837
  )
  126,468   Three
  Months EndedDec 31, 2001
  
  Sept 30, 2001
  
  June 30, 2001
  
  Mar 31, 2001
  
  TotalExploration and land (including drilling)
  
  3,453
  
  6,968
  
  11,981
  
  14,154
  
  36,556Development
  
  14,459
  
  23,396
  
  25,510
  
  27,950
  
  91,315Other
  
  1,840
  
  2,137
  
  2,080
  
  1,961
  
  8,018Acquisitions, net of dispositions
  
  (51,716
  )
  705
  
  291,270
  
  (295
  )
  239,964(31,964
  )
  33,206
  
  330,841
  
  43,770
  
  375,853   FUTURE COMMITMENTS  At December 31, 2002, the Company had in
place contracts for the following:  Period
  
  Volume
  
  Price
  
  IndexOilPrice collar
  
  Calendar
  2003
  
  2,500 bbl/d
  
  US$20.00  $26.05
  
  WTIPrice collar
  
  Calendar
  2003
  
  5,000 bbl/d
  
  US$20.00  $26.60
  
  WTIPrice collar
  
  Calendar
  2003
  
  2,500 bbl/d
  
  US$20.00  $27.00
  
  WTI  Period
  
  Amount
  
  Exchange RateForeign currency swap
  
  January 1998 to December 2005
  
  US$315,000 per month
  
  CAD/USD $1.4228  In October 2002, the Company entered into a
long-term crude oil supply contract with a third party that requires the
delivery of 20,000 barrels per day of Lloydminster Blend crude oil at a price
fixed at 71 percent of NYMEX WTI oil price. 
The contract is for an initial term of five years commencing January 1,
2003.  The volumes contracted under this
contract will increase from 9,000 barrels per day in January 2003 to 20,000
barrels per day in October 2003 and thereafter.  For the period
November 1, 2002 to October 31, 2003, the Company has entered into natural gas
sales contracts with third parties for 15,000 GJ per day for fixed prices
averaging $5.35 per GJ and 10,000 GJ per day of collar contracts with prices
between $4.20 per GJ and $7.22 per GJ.  14 
   DIRECTORS AND
OFFICERS OF BAYTEX  The
name, municipality of residence and principal occupation during the last five
years of each of the directors and senior officers of Baytex are as follows:  Name and Municipality of 
  Residence
  
  Positions
  Held(6)(7)
  
  Principal
  Occupation During Last Five YearsJohn A. Brussa(1)(2)(4)(5)Calgary, Alberta
  
  Director
  
  Partner,
  Burnet, Duckworth & Palmer LLP, Barristers and SolicitorsW.A. Blake
  Cassidy(1)(2)(5)
  Calgary, Alberta
  
  Director
  
  Retired
  BankerRaymond T.
  Chan 
  Calgary, Alberta
  
  Senior
  Vice-President, Chief Financial Officer and Director
  
  Senior
  Vice-President of Baytex since October, 1998; prior thereto Senior
  Vice-President and Chief Financial Officer of Tarragon Oil and Gas LimitedFrederic C.
  Co1es(3)(4)(5) 
  DeWinton, Alberta
  
  Director
  
  Independent
  Businessman since April 1, 2002; prior thereto Executive Chairman, Applied
  Terravision Systems Ltd.Dennis L.
  Nerland(1)(5) 
  Calgary, Alberta
  
  Director
  
  Partner,
  Shea Nerland Calnan, Barristers and SolicitorsDale O.
  Shwed(2)(3)(8)
  Calgary, Alberta
  
  President,
  Chief Executive Officer and Director
  
  President of
  BaytexRalph W.
  Gibson
  Calgary, Alberta
  
  Vice-President,
  Marketing
  
  Vice-President,
  Marketing of Baytex since September, 2001; prior thereto Vice-President,
  Crude Oil of Canpet Energy Group Inc. since November 2000; prior thereto
  Vice-President, Marketing, Ranger Oil Limited since September 1997Daniel B.
  Horner 
  Calgary, Alberta
  
  Vice-President,
  Land
  
  Vice-President,
  Land of Baytex since January, 2000; prior thereto Land Manager and Solicitor
  of Baytex since March, 1999; prior thereto Solicitor and Senior Landman of
  Amber Energy Inc. (and its successor, AEC Oil & Gas) since December, 1997John G.
  Leach 
  Calgary, Alberta
  
  Vice-President,
  Finance and Administration
  
  Vice-President,
  Finance and Administration of Baytex since October, 1998; and prior thereto
  Treasurer of Baytex since December, 1996S. Dale
  McAuley 
  Calgary, Alberta
  
  Vice-President,
  Operations
  
  Vice-President,
  Operations of BaytexRichard W.
  Naden 
  Calgary, Alberta
  
  Vice-President,
  Production
  
  Vice-President,
  Production of Baytex  15 
   Name and Municipality of 
  Residence
  
  Positions
  Held(6)(7)
  
  Principal
  Occupation During Last Five YearsGarry J. Wasylycia Calgary, Alberta
  
  Vice-President,
  Exploration
  
  Vice-President,
  Exploration of Baytex since July, 1998; and prior thereto Senior Geologist of
  Baytex since May, 1996Shannon M. Gangl Calgary, Alberta
  
  Secretary
  
  Partner,
  Burnet, Duckworth & Palmer LLP, Barristers and Solicitors since January,
  1999; prior thereto Associate, Burnet, Duckworth & Palmer LLP, Barristers
  and Solicitors  
 Notes: (1)Member of the Audit Committee.  (2)Member of the Compensation Committee.  (3)Member of the Environmental Management Committee.  (4)Member of the Corporate Governance Committee.  (5)Member of the Reserve Committee.  (6)The following individuals were initially appointed or elected
directors of Baytex on the following dates: Mr. Shwed (June 3, 1993),
Mr. Cassidy (February 8, 1994), Mr. Brussa (October 8,
1997), Mr. Coles (May 26, 1998) and Mr. Chan (October 5,
1998).  Mr. Nerland was a director
of Baytex from October, 1993 to October, 1997, when he resigned in connection
with the business combination with Dorset. 
Mr. Nerland was re-elected as a director on May 26, 1998.  (7)The directors will hold office until the next annual meeting of
holders of Common Shares or until their successor is duly elected or appointed,
unless their office is earlier vacated in accordance with the Companys
By-Laws.  (8)Mr. Shwed was a director of Echelon Energy Inc., a private
company incorporated under the ABCA.  In
September 1999, a receiver manager was appointed over the assets of Echelon.  As at March 3, 2002, the directors and senior
officers of Baytex, as a group, beneficially owned, directly or indirectly,
1,243,122 Common Shares constituting approximately 2.3 percent of the issued
and outstanding Common Shares.  Some of the directors and officers of the
Company are directors and officers of other private and public companies.  Some of these private and public companies
may, from time to time, be involved in business transactions or banking
relationships which may create situations in which conflicts might arise.  Any such conflicts shall be resolved in
accordance with the procedures and requirements of the relevant provisions of
the ABCA, including the duty of such directors and officers to act honestly and
in good faith with a view to the best interests of the Company.  PERSONNEL  As at December 31, 2002, Baytex had 143
employees.  DIVIDEND RECORD  Baytex has not declared or paid any dividends
on its Common Shares since its incorporation, and does not foresee the
declaration or payment of any dividends on the Common Shares in the near
future.  Any decision to pay dividends
on the Common Shares will be made by the board of directors on the basis of
Baytexs earnings, financial requirements and other conditions existing at such
future time.  MARKET FOR
SECURITIES  The Common Shares are listed and posted for
trading on the TSX under the trading symbol BTE.  17 
   MANAGEMENTS DISCUSSION AND ANALYSIS  The following discussion and analysis should be read in conjunction with
the Companys audited consolidated financialstatements for the fiscal years ended
December 31, 2002 and 2001.  Per barrel
of oil equivalent (boe) amounts have been calculated using a conversion rate
of six thousand cubic feet of natural gas to one barrel of oil.  Corporate
Strategy As a mid-sized public Canadian oil and gas producer, Baytex focuses its
attention on the low-cost development and production of its heavy oil and
natural gas assets in the Western Canadian Sedimentary Basin.   The Company emphasizes the full-cycle
exploration and development activity targeting operated, high working interest,
heavy oil and natural gas reserves that can be discovered and produced quickly
at a below average cost.  Baytex
enhances this activity with the strategic acquisition of corporations and
individual properties that contain assets that are complementary to the
Companys existing assets and, more importantly, provide significant
development potential.  2002 Overview During the past year, Baytex focused on
financial stability.  A strategic
divestiture program that began in the fourth quarter of 2001 and continued
through the first quarter of 2002 significantly strengthened Baytexs financial
position.  The focus on financial
stability continued throughout 2002 with a conservative capital-spending
program that emphasized financial discipline, while successfully positioning
the Company for future production growth. 
Exploration and development spending was enhanced by the key acquisition
of heavy oil assets at Ardmore, Alberta in the fourth quarter.  This acquisition provides significant heavy
oil development opportunities for 2003 and beyond.  In addition to the Ardmore purchase, the signing of a five-year
heavy oil supply agreement with a U.S.  based refining company further
highlighted the Companys commitment to heavy oil.  Commencing in 2003, this agreement allows Baytex to sell the
majority of its heavy oil production at a fixed differential to benchmark West
Texas Intermediate (WTI) price, thereby significantly reducing the added
volatility of the Companys cash flow from its heavy oil production.  Production The Companys average production for fiscal 2002 decreased by 10 percent
to 39,214 barrels of oil equivalent per day from 43,488 barrels of oil
equivalent per day for fiscal 2001. 
This decrease was the result of property dispositions that occurred in
the fourth quarter of 2001 and the first quarter of 2002 along with a decrease
in capital spending on heavy oil in the last half of 2001.  Light oil production decreased 39 percent to 3,154 barrels per day
during 2002 from 5,152 barrels per day in 2001.  Heavy oilproduction during 2002 decreased by 10
percent to 23,967 barrels per day from 26,533 barrels per day during fiscal
2001. Natural gas production for 2002 increased by 2 percent to 72.6 million
cubic feet per day compared to 70.8 million cubic feet per day for the prior
year.  Production
  by Area
  
  Conventional Oil
  and NGLs
  
  Heavy Oil
  
  Natural Gas
  
  Barrels of Oil
  Equivalent(bbls/d)
  
  (bbls/d)
  
  (mmcf/d)
  
  (boe/d)2002Heavy Oil District
  
  
  
  23,967
  
  10.5
  
  25,710Plains District
  
  2,124
  
  
  
  43.8
  
  9,418Northern District
  
  1,030
  
  
  
  18.3
  
  4,086Total
  Production
  
  3,154
  
  23,967
  
  72.6
  
  39,2142001Heavy Oil District
  
  368
  
  26,533
  
  11.5
  
  28,813Plains District
  
  3,721
  
  
  
