**UNITED STATESSECURITIES AND EXCHANGE COMMISSION**

**Washington,D.C. 20549**

 

# **FORM 20-F**

# ** **

| **(MARK ONE)**                                    |
|---------------------------------------------------|
| **o**                                             |   | **Registration statement pursuant to Section 12(b) of  the Securities Exchange Act of 1934** |
| **or**                                            |   |   |   |   |
|                                              |   |   |   |   |
| **ý**                                        |   | **Annual Report pursuant to Section 13 or 15(d) of the  Securities Exchange Act of 1934** |
| **or**                                            |   | **For the fiscal year ended:  December 31,  2003** |
|                                              |   |   |   |   |
| **o**                                             |   | **Transition Report pursuant to Section 13 or 15(d) of  the Securities Exchange Act of 1934** |
|                                              |   | **For the transition period  from   to                 ** |   |   |
|                                              |   |   |   |   |
| **Commission  File Number:  333-07612** |

 

**BAYTEX ENERGY LTD.**

(Exact name of Registrant as specified in its charter)

 

| **Alberta**                                                        |   | **1311**                                                                  |   | **Not Applicable**                                      |
|--------------------------------------------------------------------|--------|---------------------------------------------------------------------------|--------|---------------------------------------------------------|
| (Province or other jurisdiction of  incorporation or organization) |   | (Primary standard industrial  classification code number, if  applicable) |   | (I.R.S. employer identification  number, if applicable) |

 

 

| **Suite 2200, 205 – 5th Avenue S.W.  Calgary, Alberta  T2P 2V7  (403) 269-4282** |
|---------------------------------------------------------------------------------------|
| (Address and telephone number of registrant’s principle executive  offices)      |

 

Securitiesregistered or to be registered pursuant to Section 12(b) of the Act:

Title of each class: ** NONE**

 

Securitiesregistered or to be registered pursuant to Section 12(g) of the Act:

## **NONE**

## ** **

Securitiesfor which there is a reporting obligation pursuant to Section 15(d) of theAct:

**NONE**

 

Indicatethe number of outstanding shares of the issuer’s classes of capital or commonstock as of the close of the period covered by the annual report.

 
| **Common Shares:**      |   | **1**         |       |
|-------------------------|--------|---------------|------------|
| **Exchangeable Shares** |   | **3,724,649** | ** ** |

 

Indicateby check mark whether the registrant: (1) has filed all reports required to befiled by Section 13 or 15(d) of the Exchange Act during the preceding 12months (or for such shorter period that the Registrant was required to filesuch reports), and (2) has been subject to such filing requirements for thepast 90 days.

Yes       ý       No       o

 

Indicateby check mark which financial statement item the registrant has elected tofollow.

Item 17       ý       Item18       o

 

 

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| **Contents** |                                                        |   |
|--------------|-------------------------------------------------------------|--------|
| **PART I**   |                                                        |   |
|         |                                                        |   |
| **Item 1:**  | Identity of Directors, Senior  Management and Advisors      |   |
|         |                                                        |   |
| **Item 2:**  | Offer Statistics and Expected  Timetable                    |   |
|         |                                                        |   |
| **Item 3:**  | Key Information                                             |   |
|         | A.  Selected financial data                                 |   |
|         | B.  Capitalization and indebtedness                         |   |
|         | C. Reason for  the offer and use of proceeds                |   |
|         | D. Risk factors                                             |   |
|         |                                                        |   |
| **Item 4:**  | Information on the Company                                  |   |
|         | A.  History and development of the company                  |   |
|         | B. Business  Overview                                       |   |
|         | C.  Organizational structure                                |   |
|         | D. Property, plant and  equipment                           |   |
|         |                                                        |   |
| **Item 5:**  | Operating and Financial Review and  Prospects               |   |
|         | A.  Results of operations                                   |   |
|         | B.  Liquidity and capital resources                         |   |
|         | C. Research and  development, patent and licenses, etc.     |   |
|         | D. Trend information                                        |   |
|         | E. Off-balance  sheet arrangements                          |   |
|         | F. Tabular disclosure of  contractual obligations           |   |
|         | G. Safe harbor                                              |   |
|         |                                                        |   |
| **Item 6:**  | Directors, Senior Management and  Employees                 |   |
|         | A.  Directors and senior management                    |   |
|         | B. Compensation                                             |   |
|         | C. Board  practices                                         |   |
|         | D. Employees                                                |   |
|         | E. Share  ownership                                         |   |
|         |                                                        |   |
| **Item 7:**  | Major Shareholders and Related  Party Transactions          |   |
|         | A.  Major shareholders                                      |   |
|         | B. Related party  transactions                              |   |
|         | C. Interests of  experts and counsel                        |   |
|         |                                                        |   |
| **Item 8:**  | Financial Information                                       |   |
|         | A.  Consolidated statements and other financial information |   |
|         | B.  Significant changes                                     |   |
|         |                                                        |   |
| **Item 9:**  | The Offer and Listing                                       |   |
|         | A. Offer and listing details                                |   |
|         | B.  Plan of distribution                                    |   |
|         | C. Markets                                                  |   |
|         | D.  Selling shareholders                                    |   |
|         | E. Dilution                                                 |   |
|         | F.  Expenses of the issue                                   |   |

 

2

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| **Item 10:**  | Additional Information                                                        |   |
|---------------|-------------------------------------------------------------------------------|--------|
|          | A. Share  capital                                                             |   |
|          | B. Memorandum  and articles of association                                    |   |
|          | C.  Material contracts                                                        |   |
|          | D.  Exchange controls                                                         |   |
|          | E. Taxation                                                                   |   |
|          | F. Dividends and paying  agents                                               |   |
|          | G.  Statements by experts                                                     |   |
|          | H.  Documents on display                                                      |   |
|          | I.  Subsidiary information                                               |   |
|          |                                                                          |   |
| **Item  11:** | Quantitative  and Qualitative Disclosures About Market Risk                   |   |
|          |                                                                          |   |
| **Item  12:** | Description  of Securities Other than Equity Securities                       |   |
|          |                                                                          |   |
| **PART II**   |                                                                          |   |
|          |                                                                          |   |
| **Item 13:**  | Defaults, Dividend Arrearages  and Delinquencies                              |   |
|          |                                                                          |   |
| **Item 14:**  | Material Modifications to the  Rights of Security Holders and Use of Proceeds |   |
|          |                                                                          |   |
| **Item 15:**  | Controls and Procedures                                                       |   |
|          |                                                                          |   |
| **Item 16:**  | Reserved                                                                      |   |
|          |                                                                          |   |
| **Item 16A:** | Audit Committee Financial  Expert                                             |   |
|          |                                                                          |   |
| **Item 16B:** | Code of Ethics                                                                |   |
|          |                                                                          |   |
| **Item 16C:** | Principal Accountant Fees and  Services                                       |   |
|          |                                                                          |   |
| **Item 16D:** | Exemptions from Listing  Standards for Audit Committees                       |   |
|          |                                                                          |   |
| **Item 16E:** | Purchases of Equity  Securities by the Issuer and Affiliated Purchases        |   |
|          |                                                                          |   |
| **PART III**  |                                                                          |   |
|          |                                                                          |   |
| **Item 17:**  | Financial Statements                                                          |   |
|          |                                                                          |   |
| **Item 18:**  | Financial Statements                                                          |   |
|          |                                                                          |   |
| **Item 19:**  | Exhibits                                                                      |   |

 

3

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**SPECIAL NOTE REGARDINGFORWARD LOOKING STATEMENTS**

** **

Certainstatements included or incorporated by reference in this annual reportconstitute “forward-looking statements” within the meaning of the United StatesPrivate Securities Legislation Act of 1995. Such forward-looking statements involve known and unknown risks,uncertainties and other factors that may cause our actual results, performanceor achievements to be materially different from any future results, performanceor achievements expressed or implied by forward-looking statements.  When used in this annual report or indocuments incorporated by reference in this annual report, the words “believe,”“anticipate,” “estimate,” “project,” “intend,” “expect,” “may,” “will,” “plan,”“should,” “would,” “contemplate,” “possible,” “attempts,” “seeks” and similarexpressions are intended to identify these forward-looking statements.  These forward-looking statements were basedon various factors and were derived utilizing numerous assumptions and otherimportant factors that could cause actual results to differ materially fromthose in the forward-looking statements. Specific forward-looking statements contained in this annual report orin the documents incorporated by reference in this annual report include, amongothers, statements regarding:

 

•                  our expected financial performance in futureperiods;

•                  expected increases in revenues attributableto our exploration and production activities;

•                  our competitive advantages and ability tocompete successfully;

•                  our intention to continue adding valuethrough drilling;

•                  our plan to diversify our production mix byexpanding our natural gas operations;

•                  our emphasis on having a low cost structure;

•                  our intention to match our exploration anddevelopment capital expenditures to our cash flow;

•                  our reserve estimates and our estimates ofthe present value of our future net cash flows;

•                  our methods of raising capital forexploration and development of reserves;

•                  the factors upon which we will decide whetheror not to undertake an exploration or exploitation project;

•                  our plans to make acquisitions;

•                  our expectations regarding the explorationand production potential of our properties; and

 

Withrespect to forward-looking statements contained in this annual report or in thedocuments incorporated by reference in this annual report, we have madeassumptions regarding, among other things:

 

•                  future oil and gas prices;

•                  the cost of expanding our property holdings;

•                  our ability to obtain equipment in a timelymanner to meet our demand;

•                  our ability to market oil and gassuccessfully to current and new customers;

•                  the impact of increasing competition; and

•                  our ability to obtain financing on acceptableterms.

 

Someof the risks that could affect our future results and could cause results todiffer materially from those expressed in our forward-looking statementsinclude:

 

•                  the volatility of oil and gas prices,including the differential between the price of light and heavy oil;

•                  the uncertainty of estimates of oil andnatural gas reserves;

•                  the impact of competition;

•                  difficulties encountered during theexploration for and production of oil and natural gas;

•                  the difficulties encountered in deliveringoil and natural gas to commercial markets;

•                  changes in customer demand;

 

4

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•                  any decrease in investor demand for trustunits;

•                  foreign currency fluctuations;

•                  the uncertainty of our ability to attractcapital;

•                  changes in, or the introduction of new,government regulations relating to the oil and natural gas business;

•                  costs associated with exploring for andproducing oil and natural gas;

•                  compliance with environmental regulations;

•                  liabilities stemming from accidental damageto the environment;

•                  loss of the services of any of our executiveofficers; and

•                  adverse changes in the economy generally.

 

Theinformation contained in this annual report and in the documents incorporatedby reference in this annual report, including the information provided underthe heading “Risk Factors,” identifies additional factors that could affect ouroperating results and performance.  Weurge you to carefully consider those factors.

 

Allwritten or oral forward-looking statements attributable to us are expresslyqualified in their entirety by the foregoing cautionary statement.  You are cautioned not to rely on theforward-looking statements, which speak only as of the date of this annualreport.  We assume no obligation toupdate or to publicly announce the results of any revisions to any of theforward-looking statements to reflect actual results, future events or developments,changes in assumptions or changes in other factors affecting theforward-looking statements.

 

**DEFINITIONS AND OTHER MATTERS**

 

As used in this annual report, the followingterms have the meaning indicated:

 

•                  “bbls”and “mbbls” mean barrels and thousand barrels, respectively;

•                  “mcf“, “mmcf” and “bcf” mean thousand cubic feet, million cubic feet and billioncubic feet, respectively;

•                  “boe”and “mboe” mean barrel of oil equivalent and thousand barrels of oilequivalent, respectively;

•                  “bbls/d”,“mcf/d” and “boe/d” mean barrels per day, thousand cubic feet per day andbarrels of oil equivalent per day, respectively;

•                  “ngl”means natural gas liquids; and

 

Developed acreage means acreageon which we have a productive well. Undeveloped acreage means acreage on which we do not have a productivewell and includes exploratory acreage. Proved reserves are those reserves estimated as recoverable undercurrent technology and existing economic conditions under constant dollareconomics, from that portion of a reservoir which can be reasonably evaluatedas economically productive on the basis of analysis of drilling, geological,geophysical and engineering data, including the reserves to be obtained byenhanced recovery processes demonstrated to be economical and technicallysuccessful in the subject reservoir. Gross proved reserves or gross production are proved reserves orproduction attributable to our interest before deducting royalties; net provedreserves or net production are proved reserves or production after deductingroyalties.  Natural gas volumes areconverted to barrels of oil equivalent using the ratio of 6 thousand cubic feetof natural gas to one barrel of oil. Natural gas volumes are stated at the official temperature and pressurebases of the area in which the reserves are located.

 

5

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**PART 1**

 

**Item 1****. Identity ofDirectors, Senior Management and Advisors**

 

NotApplicable

 

**Item 2****. OfferStatistics and Expected Timetable**

 

NotApplicable

 

**Item 3****. KeyInformation**

 

**A. Selected Financial Data**

 

The financial data set forthbelow as at December 31, 2003 and 2002 and for each of the years in thethree-year period ended December 31, 2003 have been derived from ouraudited consolidated financial statements included in Item 17 of this Form 20-F.  Financial data at December 31, 2001,2000 and 1999 and for each of the years in the three-year period endedDecember 31, 2000 have been derived from our previously published auditedconsolidated financial statements not included in this document.

 

The financial data as atDecember 31, 2003 and 2002 and for each of the years in the three-yearperiod ended December 31, 2003 should be read in conjunction with, and arequalified in their entirety by reference to, our audited consolidated financialstatements.

 

The financial data isderived from our financial statements which have been prepared in accordancewith generally accepted accounting principles in Canada (“Canadian GAAP”), theapplication of which, in the case of Baytex Energy Ltd., conforms in all materialrespects for the periods presented with generally accepted accountingprinciples in the United States of America (“U.S. GAAP”), except as disclosedin footnotes to the consolidated financial statements.

 

The following table presentsa summary of our consolidated statement of operations derived from ourfinancial statements for 2003, 2002, 2001, 2000 and 1999.  All data presented below should be read inconjunction with the “Management’s Discussion and Analysis of FinancialCondition and Results of Operations” and our financial statements andaccompanying notes included elsewhere in this Form 20-F.

 

**Amounts in accordance with Canadian GAAP**

 

(in thousands of Canadian $, except per share data)

 
|                                |   | **December 31,** |   |
|-------------------------------------|--------|-----------------------|--------|
|                                |   | **2003**              |   | **2002** |   | **2001** |   | **2000** |   | **1999** |   |
| Petroleum and natural gas sales     |   | 351,404               |   | 365,860 |   | 329,700 |   | 286,226 |   | 120,087 |   |
| Income (loss) from operations       |   | 19,539                |   | 92,808 |   | (237,306 | ) | 75,797 |   | 25,231 |   |
| Net income (loss)                   |   | 21,376                |   | 45,136 |   | (137,107 | ) | 43,788 |   | 14,128 |   |
| Net income (loss) per common share: |   |                  |   |   |   |   |   |   |   |   |   |
| basic                               |   | 0.60                  |   | 0.86 |   | (2.77 | ) | 1.04 |   | 0.40 |   |
| Net income (loss) per common share: |   |                  |   |   |   |   |   |   |   |   |   |
| diluted                             |   | 0.60                  |   | 0.85 |   | (2.77 | ) | 1.01 |   | 0.39 |   |
| Total assets                        |   | 864,991               |   | 997,760 |   | 967,046 |   | 829,414 |   | 418,426 |   |
| Share capital                       |   | —                |   | 398,176 |   | 394,734 |   | 326,767 |   | 210,426 |   |
| Shareholders’ equity           |   | (288,546              | )      | 359,687 |   | 311,109 |   | 379,322 |   | 230,264 |   |
| Number of shares outstanding        |   | —                |   | 52,819 |   | 52,008 |   | 45,797 |   | 35,469 |   |
| Dividends declared                  |   | Nil                   |   | Nil |   | Nil |   | Nil |   | Nil |   |

 

6

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**Amounts in accordance with U.S. GAAP**

 

(inthousands of Canadian $, except per share data)

 
|                                |   | **December 31,** |   |
|-------------------------------------|--------|-----------------------|--------|
|                                |   | **2003**              |   | **2002** |   | **2001** |   | **2000** |   | **1999** |   |
| Petroleum and natural gas sales     |   | 351,404               |   | 365,860 |   | 329,700 |   | 286,226 |   | 120,087 |   |
| Net income (loss)                   |   | (26,154               | )      | 22,889 |   | (124,936 | ) | 52,175 |   | 30,348 |   |
| Net income (loss) per common share: |   |                  |   |   |   |   |   |   |   |   |   |
| basic                               |   | (0.73                 | )      | 0.44 |   | (2.52 | ) | 1.24 |   | 0.86 |   |
| Net income (loss) per common share: |   |                  |   |   |   |   |   |   |   |   |   |
| diluted                             |   | (0.73                 | )      | 0.43 |   | (2.52 | ) | 1.20 |   | 0.84 |   |
| Total assets                        |   | 719,078               |   | 855,719 |   | 829,027 |   | 707,352 |   | 315,183 |   |
| Share capital                       |   | —                |   | 412,118 |   | 408,676 |   | 340,709 |   | 224,368 |   |
| Shareholders’ equity           |   | (437,518              | )      | 286,129 |   | 259,799 |   | 317,134 |   | 155,026 |   |
| Number of shares outstanding        |   | —                |   | 52,819 |   | 52,008 |   | 45,797 |   | 35,469 |   |
| Dividends declared                  |   | Nil                   |   | Nil |   | Nil |   | Nil |   | Nil |   |

 

**Exchange Rate Information**

 

Wepublish our consolidated financial statements in Canadian dollars. In thisannual report, except where otherwise indicated, all dollar amounts are statedin Canadian dollars. References to “$” or “Cdn.$” are to Canadian dollars andreferences to “US$” are to U.S. dollars. The following table sets forth for each period indicated the period endexchange rates for conversion of U.S. dollars to Canadian dollars, the averageexchange rates on the last day of each month during such period and the highand low exchange rates during such period. These rates are based on the noon buying rate in New York City,expressed in U.S. dollars, for cable transfers in Canadian dollars as certifiedfor customs purposes by the Federal Reserve Bank of New York.  The exchange rates are presented as Canadiandollars per $1.00. On May 31, 2004, the noon buying rate was US$1.00 equalsCdn. $1.3634 and the inverse noon buying rate was Cdn.$1.00 equals US$0.7335.

 

**U.S. Dollar/Canadian Dollar Exchange Rates for Five MostRecent Financial Years**

 
| **Year Ended December 31,** |   | **2003** |   | **2002** |   | **2001** |   | **2000** |   | **1999** |   |
|----------------------------------|--------|----------|--------|----------|--------|----------|--------|----------|--------|----------|--------|
| End of period                    |   | 0.7738   |   | 0.6344   |   | 0.6285   |   | 0.6669   |   | 0.6918   |   |
|                             |   |     |   |     |   |     |   |     |   |     |   |
| Average for the period           |   | 0.7139   |   | 0.6372   |   | 0.6456   |   | 0.6732   |   | 0.6691   |   |

 

7

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**U.S. Dollar/Canadian Exchange Rates for Previous Six Months**

 
|   |   | **December  2003** |   | **January  2004** |   | **February  2004** |   | **March  2004** |   | **April  2004** |   | **May  2004** |   |
|--------|--------|--------------------|--------|-------------------|--------|--------------------|--------|-----------------|--------|-----------------|--------|---------------|--------|
| High   |   | 0.7747             |   | 0.7883            |   | 0.7650             |   | 0.7659          |   | 0.7638          |   | 0.7335        |   |
| Low    |   | 0.7447             |   | 0.7481            |   | 0.7398             |   | 0.7357          |   | 0.7301          |   | 0.7159        |   |

 

**B. Capitalization and Indebtedness**

 

NotApplicable

 

**C. Reasons for the Offer and Use of Proceeds**

 

NotApplicable

 

**D. Risk Factors**

 

Set out below are certainrisk factors that could materially adversely affect our business and our cashflow, operating results and financial condition.

 

**Oil and natural gas prices arevolatile, and low prices will adversely affect our business.**

 

Fluctuationsin the prices of oil and natural gas will affect many aspects of our business,including:

•                  our revenues, cash flows and earnings;

•                  our ability to attract capital to finance ouroperations;

•                  our cost of capital;

•                  the amount we are allowed to borrow under oursenior credit facilities; and

•                  the value of our oil and natural gasproperties.

 

Bothoil and natural gas prices are extremely volatile.  Any material decline in prices will result in a reduction of ournet production revenue, overall value and the economics of producing from somewells.  Any material decline in priceswould likely also result in a reduction in our oil and natural gas acquisitionand development activities.

 

Inaddition, a material decline in oil and natural gas prices from historicalaverage prices would reduce our borrowing base under our senior creditfacilities, therefore reducing amounts available to us and possibly requiringthat a portion of our senior credit facilities be repaid.

 

**You should not unduly rely onreserve information because reserve information represents estimates and ouractual reserves could be lower than the estimates.**

 

Estimatesof oil and natural gas reserves involve a great deal of uncertainty, becausethey depend in large part upon the reliability of available geologic andengineering data, which is inherently imprecise.  Geologic and engineering data are used to determine theprobability that a reservoir of oil and natural gas exists at a particularlocation, and whether oil and natural gas are recoverable from a reservoir.

 

Theprobability of the existence and recoverability of reserves is less than 100%and actual recoveries of proved reserves usually differ from estimates.

 

8

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Estimatesof oil and natural gas reserves also require numerous assumptions relating tooperating conditions and economic factors, including, among others:

•                  the price at which recovered oil and naturalgas can be sold;

•                  the costs associated with recovering oil andnatural gas;

•                  the prevailing environmental conditionsassociated with drilling and production sites;

•                  the availability of enhanced recoverytechniques;

•                  the ability to transport oil and natural gasto markets; and

•                  governmental and other regulatory factors,such as taxes and environmental laws.

 

Achange in any one or more of these factors could result in known quantities ofoil and natural gas previously estimated as proved reserves becomingunrecoverable and the present value of future net cash flows from estimatedreserves being reduced.

 

Inaddition, estimates of reserves and future net cash flows expected from themprepared by different independent engineers or by the same engineers atdifferent times, may vary substantially.

 

Inaddition, in accordance with Canadian GAAP, we could be required to write downthe carrying value of our oil and natural gas properties if oil and natural gasprices become depressed for even a short period of time, or if there aresubstantial downward revisions to our quantities of proved reserves.  A write down would result in a charge toearnings and a reduction of shareholders’ equity.

 

**Our heavy oil production increasesour susceptibility to low oil prices, because the price we receive for heavyoil is lower than for light oil.**

 

Theprice we receive for heavy oil is lower than for light oil.  In addition, seasonal fluctuation in demandfor heavy oil affects the price differential between light and heavy oil.  One of the main by-products from refiningheavy oil is asphalt that is used in road paving.  In general, municipal, state and provincial governments,particularly in Canada and the northern states of the United States, expend themajority of their budgets for road infrastructure improvements during thespring and summer months.  Thus, thedemand from the refineries to process heavy oil is the strongest during thisperiod, which usually leads to higher prices for heavy oil in the spring andsummer months.  The effect of anincrease in the price differential between light and heavy oil could adverselyaffect the profitability of heavy oil compared to light oil.

 

**If we are unsuccessful in acquiringand developing oil and gas properties, we will be prevented from increasing ourreserves and our business will be adversely affected because we will eventuallyrun out of reserves.**

 

Thesuccessful acquisition and development of oil and gas properties requires anassessment of:

•                  recoverable reserves;

•                  future oil and gas prices and operatingcosts;

•                  potential environmental and otherliabilities; and

•                  productivity of new wells drilled.

 

Theseassessments are inexact and if they are made too inaccurately, we will notrecover the purchase price of a property from the sale of production from theproperty, or will not recognize an acceptable return from properties weacquire.

 

Inaddition, the costs of exploitation and development could materially exceedinitial estimates.

 

9

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**We will not be able to develop ourreserves or make acquisitions if we are unable to generate sufficient cash flowor raise capital.  If we are unable toincrease our reserves, our business will be adversely affected because we willeventually run out of reserves.**

 

Wewill be required to make substantial capital expenditures to develop ourexisting reserves, to discover new oil and gas reserves and to makeacquisitions.  We will be unable toaccomplish these tasks if we are unable to generate sufficient cash flow orraise capital in the future.

 

**Drilling activities are subject tomany risks and any interruption or lack of success in our drilling activitywill adversely affect our business because drilling is expensive and a lack ofsuccess will prevent us from increasing our reserves.**

 

Drillingactivities are subject to many risks, including the risk that no commerciallyproductive and profitable reservoirs will be encountered and that we will notrecover all or any portion of our investment. The cost of drilling, completing and operating wells is often uncertain.  Our drilling operations could be curtailed,delayed or cancelled as a result of numerous factors, many of which are beyondour control, including:

•                  adverse weather conditions;

•                  compliance with governmental requirements;and

•                  shortages or delays in the delivery ofequipment and services.

 

**Our operations are affected byoperating hazards and uninsured risks and a shutdown or slowdown of ouroperations will adversely affect our business.**

 

Thereare many operating hazards in exploring for and producing oil and natural gas,including:

•                  our drilling operations could encounterunexpected formations or pressures that could cause damage to equipment orpersonal injury;

•                  we could experience blowouts, accidents, oilspills, fires or other damage to a well that could require us to redrill it ortake other corrective action;

•                  we could experience equipment failure thatcurtails or stops production;

•                  our drilling and production operations, suchas trucking of oil, are often interrupted by bad weather; and

•                  we would be unable to access our propertiesor conduct our operations due to surface conditions.

 

Anyof these events could result in damage to or destruction of oil and natural gaswells, production facilities or other property, or injury to persons.  In addition, any of the above events couldresult in environmental damage or personal injury for which we will be liable.

 

Theoccurrence of a significant event not fully insured or indemnified againstcould seriously harm our financial condition and operating results.

 

**Our hedging activities could resultin losses.**

 

Thenature of our operations results in exposure to fluctuations in commodityprices.  We monitor and, whenappropriate, utilize derivative financial instruments and physical deliverycontracts to hedge our exposure to these risks.  We are exposed to credit-related losses in the event ofnon-performance by counter-parties to the financial instruments.  From time to time we enter into hedgingactivities in an effort to mitigate the potential impact of declines in oil andnatural gas prices.  You should alsorefer to Item 5 of this annual report entitled “Risk and Risk Management”.

 

Ifproduct prices increase above those levels specified in our various hedgingagreements, the fixed price will limit us from receiving the full benefit ofcommodity price increases.

 

10

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Inaddition, by entering into these hedging activities, we will suffer financialloss if:

•                  we are unable to produce oil or natural gasto fulfill our obligations;

•                  we are required to pay a margin call on ahedge contract; or

•                  we are required to pay royalties based on amarket or reference price that is higher than our fixed or ceiling price.

 

In2003, we incurred $33.8 million in losses due to hedging.  In 2002, we incurred $8.3 million in lossesdue to hedging.

 

**Complying with environmental andother government regulations could be costly and could negatively impact ourproduction.**

 

Ouroperations are governed by numerous Canadian laws and regulations at theprovincial and federal level.  These lawsand regulations govern the operation and maintenance of our facilities, thedischarge of materials into the environment and other environmental protectionissues.

 

Underthese laws and regulations, we could be liable for personal injury, clean-upcosts, remedial measures and other environmental and property damages, as wellas administrative, civil and criminal penalties.  We do not believe that insurance coverage for the full potentialliability of environmental damages is available at a reasonable cost, so wecould be liable, or could be required to cease production on properties, ifenvironmental damage occurs.

 

Itis possible that the costs of complying with environmental laws and regulationsin the future will have a material adverse effect on our financial condition orresults of operations.  Furthermore,future changes in environmental laws and regulations could result in materiallyincreased costs for us, stricter standards and enforcement, larger fines andliability, and increased capital expenditures and operating costs, any of whichcould have a material adverse effect on our financial condition or results ofoperations.

 

**Certain factors beyond our controlcan affect our ability to market production. Since we cannot fully protect ourselves from these factors, the impactof them, if serious, could adversely affect our business.**

 

Ourability to market oil and gas from our wells depends upon numerous factorsbeyond our control.  These factorsinclude:

•                  the availability of capacity to refine heavy oil;

•                  the availability of natural gas processingcapacity;

•                  the availability of pipeline capacity;

•                  the supply of and demand for oil and naturalgas;

•                  the availability of alternative fuel sources;

•                  the availability of diluent to blend withheavy oil to enable transportation;

•                  the effects of inclement weather;

•                  Canadian federal and provincial regulation ofoil and natural gas marketing; and

•                  Canadian federal regulation of natural gassold or transported outside of the province of Alberta.

Becauseof these factors, we could be unable to market all of the oil or gas weproduce.  In addition, we could beunable to obtain favorable prices for the oil and gas we produce.

 

**The oil andnatural gas industry is highly competitive.**

 

We compete for capital, acquisitionsof reserves, undeveloped lands, skilled personnel, access to drilling rigs,service rigs and other equipment, access to processing facilities, pipeline andrefining capacity and in many other respects with a substantial number of otherorganizations, many of which may have greater technical and

 

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financial resources than we do. Some of these organizations not onlyexplore for, develop and produce oil and natural gas but also carry on refiningoperations and market oil and other products on a worldwide basis. As a resultof these complementary activities, some of our competitors may have greater andmore diverse competitive resources to draw on than we do. Given the highlycompetitive nature of the oil and natural gas industry, this could adverselyaffect the market price of our trust units and distributions to unitholders.

 

**Our currentcredit facilities and any replacement credit facilities may not providesufficient liquidity.**

 

Baytex has credit facilitiesin the amount of $165 million. Variations in interest rates and scheduled principal payments couldresult in significant changes in the amount required to be applied to debtservice before payment of any amounts to the Trust.  Although it is believed that the bank line of credit issufficient, there can be no assurance that the amount will be adequate for thefinancial obligations of Baytex or that additional funds can be obtained.

 

**Theindustry in which we operate exposes us to potential liabilities that may notbe covered by insurance.**

 

Our operations are subjectto all of the risks associated with the operation and development of oil andnatural gas properties, including the drilling of oil and natural gas wells,and the production and transportation of oil and natural gas. These risksinclude encountering unexpected formations or pressures, premature declines ofreservoirs, blow-outs, equipment failures and other accidents, cratering, sourgas releases, uncontrollable flows of oil, natural gas or well fluids, adverseweather conditions, pollution, other environmental risks, fires and spills. Anumber of these risks could result in personal injury, loss of life, orenvironmental and other damage to our property or the property of others. Wecannot fully protect against all of these risks, nor are all of these risksinsurable. We may become liable for damages arising from these events againstwhich we cannot insure or against which we may elect not to insure because ofhigh premium costs or other reasons. Any costs incurred to repair these damagesor pay these liabilities would reduce funds available for distribution tounitholders.

 

**Theoperation of oil and natural gas wells could subject us to environmental claimsand liability.**

 

The oil and natural gasindustry is subject to extensive environmental regulation pursuant to local,provincial and federal legislation. A breach of that legislation may result inthe imposition of fines or the issuance of “clean up” orders. Legislationregulating the oil and natural gas industry may be changed to impose higherstandards and potentially more costly obligations. For example, the 1997 KyotoProtocol to the United Nation’s Framework Convention on Climate Change, knownas the Kyoto Protocol, was ratified by the Canadian government in December,2002 and will require, among other things, significant reductions in greenhousegases. The impact of the Kyoto Protocol on us is uncertain and may result insignificant additional costs (future) for our operations. Although we record aprovision in our financial statements relating to our estimated futureenvironmental and reclamation obligations, we cannot guarantee that we will beable to satisfy our actual future environmental and reclamation obligations.

 

We are not fully insuredagainst certain environmental risks, either because such insurance is notavailable or because of high premium costs. In particular, insurance againstrisks from environmental pollution occurring over time (as opposed to suddenand catastrophic damages) is not available on economically reasonable terms.

 

Accordingly, our propertiesmay be subject to liability due to hazards that cannot be insured against, orthat have not been insured against due to prohibitive premium costs or forother reasons. Any site reclamation or abandonment costs actually incurred inthe ordinary course of business in a specific period will be funded out of cashflow and, therefore, will reduce the amounts available for distribution tounitholders. Should we be unable to fully fund the cost of remedying anenvironmental problem, we might be required to suspend operations or enter intointerim compliance measures pending completion of the required remedy.

 

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**We mayundertake acquisitions that could limit our ability to manage and maintain ourbusiness, result in adverse accounting treatment and are difficult to integrateinto our business. Any of these events could result in a material change in ourliquidity, impair our ability to pay dividends and could adversely affect thevalue of your investment.**

 

A component of future growthwill depend on the ability to identify, negotiate, and acquire additionalcompanies and assets that complement or expand existing operations. However wemay be unable to complete any acquisitions, or any acquisitions we may completemay not enhance our business. Any acquisitions could subject us to a number ofrisks, including:

 

•                  diversion of management’sattention;

 

•                  inability to retain themanagement, key personnel and other employees of the acquired business;

 

•                  inability to establishuniform standards, controls, procedures and policies;

 

•                  inability to retain theacquired company’s customers;

 

•                  exposure to legal claims foractivities of the acquired business prior to acquisition; and inability tointegrate the acquired company and its employees into our organizationeffectively.

 

**Since weare a Canadian company and all of our assets and key personnel are located inCanada, you may not be able to enforce a U.S. judgment for claims you may bringagainst us, our assets, our key personnel or many of the experts named in thisannual report. This may prevent you from receiving compensation to which youwould otherwise be entitled.**

 

We have been organized underthe laws of Alberta, Canada and all of our assets are located outside theU.S.  In addition, the members of ourBoard of Directors and our officers are residents of countries other than theU.S.  As a result, it may be impossiblefor you to effect service of process upon us or these individuals within theU.S. or to enforce any judgments in civil and commercial matters, includingjudgments under U.S. federal securities laws. In addition, a Canadian court may not permit you to bring an originalaction in Canada or to enforce in Canada a judgment of a U.S. court based uponcivil liability provisions of the U.S. federal securities laws.

 

**Item 4****. Informationon the Company**

 

**A. History and Development of the Company**

 

Thehead office of Baytex Energy Ltd. (“Baytex” or the “Company”) is located atSuite 2200, 205 - 5th Avenue S.W., Calgary, Alberta, T2P 2V7, telephone (403)269-4828 and its registered office is located at Suite 1400, 350 – 7thAvenue S.W., Calgary, Alberta T2P 3N9, telephone (403) 260-0100.

 

Baytexwas incorporated in Canada under the *Business Corporations Act*(Alberta) onJune 3, 1993.  On August 5,1993, Baytex filed Articles of Amendment to delete the private companyrestrictions thereunder.  OnOctober 13, 1993, Articles of Amendment were filed to amend Baytex’scapital structure to create Class A Shares and Class B Non-Voting Shares.  On October 21, 1997, Baytex filedArticles of Amalgamation to amalgamate with its wholly-owned subsidiary, DorsetExploration Ltd.  On May 28, 1999,Baytex filed Articles of Amendment to eliminate the Class B Shares and tochange the designation of the Class A Shares in the share capital of Baytexfrom “Class A Shares” to “common shares”.

 

InMay 2001, Baytex acquired all of the issued and outstanding shares of OGYPetroleums Ltd. (“OGY”), a public oil and gas company, the shares of which werelisted on the TSX.  The totalconsideration paid by Baytex for OGY was $50.7 million in cash and 1.2 millionBaytex common shares.  The operations ofOGY concentrated on light oil and natural gas in central Alberta.

 

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Alsoin May 2001, Baytex acquired all of the issued and outstanding shares ofTriumph Energy Corporation (“Triumph”), a public oil and gas company, the sharesof which were listed on the TSX.  Thetotal consideration paid for Triumph was $82.3 million in cash and 4.9 millionBaytex common shares.  The operations ofTriumph were focused on the exploration and development of natural gas inCentral Alberta and light oil and natural gas in East Central and SouthernAlberta.

 

OnJanuary 1, 2002, Baytex filed Articles of Amalgamation to amalgamate withits wholly-owned subsidiaries, OGY and Triumph.

 

Additionalheavy oil assets were acquired in the Cold Lake, Alberta and Carruthers,Saskatchewan areas in three separate property acquisitions in 2001 and 2002 fortotal cash consideration of $73.4 million.