  35.5
  
  9,192Northern District
  
  1,063
  
  
  
  23.8
  
  5,483Total
  Production
  
  5,152
  
  26,533
  
  70.8
  
  43,488  18 
   Revenue Petroleumand natural gas sales for 2002 increased by 11
percent to $365.9 million from $329.7 million for fiscal 2001.  Benchmark WTI crude oil averaged US$26.08
per barrel for 2002, representing a one percent increase over the US$25.90 per
barrel for 2001.  Correspondingly,
Baytexs light oil and NGLs price increased to $33.86 per barrel from $33.65
per barrel.  The Companys heavy oil
price increased 58 percent to $26.39 per barrel from $16.69 per barrel, as
heavy oil differentials decreased from 2001 with Baytexs heavy oil receiving
66 percent of the Canadian par crude price during fiscal 2002 compared to 43
percent in 2001.  Natural gas prices were
11 percent lower in 2002 averaging $3.94 per thousand cubic feet compared to
$4.42 per thousand cubic feet during the previous year.  Overall, after accounting for financial
derivative contracts, Baytex averaged $25.56 per barrel of oil equivalent for
2002 production, a 23 percent increase from $20.77 per barrel of oil equivalent
received in the prior year.  For 2002, light oil revenue decreased 38 percent over 2001, as
production decreased 39 percent while wellhead prices were consistent.  Revenue from heavy oil increased 43 percent
as the 10 percent decreased in production was offset by the 58 percent increase
in wellhead prices.  Natural gas revenue
decreased nine percent as production increased two percent and wellhead prices
declined by 11 percent.  Gross
  Revenue Analysis
  
  2002
  
  2001$000s
  
  $/Unit
  
  $000s
  
  $/UnitOil Revenue (barrels)Light oil
  
  38,985
  
  33.86
  
  63,288
  
  33.65Heavy oil
  
  230,874
  
  26.39
  
  161,681
  
  16.69Derivative contract loss
  
  (10,622
  )
  (1.07
  )
  (9,513
  )
  (0.82
  )Total oil revenue
  
  259,237
  
  26.19
  
  215,456
  
  18.63Natural gas revenue (mcf)
  
  104,284
  
  3.94
  
  114,244
  
  4.42Derivative contract gain
  
  2,339
  
  0.09
  
  
  
  Total natural gas revenue
  
  106,623
  
  4.03
  
  114,244
  
  4.42Total revenue (boe @ 6:1)
  
  365,860
  
  25.56
  
  329,700
  
  20.77  Royalties Total royalties increased two percent to $58.9 million for the year
ended December 2002 from $57.8 million for the same period last year due to an
increase in revenue and an increase in heavy oil royalty rates.  The overall royalty rate for 2002 was 15.7
percent of sales compared to 17 percent of sales for fiscal 2001.  The decrease in the overall royalty rate
resulted from the sale of properties at the end of 2001 and in the first
quarter of 2002 that carried a higher royalty burden.  In 2002, royalties were 16.7 percent of sales for light oil (2001
 19.1 percent), 13.9 percent for heavy oil (2001  10.6 percent) and 19.5
percent for natural gas (2001  25.1 percent).  Operating Expenses Operating expenses for 2002 decreased 10 percent to $75.2 million from
$83.4 million during the previous year. 
This decrease is attributable to a 10 percent decrease in overall
production.  For 2002, operating
expenses by product were $5.83 per barrel of light oil, $5.99 per barrel of
heavy oil and $0.61 per thousand cubic feet of natural gas.  In comparison, operatingexpenses by product for 2001 were $6.82 per barrel of light oil, $5.59 per
barrel of heavy oil and $0.64 per thousand cubic feet of natural gas.  Overall operating expenses were consistent
on a unit basis at $5.26 per barrel of oil equivalent during 2002 and 2001.  19 
   Operating Netbacks Conventional
  oil
  & NGLs ($/bbl)
  
  Heavy
  Oil
  ($/bbl)
  
  Total
  Oil & NGLs
  ($/bbl)
  
  Natural
  Gas
  ($/mcf)
  
  BOE
  ($/boe)2002
  
  2001
  
  2002
  
  2001
  
  2002
  
  2001
  
  2002
  
  2001
  
  2002
  
  2001Sales price
  
  33.86
  
  33.65
  
  26.39
  
  16.69
  
  27.26
  
  19.45
  
  3.94
  
  4.42
  
  26.14
  
  21.37Royalties
  
  (5.67
  )
  (6.44
  )
  (3.66
  )
  (1.77
  )
  (3.89
  )
  (2.53
  )
  (0.77
  )
  (1.11
  )
  (4.12
  )
  (3.64
  )Operating costs
  
  (5.83
  )
  (6.82
  )
  (5.99
  )
  (5.59
  )
  (5.97
  )
  (5.79
  )
  (0.61
  )
  (0.64
  )
  (5.26
  )
  (5.26
  )Net revenue
  
  22.36
  
  20.39
  
  16.74
  
  9.33
  
  17.40
  
  11.13
  
  2.56
  
  2.67
  
  16.76
  
  12.47  Note: Sales prices in this table are before the loss/gain recognized on
financial derivative contracts.  General and Administrative
Expenses General andadministrative expenses, after capitalization,
increased to $6.7 million for 2002 compared to $5.3 million for 2001.  On a per unit of production basis, these
expenses increased during 2002 to $0.47 per barrel of oil equivalent from $0.33
per barrel of oil equivalent in 2001. 
This increase was due to increased staff levels associated with the
Companys 2001 corporate acquisitions. 
In accordance with the full cost accounting policy, $6.7 million of
expenses were capitalized in 2002 compared to $5.3 million in 2001.  General and
  Administrative Expenses
  
  2002
  
  2001($
  thousands)Gross corporate expense
  
  19,328
  
  16,504Operators recoveries
  
  (5,842
  )
  (5,980
  )Subtotal
  
  13,486
  
  10,524Capitalized expense
  
  (6,743
  )
  (5,262
  )Net expense
  
  6,743
  
  5,262  Interest Expense For the year ended December 31, 2002, interest expenses decreased to
$25.2 million from $32.9 million for the prior year.  Average debt levels decreased from $388.8 million in 2001 to
$336.9 million in 2002.  Interest
expense was further reduced by interest rate swap agreements that the Company
negotiated in December 2001.  These
swaps were settled during the third quarter of 2002 for total proceeds of $14.1
million, which is being amortized as a reduction of interest expense.  This amortization reduces the effective
interest rate of the Company's senior secured notes from 7.23 percent to 5.7
percent until November 2004 and the senior subordinated notes form 10.5 percent
to 9.2 percent until February 2006.  Depletion and Depreciation Depletion and depreciation,before ceiling test considerations,
decreased to $106.8 million for 2002 compared to $132.9 million for 2001. The
decrease is due to lower production and the ceiling test write-down taken at
year-end 2001.  On a unit of production
basis, the provision for 2002 was $7.46 per barrel of oil equivalent compared
to $8.37 per barrel of oil equivalent for last year.  Due to wide heavy oil differentials at year-end 2001, the Company
incurred a $131.3 million ceiling test write-down (net of $103.2 million of
future income taxes).  This amount was
recognized as additional depletion and depreciation for the year ended December
31, 2001.  Site Restoration Costs Site restoration costs for 2002 decreased to $2.8 million from $3.9
million last year due to lower production and property dispositions. On a unit
of production basis, the provision for 2002 was $0.20 per barrel of oil equivalent
compared to $0.25 per barrel of oil equivalent for the previous year.  Foreign Exchange Effective January 1, 2002, the Company adopted the Canadian Institute of
Chartered Accountants (CICA) amended accounting standard with respect to
foreign currency translation.  The
amended standard eliminates the practice to defer and amortize foreign exchange
gains and losses on long-term monetary items. 
As a result, all foreign exchange gains and losses on long-term monetary
items are now recognized in earnings based on  20 
   the exchange rates at the end of the reporting periods.  The amended standard also requires that
prior years comparative figures be restated to comply with the new standard.  The foreign exchange gain for the year ended December 31, 2002 was $2.7
million compared to a loss of $16.3 million for the last year. The 2002 gain is
based on the translation of the Companys U.S. dollar denominated long-term
debt at 0.6331 at December 31, 2002 compared to 0.6279 at December 31, 2001.
The 2001 loss is based on the translation of the U.S. dollar denominated senior
secured notes at 0.6279 at December 31, 2001 compared to 0.6660 at December 31,
2000 along with the senior subordinated notes translated at 0.6279 at December
31, 2001 compared to 0.6582 on February 13, 2001 when the notes were issued.  Income Taxes Current tax expenses were $9.7 million for
2002 compared to $7.1 million in 2001. 
The current tax expenses are comprised of $8.1 million of Saskatchewan
Capital Tax and $1.6 million of Large Corporation Tax, compared to $6.1 million
and $1.0 million, respectively, for the prior year.  Saskatchewan Capital Tax has increased as higher commodity prices
have resulted in higher revenues earned in Saskatchewan.  The fiscal 2002 provision for future income
taxes was $38 million compared to recovery of $107.3 million for the prior
year.  The increase in future income
taxes was the result of higher corporate earnings in 2002 due to increased
commodity prices.  Future income taxes
for 2001 included a $103.2 million recovery associated with the year-end
ceiling test write-down.  Canadian
  Tax Pools
  
  December
  31, 2002($ thousands)Cumulative Canadian
  Exploration Expense
  
  123,000Cumulative Canadian Development
  Expense
  
  127,000Cumulative Canadian Oil and
  Gas Property Expense
  
  59,000Undepreciated Capital Cost
  
  150,000Total tax pools
  
  459,000  Cash Flow from Operations Cash flow from operations for the year ended December 31, 2002 increased
33 percent to $191.1 million from $144.1 million for the previous year, as a
result of higher field netbacks.  Field
netbacks increased from 2001 due to higher oil prices.  On a barrel of oil equivalent basis, cash
flow from operations was $13.35 for 2002 compared to $9.07 for 2001.  Cash Flow
  Netbacks
  
  2002
  
  2001$/boe
  
  Percent
  
  $/boe
  
  PercentProduction revenue
  
  26.14
  
  100
  
  21.37
  
  100Derivative contract loss
  
  (0.57
  )
  (2
  )
  (0.60
  )
  (3
  )Royalties
  
  (4.12
  )
  (16
  )
  (3.64
  )
  (17
  )Operating expenses
  
  (5.26
  )
  (20
  )
  (5.26
  )
  (25
  )Field netbacks
  
  16.19
  
  62
  
  11.87
  
  55General and administrative expenses
  
  (0.47
  )
  (2
  )
  (0.33
  )
  (1
  )Interest expense
  
  (1.69
  )
  (6
  )
  (2.02
  )
  (9
  )Current income taxes
  
  (0.68
  )
  (3
  )
  (0.45
  )
  (2
  )Cash flow netbacks
  
  13.35
  
  51
  
  9.07
  
  43  21 
   Capital
Expenditures Total exploration and development
expenditures for 2002 were $136.3 million, which is consistent with $135.9
million for 2001.  Overall net capital
expenditures decreased 66 percent to $126.5 million in 2002 from $375.9 million
in 2001.  Two corporate acquisitions
were completed in the prior year, which accounted for $249.1 million of the
2001expenditures.  Capital
  Expenditures
  