 

Inthe fourth quarter of 2001 and first quarter of 2002, Baytex executed a plan tostrengthen its balance sheet with the divestiture of certain oil and naturalgas assets.  This plan included the saleof light oil and natural gas assets for total proceeds of $101 million.  This was later augmented in the firstquarter of 2003 with the completion of the sale of natural gas assets in theFerrier/O’Chiese area for proceeds of $133.3 million. Proceeds of the assetsales were applied to reduce outstanding indebtedness.

 

OnSeptember 2, 2003, Baytex completed a Plan of Arrangement (the“Arrangement”) whereby holders of common shares of Baytex elected or weredeemed to have elected to receive either trust units (the “Trust Units”) ofBaytex Energy Trust (the “Trust”) or exchangeable shares of Baytex (the“Exchangeable Shares”) for their common shares on the basis of one Trust Unitor Exchangeable Share, respectively, for each common share held. Coincidentwith the Arrangement becoming effective, certain of Baytex’s exploration assetswere acquired by Crew Energy Inc. (“Crew”), and the common shares of Crew weredistributed to the former holders of Baytex common shares on the basis ofone-third of a common share of Crew for each such share held.  The estimated fair market value atSeptember 2, 2003 of the securities issued during the reorganization was$11.76 per Trust Unit and $0.55 per one-third of a common share of Crew.

 

OnSeptember 2, 2003, Baytex was amalgamated with Baytex Acquisition Corp.pursuant to the Arrangement.

 

**B. Business Overview**

 

Weare an intermediate oil and gas company engaged in the exploration, developmentand production of oil and natural gas. We operate substantially all of our production in two core project areasin the provinces of Alberta and Saskatchewan, Canada.  We have acquired our land holdings through government land sales,freehold acquisitions, drilling on farm-in lands and property and corporateacquisitions.  We focus on building ourasset base through land assembly, acquisitions of seismic data and exploratoryand development drilling.  Our drillingefforts are concentrated on properties that we believe will provide long livedreserves that will generate cash flow in the near term.  We continually look for opportunities toenhance our position in our core areas and intend to pursue strategic acquisitionsthat are within the operating and financial parameters that we haveestablished.  See also Item 4 “Property,Plants and Equipment”.

 

**C. Organizational Structure**

 

TheTrust is the holder of the common share of Baytex.  Certain former shareholders of Baytex own Exchangeable Shares inaccordance with the elections made by such shareholders under the Arrangement.Baytex continues to carry on an oil and natural gas business similar to thatcarried on by Baytex prior to the Arrangement becoming effective.  Baytex owns, directly or indirectly, all ofthe assets that were owned by Baytex prior to the Arrangement becomingeffective, other than certain oil and gas and exploration assets that weretransferred to Crew in accordance with the Arrangement.

 

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**Inter-Corporate Relationships**

** **

Thefollowing table provides the name, the percentage of voting securities owned byBaytex and the jurisdiction of incorporation, continuance or formation of thesesubsidiaries either, direct and indirect, as at the date hereof.

 
|                     |   | **Percentage  of voting securities  (directly or indirectly)** |   | **Jurisdiction  of  Incorporation** |   |
|--------------------------|--------|----------------------------------------------------------------|--------|-------------------------------------|--------|
| Baytex Energy (USA) Inc. |   | 100                                                            | %      | Delaware                            |   |
| Baytex Marketing Ltd.    |   | 100                                                            | %      | Alberta                             |   |

 

**D. Property, Plants and Equipment**

 

Thefollowing is a description of Baytex’s principal oil and natural gas propertieson production or under development as at January 1, 2004.  The term “net”, when used to describeBaytex’s share of production, means the total of Baytex’s working interestshare before deduction of royalties owned by others. Reserve amounts arestated, before deduction of royalties, at January 1, 2004, based onforecast cost and price assumptions (gross) as evaluated in the independentreserve evaluators (see “ Reserves and Present Value Summary”).  Unless otherwise specified, gross and netacres and well count information are as at January 1, 2004.  Information in respect of current productionis average production, net to Baytex, for the year ended December 31,2003, except where otherwise indicated. Information related to land holdings is at December 31, 2003.

 

The crude oil and natural gas properties in whichBaytex has an interest are within two districts in Alberta andSaskatchewan.  Each district constitutesa well-balanced portfolio of operated properties and development prospects withconsiderable upside potential.

 

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****

 

*HeavyOil District*

 

The Heavy Oil District accounts for approximatelytwo-thirds of Baytex’s current production and approximately three-quarters ofreserves.  Heavy oil operations consistlargely of cold conventional production from wells with multi-zonepotential.  Production is generatedprimarily from vertical, slant and horizontal wells using progressive cavitypump technology to generate large volumes of heavy oil combined with gas, waterand sand.  Production from these wellsusually averages between 40 and 100 Bbls/d of low gravity crude ranging from 11to 18 API.  Once produced, the oil istrucked or pipelined to markets in both Canada and the United States forupgrading into lighter grades of crude or refined into petroleum products suchas fuel oil, lubricants and asphalt.

 

During 2003, production in the Heavy Oil Districtaveraged 25,676 Boe/d made up of 23,911 Bbls/d of heavy oil and 10.6 Mmcf/d ofnatural gas.  Baytex drilled 174 gross(165.2 net) wells in the district, resulting in 159 gross (150.2 net) oilwells, four gas wells, four service wells, and seven dry and abandoned wellsfor a success rate of 96 percent.

 

Baytex possesses a vast inventory of developmentprojects in the west central Saskatchewan heavy oil region and the Cold Lake,Ardmore and Seal areas of north central Alberta.  The ability to generate replacement production throughconventional drilling methods allows Baytex to better control the cost andtiming of its capital investments.

 

Baytex will continue to build value through internalproperty development and selective acquisitions.  Future heavy oil activity will focus on the development of theSeal and Ardmore Properties along with continued infill drilling at adjacentCold Lake and throughout the Saskatchewan Properties.

 

Ardmore:  Ardmore is one of the key heavy oildevelopment and production areas for Baytex. Acquired in 2002, this year-round access area generated approximately3,100 Bbls/d of oil in 2003, with current production in excess of 4,500Bbls/d.  Since acquiring this property,Baytex has applied leading-edge heavy oil drilling and production technology toimprove production and reduce cost.  Wellsin the area are 100 percent owned and operated by Baytex and they are able toproduce up to 300 Bbls/d of 11 to 13 API heavy crude oil primarily from theMcLaren and Sparky formations.  Baytexdrilled 48 gross (47.6 net) oil wells in the area during 2003, resulting in 47gross (46.6 net) oil wells and one service well.  Baytex holds approximately 32,000 net acres of 100 percentworking interest undeveloped land in this area.

 

Cold Lake:  Baytex acquired the Cold Lake heavy oilproperty in 2001.  This year-rounddrilling area is located on Cold Lake First Nations Land with heavy oilproduction generated largely from the Colony formation.  Average production was 935 Bbls/d during2003.  Baytex drilled 15 gross (13.5net) operated oil wells in the Cold Lake area during 2003 and holds 19,500 netacres of undeveloped land.

 

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Seal:  The Seal property is a highly prospectiveheavy oil area for Baytex.  The propertyis located in the Peace River oilsands area of northwest Alberta.   Baytex holds 100 percent working interestsin approximately 58 sections of land of which 44 sections were acquired in2003.  The Seal oil deposits can be producedthrough horizontal wells using primary production technology without the use ofcapital intensive steam injection methods. Baytex completed a seven-well test program during the first quarter of2004.  A development plan for a pilotproduction is being designed for the second half of 2004 and the winter of2005.

 

Tangleflags:  Baytex acquired the Tangleflags propertythrough the acquisition of Bellator Exploration Inc. in 2000.  Tangleflags is characterized bymultiple-zone reservoirs with production from the Colony, McLaren, Waseca, Sparky,General Petroleum and Lloydminster formations. Provincial government regulations generally prohibit production frommore than one formation at a time.  Assuch, this property possesses long-term development potential with aconsiderable number of up-hole completion opportunities.  Average production during 2003 was 4,940Bbls/d of heavy oil and 1.6 Mmcf/d of natural gas.

 

Carruthers:  The Carruthers property was obtained byBaytex in 1997 through the merger with Dorset Exploration Ltd.  The property consists of two separate poolsin the Cummings formation.  During 2003,average production was 3,300 Bbls/d of heavy oil and 0.6 Mmcf/d of naturalgas.  Baytex drilled 35 gross (29.75net) oil wells in the Carruthers area during 2003, resulting in 33 gross (27.75net) oil wells and 2 dry holes for an overall drilling success rate of 94percent.  Baytex has continued todevelop the southern pool since 1999, with 15 to 20 locations planned for 2004.

 

Marsden/Silverdale:  TheMarsden/Silverdale area of Saskatchewan is characterized by quality oil of 13to 18 API and production averaging 100 Bbls/d per well.  The lighter gravity oil allows production tobe flow-lined to treating and disposal facilities thereby reducing truckingcosts.  Lower trucking costs, combinedwith characteristically low sand production, result in lower overall operatingcosts.  Production averaged 3,400 Bbls/dof oil and 1.1 Mmcf/d of natural gas during 2003.  Baytex drilled 9 oil wells in the area during 2003, with 100percent success.  Baytex hasapproximately 12,000 net acres of undeveloped land in the Marsden/Silverdalearea.

 

*ConventionalOil and Gas District*

 

The Conventional Oil and Gas District includesProperties located in Alberta producing light and medium gravity crude oil,natural gas and related liquids. Production in this district averaged 11,010 Boe/d for the year endedDecember 31, 2003, consisting of 2,273 Bbls/d of oil and natural gasliquids and 52.4 Mmcf/d of natural gas.

 

Excluding production from the Ferrier area, whichwas sold in March 2003, and production from the properties which weretransferred to Crew pursuant to the Arrangement, production in this districtaveraged 1,860 Bbls/d of oil and natural gas liquids and 45.2 Mmcf/d of naturalgas, or 9,400 Boe/d during 2003.

 

Leahurst:  Baytex began operations in the Leahurst areain 1993.  Production in the area isprimarily natural gas from the Belly River and lower Mannville formations.  Baytex holds approximately 19,000 net acresof land in the area, interests in two gas plants and a 100-km gathering system.  In 2003, Baytex drilled 7.8 net successfulnatural gas wells.  The Leahurst areahas year-round access, which allows Baytex to conduct continuous developmentactivities.  Baytex’s average productionfor 2003 was 7.3 Mmcf/d of natural gas in this area.

 

Red Earth/Goodfish:  Baytexcommenced operations in this area through the merger with Dorset ExplorationLtd. in 1997.  Production includes lightoil from the Slave Point and Granite Wash formations and natural gas from theBluesky formation.  In 2003, Baytexdrilled 10.2 net wells in the area resulting in 5 net oil wells and 5

 

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netnatural gas wells.  Baytex holdsapproximately 58,000 net acres of undeveloped land in this area.  Baytex’s average production in 2003 was1,000 Bbls/d of light oil and 9.8 Mmcf/d of natural gas.

 

Nina/Darwin:  Baytex began operations in the Darwin area in1998, targeting natural gas from the Bluesky formation.  Production from Nina commenced inMarch 2001.  Baytex holds approximately34,000 net acres of land in the area. Average production in this area in 2003 was 4.9 Mmcf/d of natural gas.

 

Bon Accord:  The Bon Accord natural gas property wasacquired by Baytex in 1997 through the merger with Dorset Exploration Ltd.  Baytex utilizes 3-D seismic technology toidentify gas-producing zones in the Mannville, Nisku and Sparkyformations.  Baytex drilled 8 wells inthe Bon Accord area during 2003, resulting in 5 natural gas wells and 1 oil well.  Average production was 8.4 Mmcf/d of naturalgas and 360 Bbls/d of oil and natural gas liquids.  Baytex has approximately 13,000 net acres of land in this area.

 

Hamburg/Chinchaga:  Baytexconstructed a natural gas processing plant in this area during 2003 withprocessing capacity of 8.0 Mmcf/d. Baytex’s production in the area averaged approximately 5 Mmcf/dduring 2003, leaving approximately 3 Mmcf/d of plant capacity forthird-party processing which is expected to be filled by the end of the firstquarter of 2004.  Baytex has had successtargeting natural gas in the Slave Point, Bluesky and Gilwood formations.  Drilling activity in 2003 resulted in twosuccessful natural gas wells.  Netlandholdings in the area total 17,500 acres as at December 31, 2003.

 

**Reserves and Present Value Summary**

 

Baytexis required to comply with the National Instrument 51-101, (“NI 51-101”) issuedby the Canadian Securities Administrators, in all its reserves relateddisclosures. NI 51-101 came into effect on September 30, 2003 and isapplicable for financial years ended on or after December 31, 2003.  The purpose of NI 51-101 is to enhance thequality, consistency, timeliness and comparability of oil and gas activities byreporting issuers and elevate reserves reporting to a higher level ofaccountability.  NI 51-101 brought aboutsignificant changes in which Canadian reporting issuers manage and publiclydisclose information relating to their oil and gas reserves, mandates annualdisclosure requirements and prescribes new reserve definitions as follows:

 

NI 51-101 requires a higher degree of confidence inthe assignment of oil and gas reserves. Under NI 51-101, proved reserves are defined to have a 90% probabilitythat the actual reserves recovered will equal or exceed the assigned estimatescompared to the previous definition of “reasonable certainty” as stipulated byNational Policy 2-B (“NP 2-B”).  Also,under NI 51-101, probable reserves are defined to have a 50% probability thatthe actual reserves recovered will equal or exceed the assigned estimatescompared to the previous definition of “likelihood of existence” in NP2-B.  Because of the more stringentrequirements under NI 51-101, the industry has adopted the interpretation thatthe new proved plus probable (P-50) reserves represent the most “realistic” estimatesof remaining recoverable reserves. The following reserves information alsoadopts the general industry practice of comparing the new P-50 reserves to theprevious proved plus risk adjusted (50%) probable reserves, commonly referredto as “established reserves”, under NP 2-B.

 

Inthe United States, registrants [other than foreign private issuers] arerequired to disclose reserves using the standards contained in U.S. RegulationS-X, and the standardized measure of discounted future net cash flows relatingto proved oil and gas reserves determined in accordance with United StatesStatement of Financial Accounting Standards No.69 “Disclosures About Oil andGas Producing Activities’’ (“FAS 69’’). As a foreign private issuer, Baytex ispermitted to comply with the disclosure requirements contained in NI 51-101 forthe purposes of its U.S. regulatory filings. Unless otherwise indicated, all ofthe reserves and production information disclosure in this Form 20-F is incompliance with NI 51-101.

 

Theprimary differences between the U.S. requirements and the NI 51-101requirements are that (i)the U.S. standards require disclosure only of provedreserves, whereas NI 51-101 requires disclosure of proved and probablereserves, and (ii) the U.S. standards require that the reserves and relatedfuture net revenue be

 

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estimatedunder existing economic and operating conditions, i.e., prices and costs as ofthe date the estimate is made, whereas NI 51-101 requires disclosure of provedreserves and the related future net revenue estimated using constant prices andcosts as at the last day of the financial year, and of proved and probablereserves and related future net revenue using forecast prices and costs.  The definitions of proved reserves alsodiffer, but according to the Canadian Oil and Gas Evaluation Handbook (thereference source for the definition of proved reserves under NI 51-101),differences in the estimated proved reserve quantities based on constant pricesshould not be material.  Baytex believesthat the definition and measurement of proved reserves under NI 51-101 will bemore conservative than proved reserves under U.S. standards.

 

Inthis Form 20-F, certain natural gas volumes have been converted to barrels ofoil equivalent (“BOEs’’) on the basis of six thousand cubic feet to onebarrel.  BOEs may be misleading,particularly if used in isolation.  ABOE conversion ratio of six Mcf to one bbl is based on an energy equivalencyconversion method primarily applicable at the burner tip and does not representequivalency at the well head.

 

Reservevolumes and values at January 1, 2004 are based on Baytex’s interest inits total proved and probable reserves prior to royalties as defined in NI51-101.  Reserve volumes and values forprevious years are based on “established” (proved plus 50% probable) reservesprior to deduction of royalties. Under those definitions, probable reserveswere discounted by an arbitrary risk factor of 50% in reporting established reserves.  Under NI 51-101 reserves definitions,estimates are prepared such that the full proved and probable reserves areestimated to be recoverable (proved plus probable reserves are effectively a“most likely case”). As such, the probable reserves now reported are already“risked”.

 

Baytexhas its reserves evaluated by independent engineers every year.  Baytex’s 2003 reserves were independentlyevaluated as at January 1, 2004 by Sproule Associates Limited (“Sproule”)for all its properties.

 

Thefollowing table shows our oil and natural gas proved reserves based on constantprices.  All of the oil and natural gasproved reserves are located in Canada. Oil reserves are expressed in millions of barrels and natural gasreserves in billions of cubic feet.

 
|                          |   | **January 1,  2004** |   | **December 31,** |   |
|-------------------------------|--------|---------------------------|--------|-----------------------|--------|
| **2002**                      |   | **2001**                  |
|                          |   | **Oil**                   |   | **Gas**               |   | **Oil** |   | **Gas** |   | **Oil** |   | **Gas** |   |
| Net proved reserves           |   | 56.6                      |   | 66.3                  |   | 95.5 |   | 120.1 |   | 95.1 |   | 105.8 |   |
| Net proved developed reserves |   | 39.4                      |   | 63.1                  |   | 61.4 |   | 105.1 |   | 59.1 |   | 96.6 |   |

 

**Long-term Supply Contract**

 

In October 2002, we entered into a long-termcrude oil supply contract with a third party that requires the delivery of upto 20,000 barrels per day of Lloydminster Blend crude oil at a price fixed at71% of NYMEX WTI oil price.  Thecontract is for an initial term of five years commencing January 1,2003.  The contract volumes increasedfrom 9,000 barrels per day in January 2003 to 20,000 barrels per day inOctober 2003 and thereafter.

 

**Production**

 

The following table summarizes Baytex’s workinginterest production during the periods indicated:

 
|                 |   | **Years  Ended December 31,** |   |
|----------------------|--------|------------------------------------|--------|
|                 |   | **2003**                           |   | **2002** |   | **2001** |   |
| Oil and NGL (bbls/d) |   | 26,184                             |   | 27,121 |   | 31,685 |   |
| Natural gas (mmcf/d) |   | 63.0                               |   | 72.6 |   | 70.8 |   |
| Total (BOE/d)        |   | 36,686                             |   | 39,214 |   | 43,488 |   |

 

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**Industry Conditions**

 

**General**

 

Theoil and natural gas industry is subject to extensive controls and regulationsgoverning its operations (including land tenure, exploration, development,production, refining, transportation and marketing) imposed by legislationenacted by various levels of government and with respect to pricing andtaxation of oil and natural gas by agreements among the governments of Canada,Alberta, British Columbia and Saskatchewan, all of which should be carefullyconsidered by investors in the oil and gas industry.  It is not expected that any of these controls or regulations willaffect the operations of the Company in a manner materially different than theywould affect other oil and gas companies of similar size.  All current legislation is a matter ofpublic record and the Company  unable topredict what additional legislation or amendments may be enacted.  Outlined below are some of the principalaspects of legislation, regulations and agreements governing the oil and gasindustry.

 

**Pricing and Marketing Oil andNatural Gas**

 

Theproducers of oil are entitled to negotiate sales contracts directly with oilpurchasers, with the result that the market determines the price of oil.  Such price depends in part on oil quality,prices of competing oils, distance to market, the value of refined products andthe supply/demand balance.  Oilexporters are also entitled to enter into export contracts with terms notexceeding one year in the case of light crude oil and two years in the case ofheavy crude oil, provided that an order approving such export has been obtainedfrom the National Energy Board of Canada (the “NEB”).  Any oil export to be made pursuant to a contract of longer duration(to a maximum of 25 years) requires an exporter to obtain an export licencefrom the NEB and the issuance of such licence requires the approval of theGovernor in Council.

 

Theprice of natural gas is determined by negotiation between buyers and sellers.Natural gas exported from Canada is subject to regulation by the NEB and theGovernment of Canada.  Exporters arefree to negotiate prices with purchasers, provided that the export contractsmust continue to meet certain other criteria prescribed by the NEB and theGovernment of Canada.  Natural gasexports for a term of less than 2 years or for a term of 2 to 20 years (inquantities of not more than 30,000 m3/day), must be made pursuant toan NEB order.  Any natural gas export tobe made pursuant to a contract of longer duration (to a maximum of 25 years) ora larger quantity requires an exporter to obtain an export licence from the NEBand the issuance of such licence requires the approval of the Governor inCouncil.

 

Thegovernments of Alberta, British Columbia and Saskatchewan also regulate thevolume of natural gas which may be removed from those provinces for consumptionelsewhere based on such factors as reserve ability, transportation arrangementsand market considerations.

 

Thelack of firm pipeline capacity continues to limit the ability to produce andmarket natural gas production although pipeline expansions are ongoing.  In addition, the prorationing of capacity onthe interprovincial pipeline systems continues to limit oil exports.

 

**The North American Free TradeAgreement**

 

TheNorth American Free Trade Agreement (“NAFTA”) among the governments of Canada,United States of America and Mexico became effective on January 1,1994.  NAFTA carries forward most of thematerial energy terms that are contained in the Canada United States Free TradeAgreement. Canada continues to remain free to determine whether exports ofenergy resources to the United States or Mexico will be allowed, provided thatany export restrictions do not: (i) reduce the proportion of energy resourcesexported relative to domestic use (based upon the proportion prevailing in themost recent 36 month period); (ii) impose an export

 

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pricehigher than the domestic price; or (iii) disrupt normal channels ofsupply.  All three countries areprohibited from imposing minimum export or import price requirements.

 

NAFTAcontemplates the reduction of Mexican restrictive trade practices in the energysector and prohibits discriminatory border restrictions and export taxes.  The agreement also contemplates clearerdisciplines on regulators to ensure fair implementation of any regulatorychanges and to minimize disruption of contractual arrangements, which isimportant for Canadian natural gas exports.

 

**Provincial Royalties and Incentives**

 

Inaddition to federal regulation, each province has legislation and regulationswhich govern land tenure, royalties, production rates, environmental protectionand other matters.  The royalty regimeis a significant factor in the profitability of crude oil, natural gas liquids,sulphur and natural gas production. Royalties payable on production from lands other than Crown lands aredetermined by negotiations between the mineral owner and the lessee, althoughproduction from such lands is subject to certain provincial taxes androyalties. Crown royalties are determined by governmental regulation and aregenerally calculated as a percentage of the value of the gross production.  The rate of royalties payable generallydepends in part on prescribed reference prices, well productivity, geographicallocation, field discovery date and the type or quality of the petroleum productproduced.

 

Fromtime to time the governments of the western Canadian provinces create incentiveprograms for exploration and development. Such programs often provide for royalty rate reductions, royaltyholidays and tax credits, and are generally introduced when commodity pricesare low.  The programs are designed toencourage exploration and development activity by improving earnings and cashflow within the industry.

 

Inthe Province of Alberta, a producer of oil or natural gas is entitled to acredit against the royalties payable to the Crown by virtue of the Albertaroyalty tax credit (“ARTC”) program. The ARTC rate is based on a price sensitive formula and the ARTC ratevaries between 75% at prices at and below $100 per m3 and 25% atprices at and above $210 per m3. The ARTC rate is applied to a maximum of $2,000,000 of Alberta Crownroyalties payable for each producer or associated group of producers.  Crown royalties on production from producingproperties acquired from a corporation claiming maximum entitlement to ARTCwill generally not be eligible for ARTC. The rate will be established quarterly based on the average “par price”,as determined by the Alberta Department of Energy for the previous quarterlyperiod.

 

Crudeoil and natural gas royalty programs for specific wells and royalty reductionsreduce the amount of Crown royalties paid by the Trust’s operating subsidiariesto the provincial governments.  Ingeneral, the ARTC program provides a rebate on Alberta Crown royalties paid inrespect of eligible producing properties.

 

**Land Tenure**

 

Crudeoil and natural gas located in the western provinces is owned predominantly bythe respective provincial governments. Provincial governments grant rights toexplore for and produce oil and natural gas pursuant to leases, licences andpermits for varying terms from two years and on conditions set forth inprovincial legislation including requirements to perform specific work or makepayments.  Oil and natural gas locatedin such provinces can also be privately owned and rights to explore for andproduce such oil and natural gas are granted by lease on such terms andconditions as may be negotiated.

 

**Environmental Regulation**

 

Theoil and natural gas industry is currently subject to environmental regulationspursuant to a variety of provincial and federal legislation.  Such legislation provides for restrictionsand prohibitions on the release or emission of various substances produced inassociation with certain oil and gas industry operations.  In addition, such legislation requires thatwell and facility sites be abandoned and reclaimed to the satisfaction of

 

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provincialauthorities.  Compliance with suchlegislation can require significant expenditures and a breach of suchrequirements may result in suspension or revocation of necessary licenses andauthorizations, civil liability for pollution damage and the imposition ofmaterial fines and penalties.

 

Environmentallegislation in the Province of Alberta has been consolidated into the AlbertaEnvironmental Protection and Enhancement Act (the “APEA”), which came intoforce on September 1, 1993.  TheAPEA imposes stricter environmental standards, requires more stringentcompliance, reporting and monitoring obligations and significantly increasespenalties.  The Trust is committed tomeeting its responsibilities to protect the environment wherever it operatesand anticipates making increased expenditures of both a capital and an expensenature as a result of the increasingly stringent laws relating to theprotection of the environment and will be taking such steps as required toensure compliance with the APEA and similar legislation in other jurisdictionsin which it operates.  The Companybelieves that it is in material compliance with applicable environmental lawsand regulations.  The Company alsobelieves that it is reasonably likely that the trend towards stricter standardsin environmental legislation and regulation will continue.

 

InDecember 2002 the Government of Canada ratified the Kyoto Protocol.  This protocol calls for Canada to reduce itsgreenhouse gas emissions to 6 percent below 1990 levels during the periodbetween 2008 and 2012.  The protocolwill 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 becomes legally binding, itis expected to affect the operation of all industries in Canada, including theoil and gas industry.  As details of theimplementation of this protocol have yet to be announced, the effect on the Companycannot be determined at this time.

 

**Item 5****: Operatingand Financial Review and Prospects**

 

**A. Results of Operations**

 

**Management’s Discussion andAnalysis of Financial Condition and Results of Operations**

 

Thefollowing discussion and analysis, dated June 29, 2004, should be read inconjunction with Baytex’ audited consolidated financial statements for thefiscal years ended December 31, 2003 and 2002.  Per barrel of oil equivalent (“boe”) amounts have been calculatedusing a conversion rate of six thousand cubic feet of natural gas to one barrelof oil.

 

The financial results of the Company for 2003 were impacted by theArrangement. The net loss for the year ended December 31, 2003 included $18.9million of costs related to the reorganization under the Arrangement. The lossfor the year also included $44.8 million of costs related to redemption andexchange of notes. These items were offset by a foreign exchange gain of $52.1million on our U.S. denominated debt.

 

Crude oil prices remained strong in 2003 as supply and demandfundamentals supported higher prices. Instability in the Middle East, growingdemand and low inventory levels kept average WTI at US$31.04/bbl. The oil pricereceived by Baytex averaged $26.36 per barrel for 2003. Natural gas pricesreceived averaged $6.07 per mcf for 2003. The overall higher prices offsetlower oil and gas production during 2003. Production was lower during 2003 ascertain properties were transferred to Crew under the Arrangement.

 

The strengthening Canadian dollar relative to the U.S. dollar impactedour net income, as revenues and realized commodity prices, referenced in U.S.dollars, were lower when translated to Canadian dollars. However, we benefit asour fixed-rate debt is denominated in U.S. dollars so this debt is reduced witha strengthening Canadian dollar.

 

Baytexevaluates performance based on net income and cash flow from operations.  Cash flow from operations is not a measurebased on generally accepted accounting principles, but is a financial termcommonly used in the oil and gas industry. It represents cash generated from operating activities before changes innon-cash working capital, deferred charges and other assets and deferredcredits.  Baytex considers it a keymeasure of performance as it demonstrates the ability of the Company to generatethe cash flow necessary to fund future distributions to unitholders and capitalinvestments.

 

**Results of Operations 2003 comparedto 2002**

 

**Production**                                    Baytex’s average production for fiscal 2003decreased by six percent to 36,686 boe per day from 39,214 boe per day forfiscal 2002.  This decrease was theresult of property dispositions that occurred at the end of the first quarterof 2003 and the transfer of the petroleum and natural gas assets to Crew underthe Plan of Arrangement effective September 2, 2003.

 

Lightoil production decreased 28 percent to 2,273 barrels per day during 2003 from3,154 barrels per day in 2002.  Heavyoil production during 2003 was 23,911 barrels per day, consistent withproduction of 23,967 barrels per day during fiscal 2002.  Natural gas production for 2003 decreased by13 percent to 63.0 million cubic feet per day compared to 72.6 million cubicfeet per day for the prior year.

 

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| **Production by Area**            |   | **Light Oil  and NGL** |   | **Heavy Oil** |   | **Natural  Gas** |   | **Barrels of  Oil  Equivalent** |   |
|-----------------------------------|--------|------------------------|--------|---------------|--------|------------------|--------|---------------------------------|--------|
|                              |   | **(bbls/d)**           |   | **(bbls/d)**  |   | **(mmcf/d)**     |   | **(boe/d)**                     |   |
| **2003**                          |   |                   |   |          |   |             |   |                            |   |
| Heavy Oil District                |   | —                 |   | 23,911        |   | 10.6             |   | 25,676                          |   |
| Conventional Oil and Gas District |   | 2,273                  |   | —        |   | 52.4             |   | 11,010                          |   |
| **Total Production**              |   | 2,273                  |   | 23,911        |   | 63.0             |   | 36,686                          |   |
|                              |   |                   |   |          |   |             |   |                            |   |
| **2002**                          |   |                   |   |          |   |             |   |                            |   |
| Heavy Oil District                |   | —                 |   | 23,967        |   | 10.5             |   | 25,710                          |   |
| Conventional Oil and Gas District |   | 3,154                  |   | —        |   | 62.1             |   | 13,504                          |   |
| **Total Production**              |   | 3,154                  |   | 23,967        |   | 72.6             |   | 39,214                          |   |

 

**Revenue****                                   **Petroleum and natural gas sales for 2003decreased by four percent to $351.4 million from $365.9 million for fiscal2002.  Benchmark WTI crude oil averagedUS$31.04 per barrel for 2003, representing a 19 percent increase over theUS$26.08 per barrel for 2002. Correspondingly, the Trust’s light oil and NGLs price increased to$39.04 per barrel from $33.86 per barrel in 2002.  The heavy oil price decreased five percent to $25.12 per barrelin 2003 from $26.39 per barrel in 2002, principally due to the increase inheavy oil differentials.  Natural gasprices were 54 percent higher in 2003, averaging $6.07 per thousand cubic feetcompared to $3.94 per thousand cubic feet during the previous year.  Overall, after accounting for financialderivative contracts, the Trust averaged $26.72 per boe for 2003, a 4 percentincrease from $25.56 per boe received in the prior year.  For the per-sales-unit calculations, heavyoil sales for 2003 were 650 barrels per day lower than the production for theyear due to inventory in transit under the Frontier supply agreement.

 

For2003, light oil revenue decreased 17 percent over 2002, as the 15 percentincrease in wellhead prices were offset by a 28 percent decrease inproduction.  Revenue from heavy oildecreased eight percent due to a five percent decrease in wellhead prices and athree percent decrease in sales volumes. Natural gas revenue increased 34 percent as the 13 percent productiondecreased was offset by a 54 percent increase in wellhead prices.

 
| **Gross Revenue Analysis** |   | **2003**         |   | **2002**       |   |
|----------------------------|--------|------------------|--------|----------------|--------|
|                       |   | **$  thousands** |   | **$/Unit (1)** |   | **$  thousands** |   | **$/Unit (1)** |   |
| Light oil                  |   | 32,393           |   | 39.04          |   | 38,985 |   | 33.86 |   |
| Heavy oil                  |   | 213,297          |   | 25.12          |   | 230,874 |   | 26.39 |   |
| Derivative contract loss   |   | (33,777          | )      | (3.62          | )      | (10,622 | ) | (1.07 | ) |
| Total oil revenue          |   | 211,913          |   | 22.74          |   | 259,237 |   | 26.19 |   |
|                       |   |             |   |           |   |   |   |   |   |
| Natural gas revenue        |   | 139,491          |   | 6.07           |   | 104,284 |   | 3.94 |   |
| Derivative contract gain   |   | —           |   | —         |   | 2,339 |   | 0.09 |   |
| Total natural gas revenue  |   | 139,491          |   | 6.07           |   | 106,623 |   | 4.03 |   |
|                       |   |             |   |           |   |   |   |   |   |
| Total revenue (boe @ 6:1)  |   | 351,404          |   | 26.72          |   | 365,860 |   | 25.56 |   |

 

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(1)Per-unit oil revenue is in $/bbl; per unit natural gas revenue is in $/mcf.

 

**Royalties****                                            **For the year ended December 31, 2003,royalties decreased eight percent to $54.2 million from $58.9 million last yearand were 15.4 percent of sales compared to 15.7 percent of sales in 2002.  A portion of the royalties paid during 2003were reimbursed by the Trust, resulting in a lower royalty rate.  Before the reimbursement by the Trust,royalties for 2003 were 17.8 percent of sales for light oil, 13.8 percent forheavy

 

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oiland 22.9 percent for natural gas.  Theserates compared to 16.7 percent, 13.9 percent and 19.5 percent, respectively,for 2002.

 

**Operating Expenses****                        **Operating expenses for the year 2003 increased14 percent to $86.0 million from $75.2 million for 2002.  This increase is attributable to thedisposition of properties with lower operating costs and a general increase infield operating costs.  Operatingexpenses were $6.54 per boe for 2003 compared to $5.26 per boe for the prioryear.  Operating expenses were $8.32 perbarrel of light oil, $7.34 per barrel of heavy oil and $0.73 per thousand cubicfeet of natural gas for 2003 versus $5.83, $5.99 and $0.61, respectively, for2002.

 

**General and Administrative Expenses****                                    **General and administrative expenses for 2003were $8.9 million, compared to $6.7 million a year ago.  On a sales-unit basis, these expensesincreased to $0.67 per boe from $0.47 per boe. In accordance with the full-cost accounting policy, $4.4 million ofexpenses were capitalized in 2003, compared with $6.7 million capitalized in2002.  The amount of capitalizedexpenses has been reduced due to lower exploration activity since the effectivedate of the Arrangement.

 

**Stock-basedCompensation****                          **Baytex accounts for compensation expensebased on the fair value of rights granted to its employees under the Trust’sunit-based compensation plan.  As theTrust is unable to determine the fair value of the rights granted, compensationexpense has been determined based on the intrinsic value of the rights at theexercise date or at the date of the consolidated financial statements forunexercised rights.  Compensationexpense of $0.22 million was recorded as compensation expense for all trustunit rights granted on or after January 1, 2003.

 

Compensationexpense was also calculated on the stock options outstanding prior to the Planof Arrangement.  Compensation expense of$0.52 million was recorded as compensation expense for all stock optionsgranted on or after January 1, 2003. All outstanding stock options were cancelled or exercised effectiveSeptember 2, 2003.

 

**Interest Expense**                           For 2003, interestexpenses on long-term debt were $23.5 million compared to $25.2 million for2002.  The decrease is due to theredemption of the senior secured term notes and the impact of the strongerCanadian dollar on U.S dollar based interest expenses.  Interest on intercompany notes for 2003 was$21.5 million.

 

**Costs on Redemption and Exchange of Notes  **On July 9, 2003, the Company completed an exchange offer relatedto its previously outstanding US$150 million 10.5 percent senior subordinatednotes due 2011 (the “Old Notes”).  TheCompany issued US$179.7 million of 9.625 percent senior subordinated notes due2010 in exchange for US$149.8 million of the Old Notes and incurred a non-cashloss of $40.0 million on the completion of this transaction, which wasrecognized in income.  Also recognizedin income is $4.7 million of costs on the redemption of the US$57 million senior7.23 percent secured notes.