  2002
  
  2001($
  thousands)Land
  
  13,834
  
  11,494Seismic
  
  8,183
  
  7,242Drilling and completions
  
  81,862
  
  71,928Equipment
  
  24,507
  
  37,206Other
  
  7,949
  
  8,019Total exploration and development
  
  136,335
  
  135,889Corporate acquisitions
  
  
  
  249,152Property acquisitions
  
  45,713
  
  53,394Dispositions
  
  (55,580
  )
  (62,582
  )Net capital expenditures
  
  126,468
  
  375,853  Liquidity and Capital Resources  At December 31, 2002, total net debt
(including working capital) was $362.8 million compared to $379.1 million at
December 31, 2001.  The decrease in
total debt at the end of 2002 was the result of cash flow from operations
exceeding capital spending, proceeds from property dispositions, and proceeds
received on the settlement of the interest rate swaps. The U.S. dollar
denominated senior secured notes and senior subordinated notes decreased by a
combined $2.7 million as a result of foreign exchange gains.  The Companys debt structure consists of
three main components.  The first
component is the Companys senior credit facilities.  At year-end, the Company had undrawn bank facilities with a total
commitment of $77 million.  These
facilities are provided by a syndicate of Chartered Banks and are limited by a
total senior funded debt-borrowing base of $165 million.  Total senior funded debt is defined to
include the Companys senior secured term notes. Effective January 1, 2002, the
CICAs Emerging Issues Committee issued an abstract giving guidance on
disclosure of callable debt obligations. 
Specifically, the abstract requires the classification of borrowings
under a 364-day revolving credit facility as current liabilities.  The Companys bank loans are structured
under this type of credit facility and, as such, the comparative balance at
December 31, 2001 has been reclassified to current liabilities.  The second component is the senior secured
notes, which are due November 2004. 
These senior secured notes are governed by certain financial covenants,
measured at the end of each fiscal quarter. 
The principal covenants are:  (i)
consolidated tangible net worth not to be less than $200 million, excluding
accounting ceiling test write-down (such net worth was $529 million as at
December 31, 2002); (ii) consolidated total debt not to exceed 300 percent of
consolidated cash flow (such ratio was 145 percent as at December 31, 2002);
and (iii) consolidated cash flow not to be less than 400 percent of
consolidated interest expense (such ratio was 892 percent as at December 31,
2002).  The final component is the U.S.$150 million
senior subordinated notes.  These notes
were issued in February 2001 and have a 10-year term.  The notes bear interest at 10.5 percent payable semi-annually,
are unsecured and have no financial maintenance covenants.  Baytex believes that cash flow generated from
its operations, together with existing capacity under the bank facilities, will
be sufficient to finance current operations and planned capital expenditures
for the next year.  The timing of most
of the Companys capital expenditures is discretionary and there are no
material long-term capital expenditure commitments.  22 
   Risk and Risk
Management  The exploration for and the
development, production and marketing of petroleum and natural gas involves a
wide range of business and financial risks, some of which are beyond the
Companys control.  Included in these
risks are the uncertainty of finding new reserves, the fluctuations of
commodity prices, the volatile nature of interest and foreign exchange rates,
and the possibility of changes to royalty, tax and environmental
regulations.  The petroleum industry is
highly competitive and Baytex competes with a number of other companies, many
of which have greater financial and personnel resources.  The business risks facing
Baytex are mitigated in a number of ways. 
Geological, geophysical, engineering, environmental and financial
analyses are performed on new exploration prospects, development projects and
potential acquisitions to ensure a balance between risk and reward.  Baytexs ability to increase its production,
revenues and cash flow depends on its success in not only developing its
existing properties but also in acquiring, exploring for and developing new
reserves and production and managing those assets in an efficient manner.  Despite best practice analysis
being conducted on all projects, there are numerous uncertainties inherent in
estimating quantities of proved petroleum and natural gas reserves, including
future oil and natural gas prices, engineering data, projected future rates of
production and the timing of future expenditures.  The process of estimating petroleum and natural gas reserves
requires substantial judgment, resulting in imprecise determinations,
particularly for new discoveries.  An
independent engineering firm evaluates Baytexs properties annually to
determine a fair estimate of reserves. 
The Reserves Committee of the Board of Directors assists the Board in
their annual review of the reserve estimates.  The provision for depletion and
depreciation in the financial statements and the ceiling test are based on
proved reserve estimates.  If future
significant revisions are necessary that reduce previously estimated reserve
quantities, it could result in a full cost accounting write-down or material
changes to the annual rate of depletion and depreciation.  The financial risks that Baytex
is exposed to as part of the normal course of its business are managed with
various financial derivative instruments, in addition to fixed-price physical
delivery contracts.  The use of
derivative instruments is governed under formal policies and subject to limits
established by the Board of Directors. 
Derivative instruments are not used for speculative or trading purposes.  The Companys financial results
can be significantly affected by the prices received for petroleum and natural
gas production as commodity prices fluctuate in response to changing market
forces.  This pricing volatility is
expected to continue.  As a result,
Baytex has a risk management program that may fix the prices of oil and natural
gas on a percentage of the total expected production volume.  The objective is to lock in prices on a
portion of the Companys future production to decrease exposure to market
volatility and ensure the Companys ability to finance its capital program. The
Company recognizes gains or losses on financial derivative contracts as oil and
natural gas production revenue when the associated production occurs.  Baytexs financial results are
also impacted by fluctuations in the exchange rate between the Canadian dollar
and the US dollar.  Crude oil and, to a
large extent, natural gas prices are based on reference prices denominated in
US dollars, while the majority of expenses are denominated in Canadian
dollars.  The exchange rate also impacts
the valuation of the Company US dollar denominated term notes.  The related foreign exchange gains and
losses are included in net income.  Baytex is exposed to changes in interest
rates as the Companys banking facilities are based on our lenders prime
lending rate and short-term Bankers Acceptance rates.  In December 2001, the Company entered into
interest rate swap contracts converting the fixed rate on the US denominated
term notes to a floating rate reset quarterly based on the three-month LIBOR
rate.  During 2002, the Company
terminated all outstanding interest rate swap agreements for total proceeds of
$14.1 million.  This amount has been
deferred and is being amortized as a reduction of interest expense over the
original terms of the agreements.  There
is no plan at this time to fix the exchange rate on any of Baytexs long-term
borrowings.  23 
   The Companys current position with respect
to its financial derivative contracts is detailed in Note 12 of the
Consolidated Financial Statements, which are attached as Schedule A to this
Annual Information Form.  Critical
Accounting Policies The preparation of the consolidated financial
statements in accordance with generally accepted accounting principles requires
management to make judgements and estimates that affect the financial results
of the Company.  These critical
estimates are discussed below.  Oil And Gas
AccountingBaytex follows the full-cost accounting guideline to account for its
crude oil and natural gas properties. 
Under this method, all costs associated with the exploration for and
development of petroleum and natural gas reserves are capitalized in one Canadian
cost centre.  These capitalized costs,
along with estimated future development costs, are depleted and depreciated on
a unit of production basis using estimated proven petroleum and natural gas
reserves.  Unit of production
calculations are also used in the determination of the site restoration
expense.  By their inclusion in the unit
of production calculation, reserve estimates are a significant component of the
calculation of depletion and depreciation and site restoration expense.  Independent engineers engaged by the Company
use all available geological, reservoir, and production performance data to
prepare the reserve estimates.  These
estimates are reviewed and revised, either upward or downward, as new
information becomes available. 
Revisions are necessary due to changes in assumptions based on reservoir
performance, prices, economic conditions, government restrictions and other
relevant factors.  If reserve estimates
are revised downward, net income could be affected by increased depletion and depreciation
and site restoration expense.  Impairment of
Petroleum and Natural Gas Assets                       Companies that use the
full-cost method of accounting for oil and natural gas operations are required
to perform a ceiling test each quarter that calculates a limit for the net
carrying cost of petroleum and natural gas assets.  The ceiling test calculation utilizes and holds constant the
prices and costs in effect at the end of the period.  An estimate is made of the ultimate recoverable amount from
future net revenues using proved reserves and period end prices, plus the net
costs of major development projects and unproved properties, less future
removal and site restoration costs, overhead, financing costs and income
taxes.  The calculation of future net
revenues in the ceiling test can be significantly impacted by fluctuations in
any of these estimates.  An impairment
loss is recognized if the amount calculated under the ceiling test is less than
the carrying costs of the Companys petroleum and natural gas assets and can
result a significant loss for a particular period.  New Accounting
Pronouncements  In November 2002, the CICA amended its
accounting guideline on hedging relationships, which was originally issued in
November 2001. The guideline establishes certain conditions where hedge
accounting may be applied. It is effective for years beginning on or after July
1, 2003.  The CICA has amended the Handbook sections
dealing with cash flow statements and earnings per share to restrict the
disclosure of cash flow per share amounts in the financial statements.  Under the amended standard, effective
January 1, 2003, companies are no longer be permitted to disclose cash flow per
share amounts on either the face of the cash flow statement or in the notes to
the financial statements.  In December
2002, the CICA issued a new standard on the accounting for asset retirement
obligations.  This standard requires
recognition of a liability at discounted fair value for the future abandonment
and reclamation associated with the petroleum and natural gas properties.  The fair value of the liability is
capitalized as part of the cost of the related asset and amortized to expense
over its useful life.  The liability
accretes until the date of expected settlement of the retirement obligations.  The new standard is effective for all fiscal
years beginning on or after January 1, 2004. 
Baytex is currently assessing the impact the adoption of this new
standard will have on the consolidated financial statements.  24 
   Quarterly Information  Financial
  (unaudited)
  
  2002
  
  2001($ thousands, except per share amounts)
  
  Q4
  
  Q3
  
  Q2
  
  Q1
  
  Q4
  
  Q3
  
  Q2
  
  Q1Revenue
  
  100,590
  
  94,633
  
  91,507
  
  79,130
  
  64,327
  
  101,689
  
  84,454
  
  79,230Cash flow
  from operations
  
  53,116
  
  48,637
  
  49,208
  
  40,125
  
  24,353
  
  46,330
  
  35,770
  
  37,617Per share
  basic
  
  1.00
  
  0.93
  
  0.95
  
  0.77
  
  0.47
  
  0.89
  
  0.74
  
  0.82Per share
  diluted
  
  0.99
  
  0.91
  
  0.93
  
  0.76
  
  0.47
  
  0.87
  
  0.72
  
  0.80Net income
  (loss)
  