 

**Depletion and Depreciation****                         **Depletion anddepreciation increased to $110.5 million for 2003 compared to $106.8 millionlast year.  On a sales-unit basis, theprovision for 2003 was $8.25 per boe compared to $7.46 per boe for 2002 due tothe revisions in proved reserves under the new standards of disclosure for oiland gas activities, NI 51-101, as mandated by the Canadian SecuritiesAdministrators for year-ends beginning with December 31, 2003.

 

The ceiling test was calculated at December 31,2003 using the proved reserves as determined under NI51-101 and at prices atyear-end.  No write-down was required atDecember 31, 2003 under this calculation.

 

**Site Restoration Costs****                    **Site restorationcosts for the year ended December 31, 2003 increased to $2.9 million from$2.8 million last year.  On a sales-unitbasis, the provision for 2003 was $0.22 per boe compared to $0.20 per boe for2002 due the changes in the proved reserves used in the calculation.

 

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**Foreign Exchange****                                             **Foreign exchangegain for 2003 was $52.1 million compared to $2.7 million in 2002.  The 2003 gain is based on the translation ofthe Company’s U.S. dollar denominated long-term debt at 0.7737 atDecember 31, 2003 compared to 0.6331 at December 31, 2002.  The 2002 gain is based on translation at0.6331 at December 31, 2002 compared to 0.6279 at December 31, 2001.

 

**Income Taxes**                                      Current taxexpenses were $9.7 million for 2003 compared to $9.7 million last year.  The 2003 current tax expense is comprised of$8.0 million of Saskatchewan Capital Tax and $1.7 million of Large CorporationTax compared to $8.1 million and $1.6 million, respectively, in 2002.

 

Thefiscal 2003 provision for future income taxes was a recovery of $11.5 millioncompared to $37.9 million for the prior year. The future income tax recovery for 2003 included a non-recurringadjustment resulting from a 0.5 percent decrease to the Alberta corporateincome tax rate and from the federal legislation introduced to change thetaxation of resource income.  Thefederal resource tax changes include a change in the federal income tax rate,deductibility of crown royalties and elimination of the resource allowance, tobe phased in over the next five years. These changes are considered substantially enacted for the purposes ofGAAP and the Company’s future income tax liability has been reducedaccordingly.

 

**Capital Expenditures.**   Exploration and development expenditures increased to $180.1 million for2003 compared to $136.3 million last year. Total capital expenditures for the last two years are summarized in thetable below.

 
| **($ thousands)**                 |   | **2003** |   | **2002** |   |
|-----------------------------------|--------|----------|--------|----------|--------|
| Land                              |   | $        | 14,138 |     | $      | 13,834 |   |
| Seismic                           |   | 5,436    |   | 8,183    |   |
| Drilling and completion           |   | 111,772  |   | 81,862   |   |
| Equipment                         |   | 42,365   |   | 24,507   |   |
| Other                             |   | 6,401    |   | 7,949    |   |
| Total exploration and development |   | 180,112  |   | 136,335  |   |
| Property acquisitions             |   | 6,644    |   | 45,713   |   |
| Property dispositions             |   | (137,493 | )      | (55,580  | )      |
| Net capital expenditures          |   | $        | 49,263 |     | $      | 126,468 |   |

 

**Results of Operations 2002 comparedto 2001**

 

**Production**                                    Baytex’s average production for fiscal 2002decreased by 10 percent to 39,214 barrels of oil equivalent per day from 43,488barrels of oil equivalent per day for fiscal 2001.  This decrease was the result of property dispositions thatoccurred in the fourth quarter of 2001 and the first quarter of 2002 along witha decrease in capital spending on heavy oil in the last half of 2001.

 

Lightoil production decreased 39 percent to 3,154 barrels per day during 2002 from5,152 barrels per day in 2001.  Heavyoil production during 2002 decreased by 10 percent to 23,967 barrels per dayfrom 26,533 barrels per day during fiscal 2001. Natural gas production for 2002increased by 2 percent to 72.6 million cubic feet per day compared to 70.8million 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)**                     |   |
| **2002**               |   |                           |   |          |   |             |   |                            |   |
| Heavy Oil District     |   | —                         |   | 23,967        |   | 10.5             |   | 25,710                          |   |
| Plains District        |   | 2,124                          |   | —        |   | 43.8             |   | 9,418                           |   |
| Northern District      |   | 1,030                          |   | —        |   | 18.3             |   | 4,086                           |   |
| **Total Production**   |   | 3,154                          |   | 23,967        |   | 72.6             |   | 39,214                          |   |
|                   |   |                           |   |          |   |             |   |                            |   |
| **2001**               |   |                           |   |          |   |             |   |                            |   |
| Heavy Oil District     |   | 368                            |   | 26,533        |   | 11.5             |   | 28,813                          |   |
| Plains District        |   | 3,721                          |   | —        |   | 35.5             |   | 9,192                           |   |
| Northern District      |   | 1,063                          |   | —        |   | 23.8             |   | 5,483                           |   |
| **Total Production**   |   | 5,152                          |   | 26,533        |   | 70.8             |   | 43,488                          |   |

 

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**Revenue****                              **Petroleum and natural gas sales for 2002increased by 11 percent to $365.9 million from $329.7 million for fiscal2001.  Benchmark WTI crude oil averagedUS$26.08 per barrel for 2002, representing a one percent increase over theUS$25.90 per barrel for 2001. Correspondingly, Baytex’s light oil and NGLs price increased to $33.86per barrel from $33.65 per barrel.  TheCompany’s heavy oil price increased 58 percent to $26.39 per barrel from $16.69per barrel, as heavy oil differentials decreased from 2001 with Baytex’s heavyoil receiving 66 percent of the Canadian par crude price during fiscal 2002compared to 43 percent in 2001.  Naturalgas prices were 11 percent lower in 2002 averaging $3.94 per thousand cubicfeet compared to $4.42 per thousand cubic feet during the previous year.  Overall, after accounting for financialderivative contracts, Baytex averaged $25.56 per barrel of oil equivalent for2002 production, a 23 percent increase from $20.77 per barrel of oil equivalentreceived in the prior year.

 

For2002, light oil revenue decreased 38 percent over 2001, as production decreased39 percent while wellhead prices were consistent.  Revenue from heavy oil increased 43 percent as the 10 percentdecreased in production was offset by the 58 percent increase in wellheadprices.  Natural gas revenue decreasednine percent as production increased two percent and wellhead prices declinedby 11 percent.

 
| **Gross Revenue Analysis** |   | **2002**  |   | **2001**   |   |
|----------------------------|--------|-----------|--------|------------|--------|
|                       |   | **$000s** |   | **$/Unit** |   | **$000s** |   | **$/Unit** |   |
| Oil Revenue (barrels)      |   |      |   |       |   |   |   |   |   |
| Light oil                  |   | 38,985    |   | 33.86      |   | 63,288 |   | 33.65 |   |
| Heavy oil                  |   | 230,874   |   | 26.39      |   | 161,681 |   | 16.69 |   |
| Derivative contract loss   |   | (10,622   | )      | (1.07      | )      | (9,513 | ) | (0.82 | ) |
| Total oil revenue          |   | 259,237   |   | 26.19      |   | 215,456 |   | 18.63 |   |
|                       |   |      |   |       |   |   |   |   |   |
| Natural gas revenue (mcf)  |   | 104,284   |   | 3.94       |   | 114,244 |   | 4.42 |   |
| Derivative contract gain   |   | 2,339     |   | 0.09       |   | — |   | — |   |
| Total natural gas revenue  |   | 106,623   |   | 4.03       |   | 114,244 |   | 4.42 |   |
|                       |   |      |   |       |   |   |   |   |   |
| Total 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 thesame period last year due to an increase in revenue and an increase in heavyoil royalty rates.  The overall royaltyrate for 2002 was 15.7 percent of sales compared to 17 percent of sales forfiscal 2001.  The decrease in the overallroyalty rate resulted from the sale of properties at the end of 2001 and in thefirst quarter of 2002 that carried a higher royalty burden.  In 2002, royalties were 16.7 percent ofsales 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 10percent to $75.2 million from $83.4 million during the previous year.  This decrease is attributable to a 10percent decrease in overall production. For 2002, operating expenses by product were $5.83 per barrel of lightoil, $5.99 per barrel of heavy oil and $0.61 per thousand cubic feet of naturalgas.  In comparison, operating expensesby product for 2001 were

 

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$6.82per barrel of light oil, $5.59 per barrel of heavy oil and $0.64 per thousandcubic feet of natural gas.  Overalloperating expenses were consistent on a unit basis at $5.26 per barrel of oilequivalent during 2002 and 2001.

 

**General and Administrative Expenses****                                    **General and administrative expenses, aftercapitalization, increased to $6.7 million for 2002 compared to $5.3 million for2001.  On a per unit of productionbasis, these expenses increased during 2002 to $0.47 per barrel of oilequivalent from $0.33 per barrel of oil equivalent in 2001.  This increase was due to increased stafflevels associated with the Company’s 2001 corporate acquisitions.  In accordance with the full cost accountingpolicy, $6.7 million of expenses were capitalized in 2002 compared to $5.3million in 2001.

 

**Interest Expense****                                           **For the year ended December 31, 2002,interest expenses decreased to $25.2 million from $32.9 million for the prioryear.  Average debt levels decreasedfrom $388.8 million in 2001 to $336.9 million in 2002.  Interest expense was further reduced byinterest rate swap agreements that the Company negotiated inDecember 2001.  These swaps weresettled 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 effectiveinterest rate of the senior secured notes from 7.23 percent to 5.7 percentuntil November 2004 and the senior subordinated notes form 10.5 percent to9.2 percent until February 2006.

 

**Depletion and Depreciation****                                  **Depletion and depreciation, before ceilingtest considerations, decreased to $106.8 million for 2002 compared to $132.9million for 2001. The decrease is due to lower production and the ceiling testwrite-down taken at year-end 2001.  On aunit of production basis, the provision for 2002 was $7.46 per barrel of oilequivalent compared to $8.37 per barrel of oil equivalent for last year.

 

Dueto wide heavy oil differentials at year-end 2001, the Company incurred a $131.3million ceiling test write-down (net of $103.2 million of future incometaxes).  This amount was recognized asadditional 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 propertydispositions. On a unit of production basis, the provision for 2002 was $0.20per barrel of oil equivalent compared to $0.25 per barrel of oil equivalent forthe previous year.

 

**Foreign Exchange****                                   **The foreign exchange gain for the year endedDecember 31, 2002 was $2.7 million compared to a loss of $16.3 million forthe 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 comparedto 0.6279 at December 31, 2001. The 2001 loss is based on the translationof the U.S. dollar denominated senior secured notes at 0.6279 atDecember 31, 2001 compared to 0.6660 at December 31, 2000 along withthe senior subordinated notes translated at 0.6279 at December 31, 2001compared to 0.6582 on February 13, 2001 when the notes were issued.

 

**Income Taxes****                                                           **Current tax expenses were $9.7 million for2002 compared to $7.1 million in 2001. The current tax expenses are comprised of $8.1 million of SaskatchewanCapital Tax and $1.6 million of Large Corporation Tax, compared to $6.1 millionand $1.0 million, respectively, for the prior year.  Saskatchewan Capital Tax has increased as higher commodity priceshave resulted in higher revenues earned in Saskatchewan.

 

Thefiscal 2002 provision for future income taxes was $38 million compared torecovery of $107.3 million for the prior year. The increase in future income taxes was the result of higher corporateearnings in 2002 due to increased commodity prices.  Future income taxes for 2001 included a $103.2 million recoveryassociated with the year-end ceiling test write-down.

 

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# **CapitalExpenditures**

Total exploration and development expenditures for 2002 were $136.3million, which is consistent with $135.9 million for 2001.  Overall net capital expenditures decreased66 percent to $126.5 million in 2002 from $375.9 million in 2001.  Two corporate acquisitions were completed inthe prior year, which accounted for $249.1 million of the 2001expenditures.

 
| **Capital Expenditures**          |   | **2002** |   | **2001** |   |
|-----------------------------------|--------|----------|--------|----------|--------|
| **($ thousands)**                 |   |     |   |     |   |
| Land                              |   | 13,834   |   | 11,494   |   |
| Seismic                           |   | 8,183    |   | 7,242    |   |
| Drilling and completions          |   | 81,862   |   | 71,928   |   |
| Equipment                         |   | 24,507   |   | 37,206   |   |
| Other                             |   | 7,949    |   | 8,019    |   |
| Total exploration and development |   | 136,335  |   | 135,889  |   |
| Corporate acquisitions            |   | —   |   | 249,152  |   |
| Property acquisitions             |   | 45,713   |   | 53,394   |   |
| Dispositions                      |   | (55,580  | )      | (62,582  | )      |
| Net capital expenditures          |   | 126,468  |   | 375,853  |   |

 

**Risk and Risk Management**

 

Theexploration for and the development, production and marketing of petroleum andnatural gas involves a wide range of business and financial risks, some ofwhich are beyond Baytex’s control. Included in these risks are the uncertainty of finding new reserves, thefluctuations of commodity prices, the volatile nature of interest and foreignexchange rates, and the possibility of changes to royalty, tax andenvironmental regulations.  Thepetroleum industry is highly competitive and Baytex competes with a number ofother companies, many of which have greater financial and operating resources.

 

Thebusiness risks facing Baytex are mitigated in a number of ways.  Geological, geophysical, engineering,environmental and financial analyses are performed on new explorationprospects, development projects and potential acquisitions to ensure a balancebetween risk and reward.  Baytex’sability to increase its production, revenues and cash flow depends on itssuccess not only in developing its existing properties but also in acquiring,exploring for and developing new reserves and production and managing thoseassets in an efficient manner.

 

Despitebest practice analysis being conducted on all projects, there are numerous uncertaintiesinherent in estimating quantities of petroleum and natural gas reserves,including future oil and natural gas prices, engineering data, projected futurerates of production and the timing of future expenditures.  The process of estimating petroleum andnatural gas reserves requires substantial judgment, resulting in imprecisedeterminations, particularly for new discoveries.  An independent engineering firm evaluates Baytex’s propertiesannually to determine a fair estimate of reserves.  The Reserves Evaluation Committee, consisting of qualifiedmembers of the Company’s Board, of the Board of Directors assists the Board intheir annual review of the reserve estimates.

 

Theprovision for depletion and depreciation in the financial statements and theceiling test are based on proved reserve estimates.  Any future significant revisions could result in a full-costaccounting write-down or material changes to the annual rate of depletion anddepreciation.

 

Thefinancial risks that Baytex is exposed to as part of the normal course of itsbusiness can be managed with various financial derivative instruments, inaddition to fixed-price physical delivery contracts.  The use of

 

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derivativeinstruments is governed under formal internal policies and subject to limitsestablished by the Board of Directors. Derivative instruments are not used for speculative or trading purposes.

 

Baytex’sfinancial results can be significantly affected by the prices received forpetroleum and natural gas production as commodity prices fluctuate in responseto changing market forces.  This pricingvolatility is expected to continue.  Asa result, Baytex has a risk management program that may be used to protect theprices of oil and natural gas on a portion of the total expectedproduction.  The objective is todecrease exposure to market volatility and ensure Baytex’s ability to financeits distributions and capital program. Baytex recognizes gains or losses onfinancial derivative contracts as oil and natural gas production revenue whenthe associated production occurs.

 

InOctober 2002, Baytex signed a five-year crude oil supply agreement with aU.S. based refining company.  Thisagreement calls for the delivery, beginning in January 2003, of up to20,000 Bbls/d of Lloyd Blend oil production at a fixed differential of 29percent of West Texas Intermediate price. This pricing arrangement effectively removes the additional pricing volatilityassociated with heavy oil on two-thirds of Baytex’s heavy oil production.  This contract forms part of Baytex’s riskmanagement program and should help to reduce the impact on Baytex’s cash flowfrom dramatic swings in commodity prices in the future.

 

Baytex’sfinancial results are also impacted by fluctuations in the exchange ratebetween the Canadian dollar and the US dollar. Crude oil and, to a large extent, natural gas prices are based onreference prices generally denominated in US dollars, while the majority ofexpenses are denominated in Canadian dollars. The exchange rate also impacts the valuation of the U.S. dollardenominated long-term debt.  The relatedforeign exchange gains and losses are included in net income.  There is no plan at this time to fix theexchange rate on any of Baytex’s long-term borrowings.

 

Baytexis exposed to changes in interest rates as the Company’s banking facilities arebased on the lenders’ prime lending rate and short-term Bankers’ Acceptancerates.

 

Baytex’scurrent position with respect to its financial derivative contracts is detailedin note 16 of the consolidated financial statements.

 

**CRITICAL ACCOUNTING POLICIES**

 

Thepreparation of the consolidated financial statements in accordance withgenerally accepted accounting principles requires management to make judgmentsand estimates that affect the financial results of Baytex.  These critical estimates are discussedbelow.

 

**Oil And Gas Accounting****                             **Baytex follows the full-cost accountingguideline to account for its petroleum and natural gas operations.  Under this method, all costs associated withthe exploration for and development of petroleum and natural gas reserves arecapitalized 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 estimatedproved petroleum and natural gas reserves. Unit-of-production calculations are also used in the determination ofthe site restoration expense.  By theirinclusion in the unit-of-production calculation, reserve estimates are asignificant component of the calculation of depletion and depreciation and siterestoration expense.

 

Independentengineers engaged by Baytex use all available geological, reservoir, andproduction 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 inassumptions based on reservoir performance, prices, economic conditions,government restrictions and other relevant factors.  If reserve estimates are revised downward, net income could beaffected by increased depletion and depreciation and site restoration expense.

 

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**Impairment of Petroleum and Natural Gas Assets**                     Companies that use the full-cost method ofaccounting for oil and natural gas operations are required to perform a ceilingtest each quarter that calculates a limit for the net carrying cost ofpetroleum and natural gas assets.  Theceiling test calculation utilizes and holds constant the prices and costs ineffect at the end of the period.  Anestimate is made of the ultimate recoverable amount from future net revenuesusing proved reserves and period end prices, plus the net costs of majordevelopment projects and unproved properties, less future removal and siterestoration costs, overhead, financing costs and income taxes.  The calculation of future net revenue in theceiling test can be significantly impacted by fluctuations in any of theseestimates.  An impairment loss isrecognized if the amount calculated under the ceiling test is less than thecarrying costs of Baytex’s petroleum and natural gas assets and can result in asignificant accounting loss for a particular period.

 

**Change in Accounting Policies and New Accounting Pronouncements**

 

In November 2002, the Canadian Institute of Chartered Accountants(CICA) amended its accounting guideline on hedging relationships, which wasoriginally issued in November 2001.  Theguideline addresses the identification, designation, documentation andeffectiveness of hedging transactions for the purposes of applying hedgeaccounting.  It also establishesconditions for applying or discontinuing hedge accounting.  Under the new guideline, hedgingtransactions must be documented and it must be demonstrated that the hedges aresufficiently effective to continue accrual accounting for positions hedged withderivatives.  The new guidline iseffective for fiscal years, beginning on or after July 1, 2003.  As of January 1, 2004, the Company hasrecorded as a deferred charge the unrealized loss of $10.1 million for themark-to-market value of the outstanding non-hedging financial derivatives.  This balance is being recognized over theterm of the previously designated hedged item.

 

Baytexhas elected to prospectively adopt amendments to CICA HandbookSection 3870, “Stock-based Compensation and Other Stock-based Payments”,pursuant to the transitional provisions contained therein.  Under this amended standard, Baytex isrequired to account for compensation expense based on the fair value of rightsgranted under its unit-based compensation plan.  As Baytex is unable to determine the fair value of the rights granted,compensation expense has been determined based on the intrinsic value of therights at the exercise date or at the date of the financial statements forunexercised rights.  Compensationexpense of $0.22 million was recorded as compensation expense for all trustunit rights granted on or after January 1, 2003, with a correspondingamount recorded as contributed surplus.

 

Theadoption of these amendments also impacted the stock options outstanding priorto the Plan of Arrangement. Compensation expense of $0.52 million was recorded as compensationexpense for all stock options granted on or after January 1, 2003, with acorresponding amount recorded as contributed surplus.  For stock options granted prior to January 1, 2003, the proforma earnings impact of related stock-based compensation expense is disclosedin note 10 of the consolidated financial statements.

 

InMarch 2003, the CICA issued Section 3110, “Asset RetirementObligations”.  Thissection requires recognition of a liability at discounted fair value forthe future abandonment and reclamation associated with the petroleum andnatural gas properties.  The fair valueof the liability is capitalized as part of the cost of the related asset andamortized to expense over its useful life. The liability accretes until the date of expected settlement of theretirement obligations.  The newstandard is effective for all fiscal years beginning on or afterJanuary 1, 2004.  The impact of theadoption of this standard is estimated to be an increase in asset retirementobligation on the balance sheet of $33 million at December 31, 2003.

 

InFebruary 2003, the CICA issued Accounting Guideline 14, “Disclosure ofGuarantees” (“AcG-14”). AcG-14 establishes the disclosures required forobligations under certain guarantees. The disclosure requirements are effective for interim and annual periodsbeginning on or after January 1, 2003 and have been made in note 17 of theconsolidated financial statements.

 

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In2003, the CICA issued Accounting Guideline 16, “Oil and Gas Accounting – FullCost” (“AcG-16”).  The guideline iseffective for fiscal years beginning on or after January 1, 2004.  The new guideline proposes amendments to theceiling test calculation applied by Baytex. The ceiling test was changed to a two-stage process which is to beperformed at least annually.  The firststage of the test is a recognition test which compares the undiscounted futurecash flow from proved reserves to the net book value of the petroleum andnatural gas assets to determine if the assets are impaired.  An impairment loss exists when the carryingamount of the petroleum and natural gas assets exceeds such undiscounted cashflow.  The second stage determines theamount of the impairment loss to be recorded. The impairment is measured as the amount by which the net book value ofthe petroleum and natural gas assets exceeds the future discounted cash flowfrom proved plus probable reserves.  Theadoption of this new guideline on January 1, 2004 is not anticipated tohave an impact on the financial results of Baytex.

 

OnNovember 10, 2003, the CICA issued a draft EIC (D37) on “Income Trusts -Exchangeable Units”. The EIC proposes that the retained interest of theexchangeable shareholders should be presented on the balance sheet as anon-controlling interest separate and distinct from unitholder’s equity. Thisdraft EIC is currently under review and was not enacted in final form as of thetime of release of Baytex’s consolidated financial statements.

 

InJune 2003 the CICA issued Accounting Guideline 15 “Consolidation ofVariable Interest Entities”, which deals with the consolidation of entitiesthat are subject to control on a basis other than ownership of votinginterests.  This guideline is effectivefor annual and interim periods beginning on or after November 1, 2004.Baytex has assessed that this new guideline is not applicable based on thecurrent structure of Baytex and therefore will have no impact on the financialstatements of Baytex.

 

**Recent Developments in U.S. Accounting**

 

In May 2003, the Financial Accounting StandardsBoard (FASB) issued Statement of Financial Accounting Standards No.150“Accounting for Certain Financial Instruments with Characteristics ofLiabilities and Equity”, which establishes standards for classification andmeasurement of certain financial instruments. The adoption of this accounting standard did not have a material impacton the Company.

 

In January 2003, the FASB issued InterpretationNo. 46 “Consolidation of Variable Interest Entities” (“FIN 46”).  FIN 46 provides criteria for identifyingvariable interest entities and for determining what entity, if any, should beincluded in consolidated financial statements. In December 2003, the FASB issued FIN 46(R) to clarify some of theprovisions of FIN 46 and to exempt certain entities from its requirements.  The adoption on January 1, 2004 of thisaccounting standard is not anticipated to have a material impact on theCompany.

 

In December 2003, the Securities and ExchangeCommission issued Staff Accounting Bulletin No. 104 “Revenue Recognition” (“SAB104”), which will rescind accounting guidance contained in Staff AccountingBulletin No. 101 related to multiple element revenue arrangements.  The changes noted in SAB 104 are notanticipated to have a material impact on the Company’s financial position,results of operations or cash flows.

 

**B. Liquidity and Capital Resources**

 

At December 31, 2003, total net debt (includingworking capital) was $737.0 million compared to $362.8 million atDecember 31, 2002.  The increase intotal debt at year-end 2003 compared to 2002 was the result of the notes issuedunder the Arrangement.

 

TheCompany’s debt structure consists of several components.  The first component is the senior creditfacilities.  On September 3, 2003, the Company entered into a new creditagreement with a syndicate of chartered banks. The credit facilities can be drawn in either Canadian or U.S. funds andbear interest at the agent bank’s prime lending rate, bankers’ acceptance ratesplus applicable margins or LIBOR rates plus applicable margins.  The facilities aggregating $165 million aresubject to semi-annual reviews beginning in November 2003 and are securedby a floating charge over all of the Company’s assets.  At December 31, 2003, there are noamounts outstanding under the bank credit facilities.

 

Thesecond component is the senior subordinated notes.  On February 12,2001, the Company issued US$150 million of senior subordinated notes (“OldNotes”) bearing interest at 10.5 percent payable semi-annually with principalrepayable on February 15, 2011. These notes are unsecured and are subordinate to the Company’s bankcredit facilities.  OnJuly 9, 2003, the Company completed an exchange offer related to its OldNotes.  The Company issued US$179.7million ($247.1 million) of 9.625 percent senior subordinated notes dueJuly 15, 2010 (“New Notes”) in exchange for US$149.8 million of the OldNotes and incurred a non-cash loss of $40.0 million on the completion of thistransaction, which was recognized in income. The New Notes are unsecured andare subordinate to the Company’s bank credit facilities.

 

TheCompany also has two related party notes outstanding.  On September 2,2003, the Company issued $527.4 million of unsecured, subordinated promissorynotes to the Trust.  The notes bearinterest at 12 percent payable monthly with principal repayable onSeptember 1, 2033.  These notes areunsecured and are

 

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subordinate to the Company’s bank credit facilitiesand senior subordinated notes.  Alsoduring 2003, the Company issued a total of $9.9 million of unsecured,subordinated promissory notes to Baytex ExchangeCo Ltd. (“ExchangeCo.”).  The notes bear interest at 12 percentpayable monthly with principal repayable on September 1, 2033.  These notes are unsecured and aresubordinate to the Company’s bank credit facilities and senior subordinatednotes.

 

Baytexbelieves that cash flow generated from its operations, together with existingcapacity under the bank credit facilities, will be sufficient to financecurrent operations and planned capital expenditures for the next year.  The timing of most of the capitalexpenditures is discretionary and there are no material long-term capitalexpenditure commitments.

 

**C. Research****andDevelopment, Patents and Licenses, etc.**

 

None

 

**D. Trend****Information**

 

SeeItem 4B and Item 5A

 

**E. Off Balance****SheetArrangements**

 

Baytexuses various financial derivative instruments, the fair values of which are notreflected on the consolidated balance sheet, to reduce exposure to commodityand currency fluctuations.  These risks,and Baytex’s risk management policy, are discussed in “Risk and RiskManagement”.  Baytex’s current positionwith respect to its financial derivative contracts is detailed in note 16 ofthe consolidated financial statements.

 

Baytexhas ongoing obligations related to abandonment and reclamation of well andfacility sites which have reached the end of their economic lives.  Programs to abandon and reclaim well andfacility sites are undertaken regularly in accordance with applicablelegislative requirements.

 

**F. Tabular****Disclosure ofContractual Obligations**

 

Baytexhas assumed various contractual obligations and commitments, as detailed in thetable below, in the normal course of operations and financing activities.  These obligations and commitments have beenconsidered when assessing the cash requirements in the above discussion offuture liquidity.

 
|                                       |   | **Payments  Due by Period** |   |                   |   |          |   |          |   |
|--------------------------------------------|--------|-----------------------------|--------|------------------------|--------|---------------|--------|---------------|--------|
| **Contractual Obligations  ($ thousands)** |   | **Total**                   |   | **Less than  1  year** |   | **1-3 years** |   | **4-5 years** |   | **After 5  years** |   |
| Long-Term Debt                             |   | 769,903                     |   | —                 |   | —        |   | —        |   | 769,903 |   |
| Operating Leases                           |   | 1,660                       |   | 1,328                  |   | 332           |   | —        |   | — |   |
| Transportation Agreements                  |   | 7,295                       |   | 3,192                  |   | 3,299         |   | 804           |   | — |   |
| Exchangeable shares                        |   | 42,243                      |   | —                 |   | —        |   | —        |   | 42,243 |   |
| Total Contractual Obligations              |   | 821,101                     |   | 4,520                  |   | 3,631         |   | 804           |   | 812,146 |   |

 

In October 2002, the Company entered into a long-term crude oil supplycontract with a third party that requires the delivery of up to 20,000 barrelsper day of LloydminsterBlend crude oil at a price fixed at 71% of NYMEX WTI oil price.  The contract is for an initial term of fiveyears commencing January 1, 2003.  Thecontract volumes increasedfrom 9,000 barrels per day in January 2003 to 20,000 barrels per day in October2003 and thereafter.

 

**G. Safe Harbour**

 

**Special Note Regarding ForwardLooking Statements - See Page 4**

 

Our annual interest obligationon long-term debt is $ 86.7 million.

 

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**Item 6****: Directors,Senior Management and Employees**

 

**A. Directors and Senior Management**

 

Thefollowing table sets forth the name and position of each of our directors andexecutive officers at December 31, 2003:

 
| **Name**            |   | **Age** |   | **Position Held**                                 |
|---------------------|--------|---------|--------|---------------------------------------------------|
| Raymond  T. Chan    |   | 48      |   | President,  Chief Executive Officer, Director     |
| Daniel  G. Belot    |   | 41      |   | Vice  President, Finance, Chief Financial Officer |
| Randal  J. Best     |   | 47      |   | Vice  President, Corporate Development            |
| Ralph  W. Gibson    |   | 46      |   | Vice  President, Marketing                        |
| Richard  W. Naden   |   | 44      |   | Vice  President, Engineering and Operations       |
| Shannon  M. Gangl   |   | 41      |   | Secretary                                         |
| Edward  Chwyl       |   | 60      |   | Director,  Chairman                               |
| John  A. Brussa     |   | 46      |   | Director                                          |
| W.A.  Blake Cassidy |   | 66      |   | Director                                          |
| Naveen  Dargan      |   | 46      |   | Director                                          |
| Dale  O. Shwed      |   | 45      |   | Director                                          |

 

Thereare no family relationships or other arrangements pursuant to which any personreferred to above was selected as a director or officer.

 

***Raymond T. Chan.*****   **Mr. Chan joined us as Senior Vice-President,Chief Financial Officer and a director of in October 1998.  Pursuant to the reorganization of BaytexEnergy Ltd. in September 2003, he was appointed President and ChiefExecutive Officer and a director.  Hebegan his career in the Canadian oil industry in 1981 and served as ChiefFinancial Officer of Gane Petroleum Corporation Ltd. and American EaglePetroleum Ltd. in the 1980’s.  In 1990,Mr. Chan joined Tarragon Oil and Gas Limited as its eighth employee and, in hisrole of Chief Financial Officer, helped build Tarragon into a senior producerwith 250 employees.  Tarragon was acquiredby Marathon Oil Company of Houston, Texas in the summer of 1998.  Mr. Chan graduated from the University ofSaskatchewan with a Bachelor of Commerce degree in 1977 and obtained hischartered accountant designation in 1979. Mr. Chan is also a director of C1 Energy Ltd. and Crew Energy Inc., bothof which are TSX listed oil and gas companies.

 

***Daniel G. Belot.*****   **Mr. Belot joined us as Vice President,Finance and Chief Financial Officer in September 2003.  From 2001 to 2003 Mr. Belot was Manager,Investor Relations for Pengrowth Energy Trust and prior thereto, he held theposition of Corporate and Investment Banker with Scotia Capital.  Mr. Belot holds a Bachelor degree ineconomics from the University of Calgary.

 

***Randal J. Best.*****   **Mr. Best joined us as Vice President,Corporate Development in September 2003. From 2000 to 2003, Mr. Best was Managing Director of Waterous & Co.in Calgary specializing in oil and gas property divestment and M&A advisory.Prior thereto, Mr. Best was President and CEO of Enercap Corporation, a privateinvestment company. Mr. Best holds a B.A.Sc. (Honors) degree in ChemicalEngineering from the University of Waterloo, Ontario and is a graduate of theIvey Executive Program, Richard Ivey School of Business, University of WesternOntario.

 

***Ralph G. Gibson.***   Mr. Gibson joined us as Vice-President, Marketing inSeptember 2001.  Prior to that Mr. Gibson was Vice-President, CrudeOil with Canpet Energy Group, a private crude oil and natural gas liquidsmarketing company from November 2000 to May 2001; Vice-President,Marketing with Ranger Oil Limited from September 1997 to July 2000; and Vice-President, Marketing with ELAN Energy Inc. fromNovember 1993 to September 1997.  Mr. Gibson began his careerwith Mobil Oil Canada in May 1980, holding various

 

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financeand marketing positions, most recently Manager, Crude Oil Sales &Supply.  Mr. Gibson graduated from the University of Saskatchewan with aBachelor of Commerce degree in 1980.

 

***Richard W. Naden.*****   **Mr. Naden joined us as Vice-President,Production in October 1997. Pursuant to the reorganization of Baytex Energy Ltd. inSeptember 2003, he was appointed Vice-President, Engineering andOperations.  Mr. Naden wasVice-President, Operations of Dorset Exploration Ltd. from November 1996until Dorset’s merger with us in 1997. From August 1996 to November 1996, Mr. Naden was Manager,Eastern District Production with Canadian Natural Resources Limited.  From April 1993 to August 1996,Mr. Naden was Manager, Operations and Manager, Exploitation Engineering ofSceptre Resources Limited prior to the completion of its plan of arrangementwith Canadian Natural Resources Limited. Mr. Naden graduated from the University of Calgary in 1981 with aBachelor of Science degree in mechanical engineering.

 

***Shannon M. Gangl.***  Ms.Gangl has been our corporate secretary since May 31, 2001.  She has been a partner at Burnet, Duckworth& Palmer LLP since January 1999.

 

***John A. Brussa.   ***Mr.Brussa has been one of our directors since October 1997.  He has been a partner at Burnet, Duckworth& Palmer LLP since February 1987 and specializes in the practice oftax matters.  Mr. Brussa serves on theboard of directors of Capital Energy Resources Ltd., Crew Energy Inc., CrispinEnergy Inc., Divestco Inc., E3 Energy Ltd. (formerly Mill City InternationalInc.),  Endev Energy Inc. (formerlyFlock Resources Ltd.), Energy Savings Income Fund, FET Resources Inc. (formerlyStorm Energy Inc.), Focus Energy Trust, Galleon Energy Inc., Grand PetroleumLtd., Harvest Operations Corp., High Point Resources Inc., Inter Pipeline Fund(formerly Koch Pipelines Canada, L.P.), NAV Energy Trust, Orleans ResourcesInc., Penn West Petroleum Ltd., Petrobank Energy and Resources Ltd., PilotEnergy Ltd., Progress Energy Ltd., Rider Resources Ltd., Rio Alto ResourcesInternational Inc., Southpoint Resources Ltd., and Strategic Energy Fund(formerly NCE Strategic Energy Fund).

 

***W. A. Blake Cassidy.*****   Mr. Cassidy has been one of our directorssince February 1994.  He is aretired banker after a 38 year career at the Canadian Imperial Bank ofCommerce.  He has extensive experiencein both energy banking and private banking.

 

***Edward Chwyl.  ***Mr.Chwyl joined us as a director in May 2003 and was elected Chairman of the Boardof Directors pursuant to the reorganization of Baytex Energy Ltd. inSeptember 2003.  Mr. Chwyl has over35 years of experience in the North American oil and gas industry starting withAtlantic Richfield Company in Dallas, Texas in 1968 upon graduating with hisMasters degree in Petroleum Engineering from the University of Alberta.  He returned to Canada in 1972 and heldpositions with increasing responsibilities with ARCO, Mesa, Canada NorthwestLand and its predecessor companies, and Sceptre Resources Limited.  He served as President and CEO of TarragonOil and Gas Limited from 1989 until 1998 when it was sold to Marathon OilCompany.  Mr. Chwyl has since served asa director of various energy companies in Canada.