  12,791
  
  3,687
  
  21,354
  
  7,304
  
  (141,371
  )
  (4,626
  )
  10,583
  
  (1,693
  )Per share
  basic
  
  0.24
  
  0.07
  
  0.41
  
  0.14
  
  (2.71
  )
  (0.09
  )
  0.22
  
  (0.04
  )Per share
  diluted
  
  0.24
  
  0.07
  
  0.40
  
  0.14
  
  (2.71
  )
  (0.09
  )
  0.21
  
  (0.04
  )ProductionConventional
  oil and NGLs (bbls/d)
  
  2,909
  
  2,999
  
  2,904
  
  3,818
  
  5,808
  
  6,077
  
  4,782
  
  3,911Heavy oil
  (bbls/d)
  
  25,009
  
  23,504
  
  24,498
  
  22,838
  
  24,528
  
  29,078
  
  26,545
  
  25,970Total oil
  and NGLs (bbls/d)
  
  27,918
  
  26,503
  
  27,402
  
  26,656
  
  30,336
  
  35,155
  
  31,327
  
  29,881Natural gas
  (mmcf/d)
  
  71.8
  
  71.3
  
  73.3
  
  73.7
  
  75.9
  
  78.2
  
  71.3
  
  57.6Barrels of
  oil equivalent (boe/d @ 6:1)
  
  39,890
  
  38,391
  
  39,625
  
  38,948
  
  42,990
  
  48,187
  
  43,201
  
  39,483Average PricesWTI oil
  (US$/bbl)
  
  28.15
  
  28.27
  
  26.25
  
  21.64
  
  20.43
  
  26.49
  
  27.96
  
  28.73Edmonton par
  oil ($/bbl)
  
  42.81
  
  44.02
  
  40.40
  
  33.51
  
  31.00
  
  40.37
  
  42.19
  
  43.00BTE light
  oil ($/bbl)
  
  37.67
  
  37.36
  
  34.53
  
  27.58
  
  25.41
  
  35.37
  
  37.53
  
  38.65BTE heavy
  oil ($/bbl)
  
  26.09
  
  31.03
  
  26.64
  
  21.58
  
  10.39
  
  23.75
  
  16.77
  
  14.62BTE total
  oil ($/bbl)
  
  27.30
  
  31.75
  
  27.47
  
  22.44
  
  13.27
  
  25.76
  
  19.94
  
  17.77BTE natural
  gas ($/mcf)
  
  5.29
  
  3.33
  
  3.94
  
  3.19
  
  3.09
  
  3.35
  
  5.11
  
  6.83BTE oil
  equivalent ($/boe)
  
  28.64
  
  28.10
  
  26.29
  
  21.39
  
  14.82
  
  24.23
  
  22.88
  
  23.41Share Trading InformationBTE  TSXHigh ($)
  
  8.92
  
  8.40
  
  8.45
  
  6.89
  
  5.25
  
  11.50
  
  13.55
  
  14.84Low ($)
  
  6.65
  
  5.65
  
  6.35
  
  3.95
  
  3.00
  
  4.64
  
  9.60
  
  9.00Close ($)
  
  8.48
  
  7.59
  
  7.20
  
  6.85
  
  4.37
  
  4.80
  
  9.80
  
  12.15Average
  daily volume
  
  296,000
  
  164,000
  
  293,000
  
  270,000
  
  455,000
  
  156,000
  
  203,000
  
  191,000  CONTROLS AND
PROCEDURES  Within the 90 day period prior to the filing
of the Company's United States Form 40-F, an evaluation was performed under the
supervision and with the participation of Baytexs management, including the
Chief Executive Officer and Chief Financial Officer, of the effectiveness of
the design and operation of the Companys disclosure controls and
procedures.  Based on that evaluation,
the Chief Executive Officer and Chief Financial Officer have concluded that the
Companys disclosure controls and procedures are effective.  There have been no significant changes in
Baytexs internal controls or in other factors that could significantly affect
these controls subsequent to the date of their evaluation.  25 
   SELECTED FINANCIAL
INFORMATION Summary of
Operating Results  The following table sets forth selected
financial information of the Company for the three years ended December 31,
2002.  Year
  Ended December 31(M$, except per share amounts)
  
  2002
  
  2001
  
  2000Revenue
  
  365,860
  
  329,700
  
  286,226Cash flow from operations
  
  191,086
  
  144,070
  
  155,326Per share basic(2)
  
  3.65
  
  2.91
  
  3.68Per share diluted(3)
  
  3.59
  
  2.87
  
  3.58Net income (loss)
  
  45,136
  
  (137,107
  )
  41,682Per share basic(2)
  
  0.86
  
  (2.77
  )
  0.99Per share diluted(3)
  
  0.85
  
  (2.77
  )
  0.93Capital expenditures, net
  
  126,468
  
  375,853
  
  388,052Other Working capital
  (deficiency)
  
  (35,798
  )
  24,861
  
  (42,374
  )Long-term debt and bank loans
  
  326,977
  
  403,922
  
  213,883Total assets
  
  997,760
  
  967,046
  
  829,997  
 Note: (1)There were no extraordinary items included in net income for the
three-year period ended December 31, 2002.  (2)Net income per share was calculated using the weighted average
number of Common Shares outstanding.  (3)Assumes exercise of employee and other stock options and all other
convertible securities on their dates of issue.  INDUSTRY
CONDITIONS Regulation  The oil and natural gas industry in Canada is
subject to extensive controls and regulations imposed by various levels of
government. Baytex does not expect that any of these controls or regulations
will affect its operations in a manner materially different than they would
affect other oil and gas companies of similar size.  Crude oil and natural gas located in Alberta,
Saskatchewan and British Columbia are owned predominantly by the respective
provincial governments. Provincial governments grant rights to explore for and
produce oil and natural gas under leases, licenses and permits with terms
generally varying from two years to five years and on conditions contained in
provincial legislation.  Leases,
licenses and permits may be continued indefinitely by producing under the
lease, license or permit.  Some of the
oil and natural gas located in these provinces is privately owned and rights to
explore for and produce oil and natural gas are granted by the mineral owners
on negotiated terms and conditions.  In Canada, producers of oil negotiate sales
contracts directly with oil purchasers, with the result that the market
determines the price of oil.  The price
depends in part on oil quality, prices of competing fuels, distance to market
and the value of refined products.  Oil
exports may be made under export contracts having terms not exceeding one year
in the case of oil other than heavy oil, and not exceeding two years in the
case of heavy oil, so long as an order approving any such export has been
obtained from the National Energy Board. 
Any oil export to be made pursuant to a contract of longer duration
requires an exporter to obtain an export license from the National Energy Board
and the issue of a license requires the approval of the Canadian federal
government.  The term of the license may
not exceed 25 years.  In Canada, the price of natural gas sold in
interprovincial and international trade is determined by negotiation between
buyers and sellers.  Natural gas
exported from Canada is subject to regulation by the  26 
   Government
of Canada through the National Energy Board. 
Producers and exporters are free to negotiate prices and other terms
with purchasers, provided that the export contracts must continue to meet
criteria prescribed by the National Energy Board.  Natural gas exports for a term of two years or less, or for 2 to
20 years in quantities not more than 1.1 million cubic feet per day may be
made under a National Energy Board order, or, in the case of exports for a
longer duration or larger volumes, under a National Energy Board license and
Canadian federal government approval.  The provincial governments of Alberta,
British Columbia and Saskatchewan also regulate the removal of natural gas from
those provinces for consumption elsewhere. 
They do so based on such factors as reserve availability, transportation
arrangements and market considerations.  In addition to federal regulations, each
province has legislation and regulations, which govern land tenure, royalties,
production rates, environmental protection and other matters.  The royalty regime is a significant factor
in the profitability of oil and natural gas production.  Royalties payable on production from lands other
than government lands are determined by negotiations between the mineral owner
and the lessee.  Royalties on government
land are determined by government regulation and are generally calculated as a
percentage of the value of gross production, and the rate of royalties payable
generally depends upon prescribed reference prices, well productivity,
geographical location, field discovery date and the type or quality of the
petroleum product produced.  From time to time the governments of Canada,
Alberta, British Columbia and Saskatchewan have established incentive programs
that have included royalty rate deduction and tax credits for the purpose of
encouraging oil and natural gas exploration or enhanced recovery projects.  In Alberta, a producer of oil or natural gas
is entitled to a credit against the royalties payable to the government by
virtue of the ARTC program.  The ARTC
program is based on a price sensitive formula, and ranges between 75%, for
prices for oil at or below $100 per cubic meter ($15.90 per barrel), to 25%,
for prices above $210 per cubic meter ($33.39 per barrel). In general, the
ARTC rate is applied to a maximum of $2,000,000 of government royalties payable
for each producer or associated group of producers. Government royalties on
production from producing properties acquired from companies claiming maximum
entitlement to ARTC will generally not be eligible for ARTC. The rate is
established quarterly based on the average par price, as determined by the
Alberta Department of Energy for the previous quarterly period.  Crude oil and natural gas royalty and
reductions for specific wells reduce the amount of royalties Baytex pays to the
government.  The North American Free Trade Agreement among
the governments of Canada, the United States and Mexico became effective on
January 1, 1994.  NAFTA carries forward
most of the material energy terms that are contained in the Canada-US Free
Trade Agreement.  Subject to the General
Agreement on Tariffs and Trade, Canada continues to remain free to determine
whether exports of energy resources to the United States or Mexico will be
allowed, so long as any export restrictions do not:  reduce the proportion of energy resources exported relative to total
supply (based upon the proportion prevailing in the most recent 36 month period
or another representative period agreed upon by the parties);  impose an export price higher than the domestic price (subject to an
exception that applies to some measures that only restrict the value of
exports); or  disrupt normal channels of supply.  All three
countries are prohibited from imposing minimum or maximum export or import
price requirements, with some limited exceptions.  27 
   Environmental  The oil and natural gas industry is governed
by environmental regulation under Canadian federal and provincial laws, rules
and regulations, which restrict and prohibit the release or emission and
regulate the storage and transportation of various substances produced or
utilized in association with oil and gas industry operations.  In addition, applicable environmental laws
require that well and facility sites be abandoned and reclaimed, to the
satisfaction of provincial authorities, in order to prevent pollution from
former operations.  Also, environmental
laws may impose upon responsible persons remediation obligations on property
designated as a contaminated site. 
Responsible persons include persons responsible for the substance
causing the contamination, persons who caused the release of the substance and
any present or past owner, tenant or other person in possession of the
site.  A breach of environmental laws
may result in the imposition of fines and penalties, in addition to the costs
of abandonment and reclamation.  All applicable environmental laws are
consolidated in the Environmental Protection
and Enhancement Act.  Under
this Act, environmental standards and requirements that apply to compliance,
cleanup and reporting are stricter. 
Also, the range of enforcement actions available and the severity of
penalties have been significantly increased. 
These changes will have an incremental increase in the cost of
conducting oil and natural gas operations in Alberta.  Baytex has established guidelines and
management systems to ensure compliance with environmental laws, rules and
regulations.  Baytex has designated a
compliance officer whose responsibility is to monitor regulatory
requirements and their impact on Baytex and to implement appropriate compliance
procedures.  Baytex also employs an
environmental manager whose responsibilities include causing Baytexs
operations to be carried out in accordance with applicable environmental
guidelines and implementing adequate safety precautions.  The existence of these positions cannot,
however, guarantee total compliance with environmental laws, rules and regulations.  RISK FACTORS  An investment in Baytex may be considered
speculative due to the nature of the Companys involvement in the exploration
for, and the acquisition, development, production and marketing of, oil and
natural gas and its current stage of development.  Oil and gas operations involve many risks that even a combination
of experience and knowledge and careful evaluation may not be able to
overcome.  There is no assurance that
further commercial quantities of oil and natural gas will be discovered or
acquired by the Company.  The oil and natural gas industry is intensely
competitive.  Competition is
particularly intense in the acquisition of prospective oil and natural gas
properties and oil and gas reserves. 
Baytexs competitive position depends on its geological, geophysical and
engineering expertise, its financial resources, its ability to develop its
properties and its ability to select, acquire and develop proved reserves.
Baytex competes with a substantial number of other companies having larger
technical staffs and greater financial and operational resources.  Many such companies not only engage in the
acquisition, exploration, development and production of oil and natural gas
reserves, but also carry on refining operations and market-refined
products.  Baytex also competes with
major and independent oil and natural gas companies and other industries
supplying energy and fuel in the marketing and sale of oil and natural gas to
transporters, distributors and end users, including industrial, commercial and
individual consumers.  Baytex also
competes with other oil and natural gas companies in attempting to secure
drilling rigs and other equipment necessary for drilling and completion of
wells.  Such equipment may be in short
supply from time to time.  Finally,
companies not previously investing in oil and natural gas may choose to acquire
reserves to establish a firm supply or simply as an investment.  Such companies will also provide competition
for Baytex.  The marketability of oil and natural gas
acquired or discovered is affected by numerous factors beyond the control of
Baytex.  These factors include reservoir
characteristics, market fluctuations, the proximity and capacity of oil and
natural gas pipelines and processing equipment and government regulation.  Oil and natural gas operations (exploration,
production, pricing, marketing and transportation) are subject to extensive
controls and regulations imposed by various levels of government which may be
amended from time to time.  See Industry
Conditions.  Baytexs oil and natural
gas operations may also be subject to compliance with federal, provincial and
local laws and regulations controlling the discharge of materials into the
environment or otherwise relating to the  28 
   protection of the environment.  Although the Company believes that it is in
material compliance with current applicable environmental regulations, changes
to such regulations may have a material adverse effect on the Company. See
Industry Conditions - Environmental Regulation.  In December 2002, the Government of Canada
ratified the Kyoto Protocol.  This
protocol calls for Canada to reduce its greenhouse gas emissions to 6 percent
below 1990 levels during the period between 2008 and 2012.  The Protocol will only become legally
binding when it is ratified by at least 55 countries, covering at least 55
percent of the emissions addressed by the Protocol.  If the Protocol is ratified and becomes legally binding, it is
expected to affect the operation of all industries in Canada, including the oil
and gas industry.  As details of the
implementation of this Protocol have yet to be announced, the effect on Baytex
cannot be determined at this time.  Both oil and natural gas prices are unstable
and are subject to fluctuation.  Any
material decline in prices could result in a reduction of Baytexs net
production revenue and overall value and could result in ceiling test
writedowns.  The economics of producing
from some wells may change as a result of lower prices, which could result in a
reduction in the volumes of Baytexs reserves. 
Baytex might also elect not to produce from certain wells at lower
prices.  All of these factors could
result in a material decrease in Baytexs net production revenue causing a
reduction in its oil and gas acquisition and development activities.  In addition, bank borrowings available to
the Company are in part determined by the borrowing base of the Company.  A substantial material decline in prices
from historical average prices could further reduce the Companys borrowing
base, therefore reducing the bank credit available to the Company and possibly
require that a portion of the Companys bank debt be repaid.  The Company uses the full cost method of
accounting for oil and natural gas properties. 
Under this accounting method, capitalized costs are reviewed for
impairment to ensure that the carrying amount of these costs is recoverable
based on expected future cash flows.  To
the extent that such capitalized costs (net of accumulated depreciation and
depletion) less future taxes exceed the present value of estimated future net
cash flows from the Companys proved oil and natural gas reserves, those excess
costs would be required to be charged to operations.  From time to time the Company may enter into
agreements to receive fixed prices on its oil and natural gas production to
offset the risk of revenue losses if commodity prices decline; however, if
commodity prices increase beyond the levels set in such agreements, the Company
will not benefit from such increases.  From time to time the Company may enter into
agreements to fix the exchange rate of Canadian to United States dollars in
order to offset the risk of revenue losses if the Canadian dollar increases in
value compared to the United States dollar; however, if the Canadian dollar
declines in value compared to the United States dollar, the Company will not
benefit from the fluctuating exchange rate.  Oil and natural gas exploration operations
are subject to all the risks and hazards typically associated with such
operations, including hazards such as fire, explosion, blowouts, cratering and
oil spills, each of which could result in substantial damage to oil and natural
gas wells, production facilities, other property and the environment or in
personal injury.  In accordance with
industry practice, the Company is not fully insured against all of these risks,
nor are all such risks insurable. 
Although Baytex maintains liability insurance in an amount, which it
considers adequate and consistent with industry practice, the nature of these
risks is such that liabilities could exceed policy limits, in which event
Baytex could incur significant costs that could have a materially adverse
effect upon its financial condition. 
Oil and natural gas production operations are also subject to all the
risks typically associated with such operations, including premature decline of
reservoirs and the invasion of water into producing formations.  Oil and natural gas exploration and
development activities are dependent on the availability of drilling and
related equipment in the particular areas where such activities will be
conducted.  Demand for such limited
equipment or access restrictions may affect the availability of such equipment
to the Company and may delay exploration and development activities.  To the extent Baytex is not the operator of
its oil and gas properties, Baytex will be dependent on such operators for the
timing of activities related to such properties and will be largely unable to
direct or control the activities of the operators.  Although title reviews will be done according
to industry standards prior to the purchase of most oil and natural gas
producing properties or the commencement of drilling wells, such reviews do not
guarantee or certify that an unforeseen defect in the chain of title will not
arise to defeat the claim of Baytex which could result in a reduction of the
revenue received by Baytex.  There are numerous uncertainties inherent in
estimating quantities of reserve and cash flows to be derived therefrom,
including many factors that are beyond the control of the Company.  The reserve and cash flow information set
forth in this Annual Information Form represent estimates only.  The reserves and estimated future net cash
flow from the Companys properties have been independently evaluated effective
December 31, 2002 by Outtrim. 
These evaluations include a number of assumptions relating to factors
such as initial production rates,  29 
   production decline rates, ultimate recovery
of reserves, timing and amount of capital expenditures, marketability of
production, future prices of oil and natural gas, operating costs and royalties
and other government levies that may be imposed over the producing life of the
reserves.  These assumptions were based
on price forecasts in use at the date the relevant evaluations were prepared
and many of these assumptions are subject to change and are beyond the control
of the Company.  Actual production and
cash flows derived therefrom will vary from these evaluations, and such
variations could be material.  The
foregoing evaluations are based in part on the assumed success of exploitation
activities intended to be undertaken in future years.  The reserves and estimated cash flows to be derived therefrom
contained in such evaluations will be reduced to the extent that such
exploitation activities do not achieve the level of success assumed in the
evaluations.  From time to time the Company may enter into
transactions to acquire assets or the shares of other companies.  These transactions may be financed partially
or wholly with debt, which may increase the Companys debt levels above
industry standards.  Depending on future
exploration and development plans, the Company may require additional financing
that may not be available or, if available, may not be available on favourable
terms.  Certain directors of Baytex are also
directors of other oil and gas companies and as such may, in certain
circumstances, have a conflict of interest requiring them to abstain from
certain decisions.  Conflicts, if any,
will be subject to the procedures and remedies of the ABCA.  Baytexs success depends in large measure on
certain key personnel including Messrs. Dale O. Shwed and Raymond T. Chan.  The loss of the services of such key
personnel could have a material adverse effect on Baytex.  Baytex does not have key person insurance in
effect for management.  The
contributions of these individuals to the immediate operations of the Company
are likely to be of central importance. 
In addition, competition for qualified personnel in the oil and natural
gas industry is intense and there can be no assurance that Baytex will be able
to continue to attract and retain all personnel necessary for the development
and operation of its business. 
Investors must rely upon the ability, expertise, judgment, discretion,
integrity and good faith of the management of the Company.  ADDITIONAL
INFORMATION  Additional information, including information
as to directors and officers remuneration and indebtedness, principal holders
of the Companys securities, options to purchase securities and interests of
insiders in material transactions, is contained in the Management Proxy
Circular of the Company dated April 12, 2002 provided for the annual meeting of
the shareholders of the Company held on May 28, 2002.  Additional financial information is also provided in the Companys
audited consolidated financial statements for the year ended December 31, 2002,
together with the report of the auditors thereon, which are attached as
Schedule A.  Upon request the Company will provide to any
person:  1.One copy of this Annual Information Form together with one copy of any
document, or the pertinent pages of any document incorporated by reference in
the Annual Information Form;  2.One copy of any of the Companys interim financial statements
subsequent to the Companys consolidated financial statements year for the ended
December 31, 2002 which are attached as Schedule A;  3.One copy of the Companys Management Proxy Circular provided for the
annual meeting of the shareholders of the Company held on May 28, 2002; and  4.When the Companys securities are in the course of a distribution
pursuant to a short form prospectus or when a preliminary short form prospectus
has been filed in respect of a distribution of the Companys securities, also
upon request to the Company, one copy of any other document that is incorporated
by reference in the preliminary or final short form prospectus, as the case may
be.  30 
   Copies
of these documents may be obtained in some cases upon payment of a reasonable
charge upon request to:  Baytex Energy Ltd. Suite 2200, 205 - 5th Avenue SW Calgary, Alberta T2P 2V7 Phone:    (403)
269-4282 Fax:         (403)
205-3845  31 
   Schedule A  Managements Report  Management, in accordance with
Canadian generally accepted accounting principles, has prepared the
accompanying consolidated financial statements of Baytex Energy Ltd.  Financial and operating information
presented throughout this Annual Report is consistent with that shown in the
consolidated financial statements.  Management is responsible for the
integrity of the financial information. 
Internal control systems are designed and maintained to provide
reasonable assurance that assets are safeguarded from loss or unauthorized use
and to produce reliable accounting records for financial reporting purposes.  Deloitte & Touche LLP, were
appointed by the Companys shareholders to perform an examination of the
corporate and accounting records so as to express an opinion on the
consolidated financial statements. 
Their examination included a review and evaluation of Baytexs internal
control systems and included such test and procedures, as they considered
necessary, to provide a reasonable assurance that the consolidated financial
statements are presented fairly in accordance with Canadian generally accepted
accounting principles.  The Board of Directors is
responsible for ensuring that management fulfills its responsibilities for
financial reporting and internal control. 
The Board exercises this responsibility through the Audit Committee,
with assistance from the Reserves Committee regarding the annual review of our
petroleum and natural gas reserves.  
The Audit Committee meets regularly with management and the independent
auditors to ensure that managements responsibilities are properly discharged,
to review the consolidated financial statements and recommend that the
consolidated financial statements be presented to the Board of Directors for
approval.  The Audit Committee also considers
the independence of the external auditors and reviews their fees.  The external auditors have access to the
Audit Committee without the presence of management.   (signed)
  /s/ Dale O. Shwed
  