 

***Naveen Dargan.***    Mr. Dargan joined us as adirector in September 2003.  Mr. Dargan became an independentbusinessman in June 2003, prior to which he worked in the investmentbanking business since 1983.  Between 2001 and 2003, Mr. Dargan was SeniorManaging Director and head of energy investment banking for Raymond James Ltd.,and between 1996 and 2001, Mr. Dargan was head of energy investment banking fortwo predecessor companies to Raymond James Ltd.  Between 1991 and 1996,Mr. Dargan worked for two major Canadian national investment banking firms, ineach case as the head of investment banking in the province of Alberta. Mr. Dargan holds a Bachelor of Arts (Honours) degree in mathematics andeconomics from Queen’s University, as well as an MBA from York University and aChartered Business Valuator designation (CBV).  In addition to Baytex, Mr.Dargan currently serves on the Board of Directors of CCS Inc., Defiant EnergyCorporation, Trinidad Drilling Ltd., and two privately held companies.

 

***Dale O. Shwed*****.  **In June 1993, Mr. Shwed founded BaytexEnergy Ltd. and served as President, Chief Executive Officer and a Directoruntil the reorganization in September 2003.  At that time, Mr. Shwed became

 

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President,Chief Executive Officer and a director of Crew Energy Inc. and continued in hiscapacity as director of Baytex Energy Ltd. Mr. Shwed has over 20 years of experience in the Canadian oil and gasindustry, working for companies such as Amoco Canada Petroleum CorporationLtd., Westmin Resources Ltd., Inverness Petroleum Ltd., and the Canadiandivision of Ceja Corporation.  He wasalso the founder of two oil and gas companies in the mid-1980’s, ELAD ResourcesCorporation and Tygas Industries Ltd. Mr. Shwed graduated from the University of Alberta with a Bachelor ofScience degree in geology in 1980.

 

**B. Compensation**

 

The following table provides a summary of compensationearned during the fiscal year ended December 31, 2003 by the current ChiefExecutive Officer, the former Chief Executive Officer and the four other mosthighly compensated executive officers or former executive officers of Baytex(collectively the “named executive officers”).

 

**SUMMARY COMPENSATION TABLE**

 
|                                                                 |   | **Annual  Compensation** |   | **Long-Term  Compensation** |   |                      |
|----------------------------------------------------------------------|--------|--------------------------|--------|-----------------------------|--------|---------------------------|
| **Name and Principal  Position**                                     |   | **Year**                 |   | **Salary ($)**              |   | **Bonus ($)  (5)**        |   | **Other  Annual Compensation  ($)(6)** |   | **Securities  Under Incentive  Rights/Options Granted   (#)** |   | **All Other  Compensation  ($)(7)** |
| Raymond T. Chan (1) President and Chief Executive Officer            |   | 2003  2002  2001         |   | 300,000  250,000  220,000   |   | 250,000  250,000  100,000 |   | Nil  Nil  Nil |   | 350,000 Rights  300,000 Options  180,000 Options |   | Nil  Nil  Nil |
| Dale O. Shwed (2)  Former President and Chief Executive Officer      |   | 2003  2002  2001         |   | 259,684  350,000  300,000   |   | 166,667  250,000  100,000 |   | Nil  Nil  Nil |   | 30,000 Rights  300,000 Options  330,000 Options |   | 1,886,026  Nil  Nil |
| Richard W. Naden  Vice President, Engineering & Operations       |   | 2003  2002  2001         |   | 196,667  180,000  175,000   |   | 75,000  45,000  20,000    |   | Nil  Nil  Nil |   | 175,000 Rights  45,000 Options  42,000 Options |   | Nil  Nil  Nil |
| John G. Leach (3)Former Vice President, Finance & Administration |   | 2003  2002  2001         |   | 114,641  160,000  150,000   |   | 130,000  45,000  20,000   |   | Nil  Nil  Nil |   | Nil  45,000 Options  27,000 Options |   | 500,589  Nil  Nil |
| Ralph W. Gibson  Vice President, Marketing                           |   | 2003  2002  2001         |   | 185,000  160,000  160,000   |   | 80,000  50,000  10,000    |   | Nil  Nil  Nil |   | 175,000 Rights  75,000 Options  10,000 Options |   | Nil  Nil  Nil |
| Garry J. Wasylycia (4)  Former Vice President,  Exploration     |   | 2003  2002  2001         |   | 144,988  205,000  200,000   |   | 33,000  50,000  25,000    |   | Nil  Nil  Nil |   | Nil  45,000 Options  51,000 Options |   | 639,120  Nil  Nil |

 

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Notes:

(1)                                  Mr. Chan becamethe President and Chief Executive Officer of Baytex in September 2003 uponcompletion of the Arrangement.  Priorthereto, he was the Senior Vice President and Chief Financial Officer.

(2)                                  Mr. Shwed ceasedto be the President and Chief Executive Officer of Baytex inSeptember 2003 upon completion of the Arrangement.  Mr. Shwed continues as a Director of Baytexsubsequent to the completion of the Arrangement.

(3)                                  Mr. Leach ceasedto be the Vice President, Finance & Administration of Baytex inSeptember 2003 upon completion of the Arrangement.

(4)                                  Mr. Wasylyciaceased to be the Vice President, Exploration of Baytex in September 2003upon completion of the Plan of Arrangement.

 

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(5)                                  Each of Baytex’sexecutive officers applied all 2002 bonuses to the acquisition of flow throughcommon shares of Baytex.  The commonshares were acquired at $7.86 per common share representing a premium of 6.2%over the closing price of the Baytex common shares on the TSX the day prior tothe approval of the bonuses by the Board of Directors.

(6)                                  Perquisites andother personal benefits do not exceed the lesser of $50,000 and 10% of thetotal annual salary and bonus for any of the named executive officers.

(7)                                  Payments pursuantto change of control provisions of employment agreements.

 

**Trust Unit Rights Incentive Plan**

** **

The Trust has established a Trust Unit RightsIncentive Plan for the directors, officers and employees of Baytex.  As at March 31, 2004, the Plan had5,800,000 Trust Units reserved for issuance thereunder.  As at March 31, 2004, there wereincentive rights outstanding to purchase 2,864,100 Trust Units.

 

The aggregate number of trust unit incentiverights granted to any single holder must not exceed 1% of the issued andoutstanding Trust Units (including the number of Trust Units which may beissued on the exchange of the Exchangeable Shares which may be converted intoTrust Units) (collectively, the “Total Units”) and the number of trust unitincentive rights issuable pursuant to the Trust Units Rights Incentive Plan tonon-management directors as a group is limited to a maximum of 1% of the TotalUnits.  The trust unit incentive rightsmay be exercised during a period (the “Exercise Period”) not exceeding five (5)years from the date upon which the trust unit incentive right was granted (the“Grant Date”), and any trust unit incentive right granted shall vest pursuantto vesting schedules determined by the Board in its sole discretion.  Subject to regulatory approval, the grantprice (“Grant Price”) per trust unit incentive right shall be equal to theclosing price of the Trust Units on the Toronto Stock Exchange on the lasttrading day immediately preceding the Grant Date.  The exercise price (“Exercise Price”) per trust unit incentiveright shall be calculated by deducting from the Grant Price the aggregate ofall monthly distributions, on a per Trust Unit basis made by the Trust afterthe Grant Date, provided the amount of such monthly distribution represents areturn of more than 0.833% of the Trust’s recorded cost of oil and natural gasproperties less accumulated depreciation and depletion and any future incometax liability associated with such oil and natural gas properties at the end ofeach month.

 

The following table sets forth individualgrants of trust unit incentive rights made to the named executive officersduring the fiscal year ended December 31, 2003.

 

**TRUST UNIT INCENTIVE RIGHTS GRANTS DURING THEYEAR ENDED DECEMBER 31, 2003**

 
| **Name**           |   | **Securities  Under  Trust Unit  Incentive Rights  Granted (#)** |   | **% of Total  Trust Unit  Incentive  Rights  Granted in  Fiscal Year** |   | **Exercise  Price  as at  December 31,  2003  ($/Trust  Unit)** |   | **Market  Value of  Securities Underlying  Trust Unit Incentive  Rights on the Date of  Grant  ($/Trust Unit)** |   | **Expiration  Date**   |
|--------------------|--------|------------------------------------------------------------------|--------|------------------------------------------------------------------------|--------|----------------------------------------------------------------------|--------|-----------------------------------------------------------------------------------------------------------------|--------|------------------------|
| Raymond T. Chan    |   | 350,000                                                          |   | 11.8%                                                                  |   | 10.23                                                                |   | 10.80                                                                                                           |   | September 9, 2008 |
| Dale O. Shwed      |   | 30,000                                                           |   | 1.0%                                                                   |   | 10.23                                                                |   | 10.80                                                                                                           |   | September 9, 2008 |
| Richard W. Naden   |   | 175,000                                                          |   | 5.9%                                                                   |   | 10.23                                                                |   | 10.80                                                                                                           |   | September 9, 2008 |
| John G. Leach      |   | Nil                                                              |   | N/A                                                                    |   | N/A                                                                  |   | N/A                                                                                                             |   | N/A                    |
| Ralph W. Gibson    |   | 175,000                                                          |   | 5.9%                                                                   |   | 10.23                                                                |   | 10.80                                                                                                           |   | September 9, 2008 |
| Garry J. Wasylycia |   | Nil                                                              |   | N/A                                                                    |   | N/A                                                                  |   | N/A                                                                                                             |   | N/A                    |

 

The Arrangement became effectiveSeptember 2, 2003.  Prior to thecompletion of the Arrangement, the named executive officers did not receivestock options grants during 2003 to acquire common shares of Baytex.

 

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Pursuant to the Arrangement, holders of stockoptions were entitled to participate in the Arrangement by exercising theirstock options and receiving the same consideration under the Arrangement as theother shareholders of Baytex.  All ofthe issued and outstanding stock options of Baytex, including those held by thenamed executive officers, were exercised prior to the Arrangement becomingeffective on September 2, 2003.

 

The following table sets forth information withrespect to the exercise of trust unit incentive rights during the fiscal year endedDecember 31, 2003 by the named executive officers and with respect to allincentive rights held by the named executive officers and still outstanding onDecember 31, 2003.

 

**AGGREGATEDTRUST UNIT INCENTIVE RIGHTS EXERCISED DURING THE YEAR ENDEDDECEMBER 31, 2003 AND YEAR-END TRUST UNIT INCENTIVE RIGHTS VALUES**

 
|               |   | **Securities  Acquired  on Exercise** |   | **Aggregate  Value  Realized** |   | **Unexercised  Trust Unit  Incentive Rights at  December 31, 2003  (#)** |   | **Value of  Unexercised In-the-  Money Trust Unit Incentive  Rights at December 31, 2003(1)  ($)** |   |
|--------------------|--------|---------------------------------------|--------|--------------------------------|--------|-------------------------------------------------------------------------------|--------|---------------------------------------------------------------------------------------------------------|--------|
| **Name**           |   | **(#)**                               |   | **($)**                        |   | **Vested**                                                                    |   | **Not Vested**                                                                                          |   | **Vested** |   | **Not Vested** |   |
| Raymond T. Chan    |   | Nil                                   |   | Nil                            |   | Nil                                                                           |   | 350,000                                                                                                 |   | Nil |   | 217,000 |   |
| Dale O. Shwed      |   | Nil                                   |   | Nil                            |   | Nil                                                                           |   | 30,000                                                                                                  |   | Nil |   | 18,600 |   |
| Richard W. Naden   |   | Nil                                   |   | Nil                            |   | Nil                                                                           |   | 175,000                                                                                                 |   | Nil |   | 108,500 |   |
| John G. Leach      |   | Nil                                   |   | Nil                            |   | Nil                                                                           |   | Nil                                                                                                     |   | Nil |   | Nil |   |
| Ralph W. Gibson    |   | Nil                                   |   | Nil                            |   | Nil                                                                           |   | 175,000                                                                                                 |   | Nil |   | 108,500 |   |
| Garry J. Wasylycia |   | Nil                                   |   | Nil                            |   | Nil                                                                           |   | Nil                                                                                                     |   | Nil |   | Nil |   |

 

----

Note:

 

(1)                                  Based on theDecember 31, 2003 closing price per Trust Unit on the TSX of $10.85.

 

The following table sets forth information withrespect to the exercise of stock options during the fiscal year endedDecember 31, 2003 by the named executive officers and with respect to allstock options held by the named executive officers and still outstanding onDecember 31, 2002.

 

**AGGREGATEDSTOCK OPTIONS EXERCISED DURING THE YEAR ENDEDDECEMBER 31, 2003 AND YEAR-END STOCK OPTION VALUES**

 
|               |   | **Securities  Acquired on  Exercise** |   | **Aggregate  Value  Realized** |   | **Unexercised  Stock  Options at December 31,  2003  (#)** |   | **Value of  Unexercised In-the-  Money Stock Options at  December 31, 2003  ($)** |   |
|--------------------|--------|---------------------------------------|--------|--------------------------------|--------|-----------------------------------------------------------------|--------|----------------------------------------------------------------------------------------|--------|
| **Name**           |   | **(#)**                               |   | **($)**                        |   | **Vested**                                                      |   | **Not Vested**                                                                         |   | **Vested** |   | **Not Vested** |   |
| Raymond T. Chan    |   | 830,000                               |   | 3,360,900                      |   | Nil                                                             |   | Nil                                                                                    |   | Nil |   | Nil |   |
| Dale O. Shwed      |   | 1,380,000                             |   | 5,842,900                      |   | Nil                                                             |   | Nil                                                                                    |   | Nil |   | Nil |   |
| Richard W. Naden   |   | 231,300                               |   | 832,198                        |   | Nil                                                             |   | Nil                                                                                    |   | Nil |   | Nil |   |
| John G. Leach      |   | 137,000                               |   | 554,810                        |   | Nil                                                             |   | Nil                                                                                    |   | Nil |   | Nil |   |
| Ralph W. Gibson    |   | 160,000                               |   | 807,250                        |   | Nil                                                             |   | Nil                                                                                    |   | Nil |   | Nil |   |
| Garry J. Wasylycia |   | 217,667                               |   | 875,098                        |   | Nil                                                             |   | Nil                                                                                    |   | Nil |   | Nil |   |

 

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**Retirement Plans**

** **

Baytex has no retirement plans for its employees.

 

**Employment Agreement and Change of Control Agreements**

** **

Baytex has entered into an employment agreement withMr. Chan which provides that in the event that the executive’s employment withBaytex is terminated without cause or upon a change of control of Baytex asdefined in the agreement, and subject to certain conditions being met, Mr. Chanmay receive a payment equal to 30 months salary, a bonus consideration andother employment benefits.  Baytex hasalso entered into change of control agreements with other officers.  The agreements provide that in the event ofa change of control of Baytex as defined, and subject to certain conditionsbeing met, the officers may receive payments equal to 24 months salary, a bonusconsideration and other employment benefits.

 

In addition, the employment agreements and change ofcontrol agreements allow for the acceleration of un-vested and unexercisedtrust unit incentive rights.  Theserights may be exercised for a period of 30 days following the date oftermination of employment.

 

**Compensation of Directors**

** **

Prior to the Arrangement, unrelated directors ofBaytex were paid an annual retainer of $10,000 plus a fee of $500 per meetingattended.  Subsequent to theArrangement, fees to unrelated directors, other than the Chairman, wereincreased to an annual retainer of $15,000 plus a fee of $1,000 per meetingattended. The Chairman receives an annual retainer of $25,000 plus a fee of$1,000 per meeting attended.  Directorfees are paid on a quarterly basis.

 

During 2003, the unrelated directors were also grantedtrust unit incentive rights as follows: Mr. Brussa - 30,000 trust unitincentive rights; Mr. Shwed - 30,000 trust unit incentive rights; Mr. Cassidy -30,000 trust unit incentive rights; Mr. Chwyl - 45,000 trust unit incentiverights; and Mr. Dargan - 30,000 trust unit incentive rights.

 

**Liability Insurance of Directors and Officers**

** **

Baytex maintains directors’ and officers’liability insurance coverage for losses to Baytex if it is required toreimburse directors and officers, where permitted, and for direct indemnity ofdirectors and officers where corporate reimbursement is not permitted bylaw.  The insurance protects Baytexagainst liability (including costs), subject to standard policy exclusions,which may be incurred by directors and/or officers acting in such capacity forBaytex.  All directors and officers ofBaytex are covered by the policy and the amount of insurance appliescollectively to all.  The cost of thisinsurance is $202,000 per annum.

 

**C. Board Practices**

 

Directorsare elected at each annual meeting to hold office for a term expiring at theclose of the next annual meeting of shareholders.  No specific term of office is applicable to executive officers;however, they are normally re-appointed annually.  The last annual meeting was held May 17, 2004.

 

Themembers of Baytex’s audit committee are Naveen Dargan, Dale O. Shwed and, W. A.Blake Cassidy.  The audit committee,consisting of a majority of outside directors, reviews the ConsolidatedFinancial Statements, assessing the accounting principles, risks, adequacy andinternal effectiveness of internal controls and recommends the ConsolidatedFinancial Statements to the Board for approval.  The audit committee alsomeets with management and external auditors to discuss internal controls andsignificant accounting and reporting issues as well as recommending theengagement or reappointment of the Company’s external auditors.

 

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Thecompensation committee is comprised of Edward Chwyl, John A. Brussa and NaveenDargan, all of whom are independent, non-employee directors of the Company. During 2003, no such member was a current or former officer or employeeof the Company or any of its subsidiaries.  The compensation committee ofthe board of directors is responsible for, among other matters, reviewing theperformance objectives and compensation package for the President and ChiefExecutive Officer, recommending compensation and benefits packages for theCompany’s leadership team and reviewing and approving fees paid to members ofthe board of directors.

 

**D. Employees**

 

Asat December 31, 2003, Baytex employed 95 head office employees and 17****field office employees.  None of our employees are represented by aunion.  We do not have a significantnumber of temporary employees.