  (signed)
  /s/ Raymond T. Chan, CAPresident
  and
  
  Senior
  Vice President andChief Executive Officer
  
  Chief Financial OfficerMarch 3, 2003  32 
   Deloitte
& Touche LLP 3000, 700
Second Street SW Calgary,
AB  Canada  T2P 0S7  Telephone+1 403-267-1700 Facsimile+1 403-264-2871  Independent Auditors Report To the Shareholders of Baytex Energy Ltd.   We have audited the
consolidated balance sheets of Baytex Energy Ltd. as at December 31, 2002 and
2001 and the consolidated statements of operations and deficit and of cash
flows for the years then ended.  These
consolidated financial statements are the responsibility of the Companys
management.  Our responsibility is to
express an opinion on these consolidated financial statements based on our
audits.  We conducted our audits in
accordance with Canadian generally accepted auditing standards.  Those standards require that we plan and
perform an audit to obtain reasonable assurance whether the consolidated
financial statements are free of material misstatement.  An audit includes examining, on a test basis,
evidence supporting the accounting principles used and significant estimates
made by management, as well as evaluating the overall consolidated financial
statement presentation.  In our opinion, these
consolidated financial statements present fairly, in all material respects, the
financial position of the Company as at December 31, 2002 and 2001 and the
results of its operations and its cash flows for the years then ended in
accordance with Canadian generally accepted accounting principles.  On March 3, 2003, we
reported separately to the board of directors and shareholders of Baytex Energy
Ltd. on the consolidated financial statements for the same period, prepared in
accordance with Canadian generally accepted accounting principles but which
included Note 17, United States Accounting Principles and Reporting and Note
18, Condensed Consolidating Financial Information.   (signed)
  /s/ Deloitte & Touche LLPCalgary, Alberta
  
  
  
  
  Chartered AccountantsMarch 3, 2003  33 
   Baytex Energy Ltd. Consolidated
Balance Sheets As at December
31, 2002 and 2001 (thousands)  2002
  
  2001(restated
   see notes 2 & 4)AssetsCurrent
  assetsCash
  
  $
  4,098
  
  $
  Accounts receivable
  
  52,667
  
  44,300Properties held for sale
  
  
  
  46,89556,765
  
  91,195Deferred charges and other
  assets
  
  8,679
  
  8,674Petroleum and natural gas
  properties (note 3)
  
  932,316
  
  867,177$
  997,760
  
  $
  967,046LiabilitiesCurrent
  liabilitiesAccounts payable and accrued
  liabilities
  
  $
  92,563
  
  $
  64,334Bank loan (note 4)
  
  
  
  73,820Current portion of long-term
  debt (note 5)
  
  
  
  2,00092,563
  
  140,154Long-term debt (note 5)
  
  326,977
  
  330,102Deferred credits (note 6)
  
  12,181
  
  18,694Provision for future site
  restoration costs
  
  21,950
  
  20,541Future income taxes (note 9)
  
  184,402
  
  146,446638,073
  
  655,937Shareholders EquityShare capital (note 7)
  
  398,176
  
  394,734Deficit
  
  (38,489
  )
  (83,625
  )359,687
  
  311,109$
  997,760
  
  $
  967,046  On behalf of the Board(signed)
  
  
  (signed)/s/John A. Brussa
  
  
  
  /s/W.
  A. Blake CassidyDirector
  
  
  Director  See accompanying notes to the consolidated financial statements.  34 
   Baytex Energy
Ltd. Consolidated Statements of Operations and
Deficit Years Ended
December 31, 2002 and 2001 (thousands, except per share
data)  2002
  
  2001(restated
   see note 2)RevenuePetroleum
  and natural gas sales
  
  $
  365,860
  
  $
  329,700Royalties
  
  (58,922
  )
  (57,805
  )306,938
  
  271,895ExpensesOperating
  
  75,228
  
  83,439General
  and administrative
  
  6,743
  
  5,262Interest
  (note 5)
  
  25,217
  
  32,942Foreign
  exchange (gain) loss (note 2)
  
  (2,691
  )
  16,262Depletion
  and depreciation (note 3)
  
  106,834
  
  367,384Site
  restoration costs
  
  2,799
  
  3,912214,130
  
  509,201Income (loss) before income taxes
  
  92,808
  
  (237,306
  )Income taxes (recovery) (note 9)Current
  
  9,716
  
  7,128Future
  
  37,956
  
  (107,327
  )47,672
  
  (100,199
  )Net income (loss)
  
  45,136
  
  (137,107
  )Retained earnings (deficit), beginning of
  year, as previously reported
  
  (75,954
  )
  52,555Accounting policy change(note 2)
  
  (7,671
  )
  927Retained earnings (deficit), beginning of
  year, as restated
  
  (83,625
  )
  53,482Deficit, end of year
  
  $
  (38,489
  )
  $
  (83,625
  )Net income (loss) per common share(note 8)Basic
  
  $
  0.86
  
  $
  (2.77
  )Diluted
  
  $
  0.85
  
  $
  (2.77
  )  See accompanying notes to the
consolidated financial statements.  35 
   Baytex Energy
Ltd. Consolidated
Statements of Cash Flows Years Ended
December 31, 2002 and 2001 (thousands, except per share
data)  2002
  
  2001(restated
   see note 2)Cash
  provided by (used in):Operating activitiesNet income (loss)
  
  $
  45,136
  
  $
  (137,107
  )Items not affecting cash:Site restoration costs
  
  2,799
  
  3,912Amortization of deferred
  charges
  
  1,052
  
  946Foreign exchange (gain) loss
  
  (2,691
  )
  16,262Depletion and depreciation
  
  106,834
  
  367,384Future income taxes (recovery)
  
  37,956
  
  (107,327
  )Cash flow from operations
  
  191,086
  
  144,070Change in non-cash working
  capital (note 10)
  
  1,272
  
  5,682Increase in deferred charges
  
  (1,057
  )
  Increase (decrease) in
  deferred credits (note 6)
  
  (18,694
  )
  18,694172,607
  
  168,446Financing activitiesIssue of senior subordinated
  term notes
  
  
  
  227,895Decrease in bank loan and
  other debt
  
  (76,254
  )
  (88,474
  )Increase in deferred charges
  
  
  
  (9,037
  )Increase in deferred credits
  (note 6)
  
  12,181
  
  Repurchase of common shares
  (note 7)
  
  (55
  )
  (860
  )Issue of common shares
  
  3,497
  
  1,444(60,631
  )
  130,968Investing activitiesCorporate acquisitions (note
  14)
  
  
  
  (249,152
  )Items not affecting cashShares issued on acquisition
  
  
  
  68,104Assumption of long-term debt
  
  
  
  36,356Assumption of working capital
  
  
  
  (2,734
  )
  
  (147,426
  )Petroleum and natural gas
  property expenditures
  
  (182,048
  )
  (189,283
  )Disposal of petroleum and
  natural gas properties
  
  55,580
  
  62,582Properties held for sale
  
  (46,895
  )
  46,895Change in non-cash working
  capital (note 10)
  
  65,485
  
  (72,182
  )(107,878
  )
  (299,414
  )Change in cash during the year
  
  4,098
  
  Cash,
  beginning of year
  
  
  
  Cash,
  end of year
  
  $
  4,098
  
  $
  Cash flow from operations per common share (note 8)Basic
  
  $
  3.65
  
  $
  2.91Diluted
  
  $
  3.59
  
  $
  2.87  See accompanying notes to the
consolidated financial statements.  36 
   Baytex Energy Ltd. Notes to the
Consolidated Financial Statements Years Ended December
31, 2002 (all tabular amounts
in thousands, except per share amounts)  1. Significant
Accounting Policies  These consolidated financial statements have
been prepared in accordance with Canadian generally accepted accounting
principles within the framework of the accounting policies summarized below:  Consolidation  The
consolidated financial statements include the accounts of the Company and its
wholly owned subsidiaries and partnership from the respective dates of
acquisition of the subsidiary companies. 
Inter-company transactions and balances are eliminated upon
consolidation.  Measurement
Uncertainty  Amounts
recorded for depreciation and depletion and amounts used for ceiling test
calculations are based on estimates of petroleum and natural gas reserves and
future costs required to develop those reserves.  The Companys reserve estimates are reviewed annually by an
independent engineering firm.  By their
nature, these estimates of reserves and the related future cash flows are
subject to measurement uncertainty, and the impact on the financial statements
of future periods could be material.  Cash and Cash
Equivalents  Cash and cash
equivalents include monies on deposit and short-term investments accounted for
at cost that have a maturity date of not more that 90 days.  Petroleum and natural gas operations  The Company follows the full cost method of
accounting for its petroleum and natural gas operations whereby all costs
relating to the exploration for and development of petroleum and natural gas
reserves are capitalized in one Canadian cost centre and charged against
income, as set out below.  Such costs
include land acquisition, drilling of productive and non-productive wells,
geological and geophysical, production facilities, carrying costs directly
related to unproved properties and corporate expenses directly related to
acquisition, exploration and development activities and do not include any
costs related to production or general overhead expenses.  These costs along with estimated future
costs that are based on current costs and that are incurred in developing
proved reserves, are depleted and depreciated on a unit of production basis
using estimated gross proved petroleum and natural gas reserves.  For purposes of this calculation, petroleum
and natural gas reserves are converted to a common unit of measurement on the
basis of their relative energy content where six thousand cubic feet of gas
equates to one barrel of oil.  Costs of
acquiring and evaluating unproved properties are excluded from costs subject to
depletion and depreciation until it is determined whether proved reserves are
attributable to the properties or impairment occurs.  Unproved properties are evaluated for impairment on an annual
basis.  Gains or
losses on sales of properties are recognized only when crediting the proceeds
to costs would result in a change of 20 percent or more in the depletion rate.  The net amount at which petroleum and natural
gas properties are carried is subject to a cost recovery test (the ceiling
test).  Under this test, an estimate is
made of the ultimate recoverable amount from future net revenues using proved
reserves and period end prices, plus the net costs of major development
projects and unproved properties, less future removal and site restoration
costs, overhead, financing costs and income taxes.  If the net carrying costs exceed the ultimate recoverable amount,
additional depletion and depreciation is provided.  37 
   Provision for future site restoration costs  Estimates are made of the future site
restoration costs relating to the Companys petroleum and natural gas
properties at the end of their economic life, based on year end values, in
accordance with current legislative requirements and industry practice.  Annual charges are provided for on a unit of
production method.  Actual expenditures
incurred are applied against the provision for future site restoration costs.  Joint interests  A portion of
the Companys exploration, development and production activities is conducted
jointly with others.  These consolidated
financial statements reflect only the Companys proportionate interest in such
activities.  Foreign currency translation  Foreign currency denominated monetary items
are translated into Canadian dollars at the exchange rate in effect at the
balance sheet date.  Effective January
1, 2002, the Company retroactively adopted the Canadian Institute of Chartered
Accountants (CICA) amended accounting standard with respect to accounting for
foreign currency translation.  As a
result of the amendments, all exchange gains and losses on long-term monetary
items that do not qualify for hedge accounting are recognized in income.  Revenue and expenses are translated at the
monthly average rate of exchange. 
Translation gains and losses are included in net income.  Deferred charges  Financing costs related to the issuance of
the senior secured term notes and the senior subordinated term notes have been
deferred and are amortized over the term of the respective notes on a
straight-line basis.  Financial
instruments  The Company formally documents its risk
management objectives and strategies, including the permitted use of derivative
financial instruments.  The Company
utilizes derivative financial instruments to manage exposures to fluctuations
in commodity prices, interest rates and foreign currency exchange rates.  All transactions of this nature entered into
by the Company are related to an underlying financial position or to future
petroleum and natural gas production. 
The Company does not use derivative financial instruments for trading
purposes.  Costs and gains on derivative
contracts are recognized in income in the same period that the transactions are
settled.  The fair values of derivative
instruments are not recorded in the balance sheet.  Gains and losses related to derivative
financial instruments that have been closed prior to the settlement dates are
deferred and recognized in the statement of operations over the original
settlement period.  Future
Income taxes  Income taxes are accounted for under the
liability method of tax allocation, which determines future income taxes based
on the differences between assets and liabilities reported for financial
accounting purposes and those reported for tax purposes.  Future income taxes are calculated using tax
rates anticipated to apply in periods that temporary differences are expected
to reverse.  38 
   Flow-through shares  The Company
has financed a portion of its exploration and development activities through
the issue of flow-through shares.  Under
the terms of the flow-through share agreements, the tax attributes of the
related expenditure are renounced to the subscribers.  Accordingly, the carrying value of the expenditures incurred and
the shares issued are recorded net of tax benefits renounced to the
subscribers. The Company records the gross carrying value of the expenditures
and records a future tax liability for the tax benefits renounced to
subscribers.  Stock-Based
Compensation  The Companys stock-based compensation plans are described in note
7.  The Company accounts for employee
stock options based on intrinsic values. 
No compensation expense is recognized when stock options are
issued.  The consideration paid on the
exercise of stock options is credited to share capital.  Benefits paid under the stock appreciation
rights plan are charged to net income.  Per Share Amounts  Basic net
income per share and basic cash flow from operations per share are computed by
dividing net income and cash flow from operations by the weighted average
number of common shares outstanding during the year.  Diluted per share amounts reflect the potential dilution that
could occur if options or warrants to purchase common shares were
exercised.  The treasury stock method is
used to determine the dilutive effect of stock options and warrants, whereby
any proceeds from the exercise of stock options or other dilutive instruments
are assumed to be used to purchase common shares at the average market price
during the period.  2.             Changes in Accounting Policy  Foreign Currency  Effective
January 1, 2002, the Company retroactively adopted the CICA amended accounting
standard with respect to accounting for foreign currency translation.  As a result of the amendments, all exchange
gains and losses on long-term monetary items that do not qualify for hedge
accounting are recognized in income. 
Previously, these exchange gains and losses were deferred and amortized
over the remaining life of the monetary item. 
The impact of the amended standard on the year ended December 31, 2002
was to increase net income by $1.8 million (2001 - decrease of $8.6
million).  The effect of this change on
the December 31, 2001 Consolidated Balance Sheet is an elimination of the
unrealized foreign exchange loss of $13.7 million, a decrease in future income
taxes of $6.0 million, and an increase in the deficit of $7.7 million.  Stock-based
Compensation  Effective
January 1, 2002, the Company adopted the new recommendations of the CICA with
respect to stock-based compensation.  In
accordance with the new standard, the Company has elected to continue its
policy of accounting for employee stock options based on intrinsic values and
will disclose the pro forma results of using the fair value based method.  The new recommendations apply to options
granted after December 31, 2001.  39 
   3.             Petroleum and Natural Gas Properties  As
  at December 31,2002
  
  2001Petroleum and natural gas properties
  
  $
  1,989,246
  
  $
  1,817,273Accumulated depletion and depreciation
  
  (1,056,930
  )
  (950,096
  )$
  932,316
  
  $
  867,177  During 2002,
$6.7 million (2001 - $5.3 million) of corporate expenses relating to
exploration and development activities were capitalized.  In calculating the depletion and
depreciation provision for 2002, $80.3 million (2001 - $85.3 million) of costs
relating to undeveloped properties and materials and supplies of $5.5 million
(2001- $7.1 million) were excluded from costs subject to depletion and
depreciation.  As a result of
the ceiling test performed at December 31, 2001, the Company recorded
additional depletion and depreciation on its petroleum and natural gas
properties of $234.5 million ($131.3 million net of income tax).  At December
31, 2002, the estimated future site restoration costs to be accrued over the
life of the remaining proved reserves are $26.2 million (2001 - $30.0 million).  4.             Bank Loan  As
  at December 31,2002
  
  2001Bank loan
  
  $
  
  
  $
  73,820  The bank loan
facilities consist of an operating loan and a 364-day revolving loan, which are
provided by a syndicate of chartered banks. 
The facilities can be drawn in either Canadian or U.S. funds and bear
interest at the agent banks prime lending rate, bankers acceptance rates plus
applicable margins or LIBOR rates plus applicable margins.  The facilities are subject to periodic
review and are secured by a charge over all of the Companys assets.  The security is shared pari passu with the
senior secured term notes.  At December
31, 2002, the facilities are limited to total commitment under the facilities
of $77 million and a $165 million borrowing base of total senior funded debt,
which is defined to include the senior secured term notes.  Effective January 1, 2002, the Company has
classified borrowing under its bank facilities as a current liability as required
by new CICA guidance.  The bank loan at
December 31, 2001 has been restated to conform to the current presentation.  5.             Long-Term Debt  As
  at December 31,2002
  
  2001Senior secured term notes (US$57 million)
  
  $
  90,037
  
  $
  90,778Senior subordinated term notes (US$150
  million)
  
  236,940
  
  238,890Other long-term debt
  
  
  
  2,434326,977
  
  332,102Less: current portion
  
  
  
  2,000$
  326,977
  
  $
  330,102  40 
   Senior secured term notes  On November
13, 1998, the Company issued US$57 million of senior secured term notes,
bearing interest at 7.23 percent payable quarterly with principal repayable on
November 13, 2004.  These notes are
governed by financial and other corporate covenants and are secured by a charge
over all of the Companys assets, which security is shared pari passu with the
bank loan facilities.  During 2002, the
Company terminated an outstanding interest rate swap agreement associated with
these notes.  The gain from the
settlement of this contract has been deferred and is being amortized as a
reduction of interest expense over the original term of the agreement (note 6).  Senior subordinated term notes  On February
12, 2001, the Company issued US$150 million of senior subordinated term notes
bearing interest at 10.5 percent payable semi-annually with principal repayable
on February 15, 2011.  These notes are
unsecured and are subordinate to the Companys bank facilities and senior
secured term notes.  During 2002, the Company
terminated outstanding interest rate swap agreements associated with these
notes.  The gain from the settlement of
these contracts has been deferred and is being amortized as a reduction of
interest expense over the original term of the agreements (note 6).  Interest Expense  The Company
has incurred interest expense on its outstanding debt as follows:  2002
  
  2001Bank loan
  
  $
  760
  
  $
  4,620Amortization of deferred charges
  
  1,052
  
  946Long-term debt
  
  23,405
  
  27,376Total interest
  
  $
  25,217
  
  $
  32,942  6.             Deferred Credits  As
  at December 31,2002
  
  2001Deferred interest swap settlement (note 5)
  
  $
  12,181
  
  $
  Deferred commodity contract gain
  
  
  
  18,694$
  12,181
  
  $
  18,694  In August 2002, the Company terminated all outstanding interest rate
swap agreements for total proceeds of $14.1 million.  This amount has been deferred and is being amortized as a
reduction of interest expense over the original terms of the agreements.  During 2001, the Company renegotiated certain derivative contracts
related to 2002 commodity prices and received a net payment of $18.7
million.  This amount was recognized in
income during 2002.  41 
   7.             Share Capital  Authorized  The Company has an unlimited number of common
shares in its authorized share capital.  Issued  2002
  
  2001#
  Shares
  
  Amount
  
  #
  Shares
  
  AmountBalance, beginning of year
  
  52,008
  
  $
  394,734
  
  45,797
  
  $
  326,767Shares issued for corporate acquisitions
  (note 14)
  
  
  
  
  
  6,119
  
  68,104Stock options exercised
  
  820
  
  3,497
  
  314
  
  1,444Normal course issuer bid
  
  (9
  )
  (55
  )
  (222
  )
  (860
  )Future tax related to flow-through shares
  
  
  
  
  
  
  
  (721
  )Balance, end of year
  
  52,819
  
  $
  398,176
  
  52,008
  
  $
  394,734  Stock options
and stock appreciation rights  The Company
grants stock options to its employees and directors at the market price of the
common shares at the time of the grant. 
The options vest over three years and have a term of four years.  At December 31, 2002, 3.7 million common
shares (2001 - 4.6 million common shares) of the Company are reserved under the
stock option plan for issuance.  Of the
5.1 million options outstanding as of December 31, 2002, 1.4 million options
are subject to shareholder ratification.  #
  Options
  
  Price
  Range
  
  Weighted
  Average
  Exercise PriceOutstanding December 31, 2000
  
  4,042
  
  $ 3.30 to $ 15.50
  
  $
  8.26Granted
  
  2,478
  
  $ 3.51 to $ 13.30
  
  $
  6.17Exercised
  
  (314
  )
  $ 3.30 to $ 12.25
  
  $
  4.84Cancelled
  
  (1,738
  )
  $ 3.80 to $ 15.50
  
  $
  11.25Outstanding December 31, 2001
  
  4,468
  
  $ 3.30 to $ 10.75
  
  $
  6.19Granted
  
  1,682
  
  $ 4.40 to $   7.97
  
  $
  7.61Exercised
  
  (820
  )
  $ 3.30 to $   6.10
  
  $
  4.27Cancelled
  
  (204
  )
  $ 4.72 to $   7.67
  
  $
  5.78Outstanding December 31, 2002
  
  5,126
  
  $ 3.51 to $ 10.75
  
  $
  6.98  The following
table summarizes information about the stock options outstanding at December
31, 2002:  Number
  Outstanding at
  December 31, 2002
  
  Weighted
  Average
  Remaining
  Term
  
  Weighted
  Average
  Exercise
  Price
  
  Number
  Exercisable
  at December 31,
  2002
  
  Weighted
  Average
  Exercise
  Price(years)$ 3.51 to $   5.00
  
  2,029
  
  2.2
  
  $
  4.52
  
  901
  
  $
  4.27$ 5.01 to $   7.00
  
  315
  
  2.8
  
  $
  6.61
  
  77
  
  $
  6.35$ 7.01 to $   9.00
  
  1,712
  
  3.4
  
  $
  7.87
  
  214
  
  $
  8.76$ 9.01 to $ 10.75
  
  1,070
  
  1.8
  
  $
  10.32
  
  713
  
  $
  10.32Total
  
  5,126
  
  2.5
  
  $
  6.98
  
  1,905
  
  $
  7.12  42 
    The Company
accounts for its stock options using intrinsic values.  On this basis, compensation costs are not
required to be recognized in the financial statements for stock options granted
at market value.  Had compensation costs
for the Companys stock option plan been determined based on the fair-value
method at the dates of grants under the plan after January 1, 2002, the
Companys pro-forma net income for the year ended December 31, 2002 would have
been reduced by $0.6 million and net income per share would be $0.85.  The weighted average fair market value of
options granted in 2002 was $3.65 per option. 
The fair value of the stock options granted is estimated on the grant
date using the Black-Scholes option-pricing model using the following
assumptions: risk free interest rate of 4%; expected life of 4 years; and
expected volatility of 57%.  The Company
had granted stock appreciation rights (Rights) to certain employees.  Holders of the Rights were entitled to
receive incentive payments based on the difference between market price of the
Companys common shares and exercise price of the Rights.  The exercise price of the Rights was
determined based on the market price of the Companys common shares at the time
the Rights were granted.  The Rights
vested over three years and had a term of four years.  During 2002, all 202,334 remaining Rights (2001 - 6,666) were
exercised.  The related compensation
expense has been included in general and administrative expenses.  Normal course issuer bid  During the
year ended December 31, 2002, the Company acquired 9,200 (2001 - 222,400) of
its common shares through a normal course issuer bid program at an average cost
of $6.03 per share (2001 - $3.87 per share). 
The shares purchased under the normal course issuer bid were cancelled.  In January 2003, the Company renewed the
normal course issuer bid to purchase up to 5.2 million common shares of the
Company during the 12-month period beginning January 7, 2003 and ending January
5, 2004.  Flow-through
shares  In accordance
with the terms of flow-through share offerings entered into by the Company and
one of its subsidiaries, and pursuant to certain provisions of the Income Tax
Act (Canada), the Company and its subsidiary fulfilled their commitment to
renounce for income tax purposes, exploration expenditures of $1.6 million in
2001 to the subscribers of the flow-through shares.  8.         Net Income and Cash
Flow from Operations per Share  The Company
applies the treasury stock method to assess the dilutive effect of outstanding
stock options on net income and cash flow from operations per share.  The number of shares used in the calculation
of diluted net income and cash flow from operations per share is determined as
follows:  2002
  
  2001Weighted
  average number of shares outstanding, basic
  
  52,298
  
  49,503Dilutive effect of stock options
  
  939
  
  701Weighted
  average number of shares outstanding, diluted
  
  53,237
  
  50,204  The diluted
net income and cash flow from operations per share discussed above did not
include 2.8 million (2001- 1.3 million) of stock options because the respective
exercise prices exceeded the average market price of the common shares during
the year.  43 
   9.         Income Taxes  The provision for income taxes has been
computed as follows:  2002
  
  2001Income (loss) before income taxes
  
  $
  92,808
  
  $
  (237,306
  )Expected
  income taxes (recovery) at the statutory rate of 43.9% (2001 - 44.0%)
  
  $
  40,743
  
  $
  (104,415
  )Increase
  (decrease) in taxes resulting from:Crown royalties
  
  21,153
  
  19,870Resource allowance
  
  (26,308
  )
  (22,560
  )Alberta royalty tax credit
  
  (219
  )
  (224
  )Rate change
  
  (138
  )
  183Other
  
  2,725
  
  (181
  )Large Corporation Tax and provincial
  capital tax
  
  9,716
  
  7,128Provision for income taxes
  
  $
  47,672
  
  $
  (100,199
  )  The components
of future income taxes are as follows:  As
  at December 31,2002
  
  2001Future
  income tax liabilities:Capital assets
  
  $
  202,429
  
  $
  173,430Future income tax assets:Abandonment costs
  
  (9,638
  )
  (9,038
  )Attributed Canadian Royalty Income
  
  (4,475
  )
  (5,263
  )Share issue costs
  
  (2,833
  )
  (4,398
  )Loss carry-forward
  
  (323
  )
  (7,528
  )Other
  
  (758
  )
  (757
  )Future income taxes
  
  $
  184,402
  
  $
  146,446  10.          Cash Flow Information  Increase (Decrease) in Non-Cash Working Capital Items  2002
  
  2001Current assets
  
  $
  38,528
  
  $
  (23,440
  )Current
  liabilities
  
  28,229
  
  (43,060
  )$
  66,757
  
  $
  (66,500
  )  2002
  
  2001Changes in non cash working capital related
  to:Operating activities
  
  $
  1,272
  
  $
  5,682Investing activities
  
  65,485
  
  (72,182
  )$
  66,757
  
  $
  (66,500
  )  During the year the Company made the
following cash outlays in respect of interest expense and current income taxes.  2002
  
  2001Interest
  
  $
  25,482
  
  $
  22,889Current income taxes (refund)
  
  $
  (3,298
  )
  $
  15,459  44 
   11.          Financial Instruments  The Companys
financial instruments recognized in the balance sheet consist of accounts
receivable, current liabilities and long-term borrowings.  The estimated fair values of financial
instruments have been determined based on the Companys assessment of available
market information and appropriate valuation methodologies; however, these
estimates may not necessarily be indicative of the amounts that could be
realized or settled in a current market transaction.  The fair
values of financial instruments other than long-term borrowings approximate
their carrying amounts due to the short-term maturity of these
instruments.  At December 31, 2002 and
2001, the reported values of the Companys senior secured term notes, bank loan
and other long-term debt approximate their fair values.  At December 31, 2002, the trading value of
the Companys senior subordinated term notes was 105% in relation to par (2001-
95%).  12.          Derivative Contracts  The nature of
the Companys operations results in exposure to fluctuations in commodity
prices, exchange rates and interest rates. 
The Company monitors and, when appropriate, utilizes derivative
contracts to manage its exposure to these risks.  The Company is exposed to credit-related losses in the event of
non-performance by counter-parties to these contracts.  In 2002, petroleum and natural gas sales
were reduced by $8.3 million (2001 - $9.5 million) due to derivative contracts.  At December
31, 2002, the Company had derivative contracts for the following:  Period
  
  Volume
  
  Price
  
  IndexOilPrice collar
  
  Calendar 2003
  
  2,500 bbl/d
  
  US$20.00  $26.05
  
  WTIPrice collar
  
  Calendar 2003
  
  5,000 bbl/d
  
  US$20.00  $26.60
  
  WTIPrice collar
  
  Calendar 2003
  
  2,500 bbl/d
  
  US$20.00  $27.00
  
  WTI  The fair value
of the oil derivative contracts at December 31, 2002 is an unrecognized
liability of $12.3 million.  Period
  
  Amount
  
  Exchange Rate
  
  Unrecognized loss at
  December 31, 2002Foreign currency swap
  
  January 1998
  to December 2005
  
  US$315,000
  per month
  
  CAD/USD $1.4228
  
  $
  2,008  13.          Commitments  In October 2002, the Company entered into a
long-term crude oil supply contract with a third party that requires the
delivery of 20,000 barrels per day of Lloydminster Blend crude oil at a price
fixed at 71% of NYMEX WTI oil price. 
The contract is for an initial term of five years commencing January 1,
2003.  The volumes contracted under this
contract will increase from 9,000 barrels per day in January 2003 to 20,000
barrels per day in October 2003 and thereafter.  For the period
November 1, 2002 to October 31, 2003, the Company has entered into natural gas
sales contracts with third parties for 15,000 GJ per day for fixed prices
averaging $5.35/GJ and 10,000 GJ per day of collar contracts with prices
between $4.20/GJ and $7.22/GJ.  45 
   14.          Corporate
Acquisitions  Effective May
1, 2001, the Company acquired all of the issued and outstanding shares of OGY
Petroleums Ltd. (OGY), a public company involved in the exploration,
development and production of oil and natural gas in Western Canada.  The acquisition has been accounted for by
the purchase method of accounting as follows:  Consideration  Cash
  
  $
  50,683Transaction costs
  
  3,10053,783Issue of 1,169,481 common shares
  
  14,057$
  67,840  Net
Assets Acquired  Petroleum and natural gas properties
  
  $
  116,607Future income taxes
  
  (36,127
  )Future site restoration costs
  
  (1,844
  )78,636Working capital deficiency
  
  (4,809
  )Long-term debt
  
  (5,987
  )$
  67,840  Effective June
1, 2001, the Company acquired all of the issued and outstanding shares of
Triumph Energy Corporation (Triumph), a public company involved in the
exploration, development and production of oil and natural gas in Western
Canada.  The acquisition has been
accounted for by the purchase method of accounting as follows:  Consideration  Cash
  
  $
  82,337Transaction costs
  
  11,30693,643Issue of 4,949,245 common shares
  
  54,047$
  147,690  Net
Assets Acquired  Petroleum and natural gas properties
  
  $
  248,480Future income taxes
  
  (77,751
  )Future site restoration costs
  
  (213
  )170,516Working capital
  
  7,543Long-term debt
  
  (30,369
  )$
  147,690  46 
   15.          Subsequent Event  On March 3, 2003, the Company signed an agreement to sell certain crude
oil and natural gas assets for total cash consideration of $133.3 million.  The sale is subject to certain conditions
and is scheduled to close by the end of March 2003.  Upon closing of this transaction, the Company intends to use the proceeds
for debt reduction and general corporate purposes.  16.          Comparative Figures  Certain
comparative figures have been reclassified to conform to the current years
presentation.   17.Differences Between Canadian and United States Generally Accepted
Accounting Principles  The consolidated financial statements have been prepared in accordance
with Canadian Generally Accepted Accounting Principles (GAAP), which differ
in some respects from GAAP in the United States.  The significant differences in GAAP, as applicable to these
consolidated financial statements and notes, are described in the Companys
Form 40-F, which is filed with the United States Securities and Exchange
Commission.  47