 

**E. Share Ownership**

 

AtApril 12, 2004, the Trust owned the common share of Baytex.  The following table contains informationprovided to us by our shareholders with respect to beneficial ownership of ourexchangeable shares:

 
|          |   | **Exchangeable  Shares Beneficially  Owned** |   |
|---------------|--------|----------------------------------------------|--------|
| **Name**      |   | **Number**                                   |   | **%** |   |
| Dale O. Shwed |   | 605,129                                      |   | 16.2 |   |

 

**Item 7****. MajorShareholders and Related Party Transactions**

 

**A. Major Shareholders**

 

Thefollowing table sets for the information, as of April 12, 2004, regardingbeneficial ownership of the common shares and exchangeable shares.

 
| **Title of Class** |   | **Identity  of Group** |   | **Amount  Owned** |   | **Percent of  Class** |   |
|--------------------|--------|------------------------|--------|-------------------|--------|-----------------------|--------|
| Common             |   | Baytex Energy Trust    |   | 1                 |   | 100                   |   |
| Exchangeable       |   | Officers and Directors |   | 605,129           |   | 16.2                  |   |

 

Thevoting rights attached to each class of share are as described below.

 

Therehas been no change in beneficial ownership during the past three years otherthan that brought about by the Arrangement.

 

**B. Related Party Transactions**

 

Related party transactions entered into by theCompany in the last 3 years that are currently in effect are as follows:

 

On September 2, 2003, the Company issued $527.4million of unsecured, subordinated promissory notes to the Trust.  The notes bear interest at 12 percentpayable monthly with principal repayable on September 1, 2033.  These notes are unsecured and aresubordinate to the Company’s bank credit facilities and senior subordinatednotes.

 

During 2003, the Company issued a total of $9.9million of unsecured, subordinated promissory notes to ExchangeCo.  The notes bear interest at 12 percentpayable monthly with principal repayable on September 1,

 

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2033.  Thesenotes are unsecured and are subordinate to the Company’s bank credit facilitiesand senior subordinated notes.

 

OnSeptember 2, 2003, Baytex completed the Arrangement whereby holders ofcommon shares of Baytex elected or were deemed to have elected to receiveeither Trust Units of the Trust or Exchangeable Shares of Baytex for theircommon shares on the basis of one Trust Unit or Exchangeable Share,respectively, for each common share held. Coincident with the Arrangement becomingeffective, certain of Baytex’s exploration assets were acquired by Crew, andthe common shares of Crew were distributed to the former holders of Baytexcommon shares on the basis of one-third of a common share of Crew for each suchshare held.

 

**C. Interests of Experts and Counsel**

 

NotApplicable

 

**Item 8****. FinancialInformation**

 

**A. Consolidated FinancialStatements and Other Financial Information**

 

SeeItem 17.

 

**B. Significant Changes**

 

None

 

**Item 9****. The Offerand Listing**

 

**A. Offer and Listing Details**

 

**Price Range of Common Stock and TradingMarkets**

 

On September 2, 2003the business of Baytex was reorganized. In conjunction with this reorganization, the shareholders of Baytex.common stock received one trust unit for each share of common stock held or non-registeredexchangeable shares convertible into an equal number of trust units.  Subsequent to this reorganization, Baytexbecame a subsidiary of the Trust.  Thecommon shares of Baytex are not listed on a stock exchange subsequent to thereorganization.  The last day of tradingon the Toronto Stock Exchange for Baytex was September 5, 2003.

 
|     |   |               |   | **High** |   | **Low** |   |
|----------|--------|--------------------|--------|----------|--------|---------|--------|
| **1999** |   |               |   | 11.30    |   | 2.90    |   |
| **2000** |   |               |   | 16.70    |   | 8.25    |   |
| **2001** |   | **First Quarter**  |   | 14.84    |   | 9.00    |   |
|     |   | **Second Quarter** |   | 13.55    |   | 9.60    |   |
|     |   | **Third Quarter**  |   | 11.50    |   | 4.64    |   |
|     |   | **Fourth Quarter** |   | 5.25     |   | 3.00    |   |
| **2002** |   | **First Quarter**  |   | 6.89     |   | 3.95    |   |
|     |   | **Second Quarter** |   | 8.45     |   | 6.35    |   |
|     |   | **Third Quarter**  |   | 8.40     |   | 5.65    |   |
|     |   | **Fourth Quarter** |   | 8.92     |   | 6.65    |   |
| **2003** |   | **January**        |   | 9.24     |   | 8.10    |   |
|     |   | **February**       |   | 9.70     |   | 8.50    |   |
|     |   | **March**          |   | 10.20    |   | 8.75    |   |
|     |   | **April**          |   | 10.65    |   | 8.75    |   |
|     |   | **May**            |   | 11.10    |   | 9.82    |   |
|     |   | **June**           |   | 12.03    |   | 10.75   |   |
|     |   | **July**           |   | 11.90    |   | 11.30   |   |
|     |   | **August**         |   | 12.74    |   | 11.91   |   |
|     |   | **September**      |   | 12.40    |   | 12.01   |   |

 

40

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**B. Plan ofDistribution**

 

Not Applicable

 

**C. Markets**

 

Not Applicable

 

**D. Selling Shareholders**

 

Not Applicable

 

**E. Dilution**

 

Not Applicable

 

**F. Expensesof the Issue**

 

Not Applicable

 

**Item 10. Additional Information**

 

**A. ShareCapital**

 

**Common Shares**

 

The Company is authorized toissue an unlimited number of common shares. Each Baytex common share entitles its holder to receive notice of and toattend all meetings of the shareholders of Baytex and to one vote at suchmeetings. The holders of common shares will be, at the discretion of the Boardof Directors of Baytex and subject to applicable legal restrictions, andsubject to certain preferences of holders of Exchangeable Shares, entitled toreceive any dividends declared by the Board of Directors on the common sharesto the exclusion of the holders of Exchangeable Shares, subject to the provisothat no dividends shall be paid on the common shares unless all declareddividends on the outstanding Exchangeable Shares have been paid in full. Theholders of common shares are entitled to share equally in any distribution ofthe assets of Baytex upon the liquidation, dissolution, bankruptcy orwinding-up of Baytex or other distribution of its assets among its shareholdersfor the purpose of winding-up its affairs. Such participation is subject to therights, privileges, restrictions and conditions attaching to the ExchangeableShares and any other shares having priority over the common shares.  At December 31, 2003, the common shareof Baytex is owned by the Trust.

 

**Exchangeable Shares**

 

The Company is authorized toissue an unlimited number of exchangeable shares.  The exchangeable shares can be converted (at the option of theholder) into Trust Units at any time up to September 2, 2013.  Up to 1.9 million exchangeable shares may beredeemed annually by the Company for either cash or the issue of TrustUnits.  The number of trust units issuedupon conversion is based upon the exchange ratio in effect at the conversiondate.  The exchange ratio is calculatedmonthly based on the cash distribution paid divided by the

 

41

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weighted average trust unit price of the five-day trading period endingon the record date.  The exchange ratioat December 31, 2003 was 1.04530 Trust Units per exchangeable share.  Cash distributions are not paid on theexchangeable shares.  The exchangeableshares are not publicly traded.

 

The following is a summarydescription of the material provisions of the Exchangeable Shares and therelated ancillary and indirect rights of holders of Exchangeable Shares underthe terms of the Voting and Exchange Trust Agreement and the Support Agreement.

 

Each Exchangeable Share haseconomic rights (including the right to have the Exchange Ratio adjusted toaccount for distributions paid to unitholders) and voting attributes (throughthe benefit of the Special Voting Units granted to the Voting and ExchangeTrust Agreement Trustee, as defined below) equivalent to those of the TrustUnits into which they are exchangeable from time to time. In addition, holdersof Exchangeable Shares have the right to receive Trust Units at any time inexchange for their Exchangeable Shares, on the basis of the Exchange Ratio ineffect at the time of the exchange. Fractional Trust Units will not bedelivered on any exchange of Exchangeable Shares. In the event that theExchange Ratio in effect at the time of an exchange would otherwise entitle aholder of Exchangeable Shares to a fractional Trust Unit, the number of TrustUnits to be delivered are rounded down to the nearest whole number of TrustUnits.  Holders of Exchangeable Shareswill not receive cash distributions from the Trust or Baytex.  Rather, the Exchange Ratio will be adjustedto account for distributions paid to unitholders.

 

***Ranking***

 

The Exchangeable Shares rankrateably with shares of any other series of exchangeable shares of Baytex andprior to any common shares and any other shares ranking junior to theExchangeable Shares with respect to the payment of dividends, if any, that havebeen declared and the distribution of assets in the event of the liquidation,dissolution or winding-up of Baytex.

 

***Dividends***

 

Holders of ExchangeableShares are entitled to receive cash dividends if, as and when declared by theBoard of Directors of Baytex. Baytex anticipates that it may from time to timedeclare dividends on the Exchangeable Shares up to but not exceeding any cashdistributions on the Trust Units into which such Exchangeable Shares areexchangeable. In the event that any such dividends are paid, the Exchange Ratiowill be correspondingly reduced to reflect such dividends.

 

***Certain Restrictions***

 

Baytex will not, withoutobtaining the approval of the holders of the Exchangeable Shares as set forthbelow under the subheading “*Amendment andApproval*”:

 

•                  pay any dividend on the commonshares or any other shares ranking junior to the common shares, other thanstock dividends payable in common shares or any other shares ranking junior tothe Exchangeable Shares;

 

•                  redeem, purchase or make anycapital distribution in respect of the common shares of Baytex or any othershares ranking junior to the Exchangeable Shares;

 

•                  redeem or purchase any othershares of Baytex ranking equally with the Exchangeable Shares with respect tothe payment of dividends or on any liquidation distribution; or

 

•                  issue any shares, other thanExchangeable Shares or common shares, which rank superior to the ExchangeableShares with respect to the payment of dividends or on any liquidationdistribution.

 

42

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The above restrictions shallnot apply if all declared dividends on the outstanding Exchangeable Shares havebeen paid in full.

 

***Liquidation or Insolvency of Baytex***

 

In the event of theliquidation, dissolution or winding-up of Baytex or any other proposed distributionof the assets of Baytex among its shareholders for the purpose of winding upits affairs, a holder of Exchangeable Shares will be entitled to receive fromBaytex, in respect of each such Exchangeable Share, that number of Trust Unitsequal to the Exchange Ratio as at the effective date of such event.

 

Upon the occurrence of suchan event, the Trust and ExchangeCo will each have the overriding right topurchase all but not less than all of the Exchangeable Shares then outstanding(other than Exchangeable Shares held by the Trust or any subsidiary of theTrust) at a purchase price per Exchangeable Share to be satisfied by theissuance or delivery, as the case may be, of that number of Trust Units equalto the Exchange Ratio at such time and, upon the exercise of this right, theholders thereof will be obligated to sell such Exchangeable Shares to the Trustor ExchangeCo, as applicable. This right may be exercised by either the Trustor ExchangeCo.

 

***Automatic Exchange Right on Liquidation of the Trust***

 

The Voting and ExchangeTrust Agreement provides that in the event of a Trust liquidation event, asdescribed below, the Trust or ExchangeCo will be deemed to have purchased alloutstanding Exchangeable Shares and each holder of Exchangeable Shares will bedeemed to have sold their Exchangeable Shares immediately prior to such Trustliquidation event at a purchase price per Exchangeable Share to be satisfied bythe issuance or delivery, as the case may be, of that number of Trust Unitsequal to the Exchange Ratio at such time. “Trust liquidation event” means:

 

•                                          any determination by theTrust to institute voluntary liquidation, dissolution or winding-up proceedingsin respect of the Trust or to effect any other distribution of assets of theTrust among the unitholders for the purpose of winding up its affairs; or

 

•                                          the earlier of, the Trust’sreceiving notice of and the Trust’s otherwise becoming aware of, any threatenedor instituted claim, suit, petition or other proceedings with respect to theinvoluntary liquidation, dissolution or winding up of the Trust or to effectany other distribution of assets of the Trust among the unitholders for thepurpose of winding up its affairs in each case where the Trust has failed tocontest in good faith such proceeding within 30 days of becoming aware thereof.

 

***Retraction of Exchangeable Shares by Holders and Retraction Call Right***

 

Subject to the RetractionCall Right of the Trust and ExchangeCo as defined below, a holder ofExchangeable Shares will be entitled at any time to require Baytex to redeemany or all of the Exchangeable Shares held by such holder for a retractionprice (the “Retraction Price”) per Exchangeable Share equal to the value ofthat number of Trust Units equal to the Exchange Ratio as at the date ofredemption (the “Retraction Date”), to be satisfied by the delivery of suchnumber of Trust Units. Fractional Trust Units will not be delivered. Any amountpayable on account of the Retraction Price that includes a fractional TrustUnit will be rounded down to the nearest whole number of Trust Units. Holdersof the Exchangeable Shares may request redemption by presenting to Baytex orthe transfer agent for the Exchangeable Shares a certificate or certificatesrepresenting the number of Exchangeable Shares the holder desires to haveredeemed, together with a duly executed retraction request and such otherdocuments as may be reasonably required to effect the redemption of theExchangeable Shares. The redemption will become effective on the Retraction Date,which will be three Business Days after the date on which Baytex or thetransfer agent receives the retraction notice.

 

When a holder requestsBaytex to redeem the Exchangeable Shares, the Trust and ExchangeCo will have anoverriding right (the “Retraction Call Right”) to purchase on the RetractionDate all but not less than all of the Exchangeable Shares that the holder hasrequested Baytex to redeem at a purchase price per Exchangeable

 

43

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Share equal to the Retraction Price, to be satisfied by the delivery ofthat number of Trust Units equal to the Exchange Ratio at such time. At thetime of a Retraction Request by a holder of Exchangeable Shares, Baytex willimmediately notify the Trust and ExchangeCo. The Trust or ExchangeCo must thenadvise Baytex within two business days as to whether the Retraction Call Rightwill be exercised. A holder may revoke his or her Retraction Request at anytime prior to the close of business on the last business day immediatelypreceding the Retraction Date, in which case the holder’s Exchangeable Shareswill neither be purchased by the Trust or ExchangeCo nor be redeemed by Baytex.If the holder does not revoke his or her Retraction Request, the ExchangeableShares that the holder has requested Baytex to redeem will on the RetractionDate be purchased by the Trust or ExchangeCo or redeemed by Baytex, as the casemay be, in each case at a purchase price per Exchangeable Share equal to theRetraction Price. In addition, a holder of Exchangeable Shares may elect toinstruct the Voting and Exchange Trust Agreement Trustee, as defined below, toexercise the optional exchange right (the “Optional Exchange Right”) to requirethe Trust or ExchangeCo to acquire such holder’s Exchangeable Shares incircumstances where neither the Trust nor ExchangeCo have exercised theRetraction Call Right. See “*Voting andExchange Trust Agreement - Optional Exchange Right*”.

 

The Retraction Call Rightmay be exercised by either the Trust or ExchangeCo.  If, as a result of solvency provisions of applicable law, Baytexis not permitted to redeem all Exchangeable Shares tendered by a retractingholder, Baytex will redeem only those Exchangeable Shares tendered by theholder as would not be contrary to such provisions of applicable law. Theholder of any Exchangeable Shares not redeemed by Baytex will be deemed to haverequired the Trust to purchase such unretracted Exchangeable Shares in exchangefor Trust Units on the Retraction Date pursuant to the Optional Exchange Right.See “*Voting and Exchange Trust Agreement -Optional Exchange Right*”.

 

***Redemption of Exchangeable Shares***

 

Subject to applicable lawand the Redemption Call Right of the Trust and ExchangeCo, Baytex:

 

will, on the tenthanniversary of the Effective Date, subject to extension of such date by theBoard of Directors of Baytex (the “Automatic Redemption Date”), redeem all butnot less than all of the then outstanding Exchangeable Shares for a redemptionprice per Exchangeable Share equal to the value of that number of Trust Unitsequal to the Exchange Ratio as at the last Business Day prior to thatRedemption Date (as that term is defined below) (the “Redemption Price”), to besatisfied by the delivery of such number of Trust Units;

 

may, on the secondanniversary of the Effective Date (the “Optional Redemption Date”), redeem allbut not less than all outstanding Exchangeable Shares for the Redemption Priceper Exchangeable Share at the last Business Day prior to that Redemption Date(as that term is defined below), to be satisfied by the delivery of TrustUnits;

 

may, on any date that is within the first 90 days of any calendar yearcommencing in 2004 (the “Annual Redemption Date”), redeem up that number ofExchangeable Shares equal to 40% of the Exchangeable Shares outstanding on theEffective Date for the Redemption Price per Exchangeable Shareat the last Business Day prior to that Redemption Date (as that term is definedbelow), to be satisfied by the delivery of Trust Units; and

 

may, at any time when theaggregate number of issued and outstanding Exchangeable Shares is less than 1million (other than Exchangeable Shares held by the Trust and its subsidiariesand as such shares may be adjusted from time to time) (the “De MinimusRedemption Date” and, collectively with the Automatic Redemption Date, optionalRedemption Date and Annual Redemption Date, a “Redemption Date”), redeem allbut not less than all of the then outstanding Exchangeable Shares for theRedemption Price per Exchangeable Share (unless contested in good faith by theTrust).

 

Baytex will, at least 90days prior to any Redemption Date, provide the registered holders of theExchangeable Shares with written notice of the prospective redemption of theExchangeable Shares by Baytex.

 

44

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The Trust and ExchangeCohave the right (the “Redemption Call Right”), notwithstanding a proposedredemption of the Exchangeable Shares by Baytex on the applicable RedemptionDate, pursuant to the Exchangeable Share Provisions, to purchase on anyRedemption Date all but not less than all of the Exchangeable Shares thenoutstanding (other than Exchangeable Shares held by the Trust or itssubsidiaries) in exchange for the Redemption Price per Exchangeable Share and,upon the exercise of the Redemption Call Right, the holders of all of the thenoutstanding Exchangeable Shares will be obliged to sell all such shares to theTrust or ExchangeCo, as applicable. If either the Trust or ExchangeCo exercisesthe Redemption Call Right, then Baytex’s right to redeem the ExchangeableShares on the applicable Redemption Date will terminate. The Redemption CallRight may be exercised by either the Trust or ExchangeCo.

 

***Voting Rights***

 

Except as required byapplicable law, the holders of the Exchangeable Shares are not entitled as suchto receive notice of or attend any meeting of the shareholders of Baytex or tovote at any such meeting. Holders of Exchangeable Shares have the notice andvoting rights respecting meetings of the Trust that are provided in the Votingand Exchange Trust Agreement.  See “*Voting and Exchange Trust Agreement - Voting Rights*”.

 

***Amendment and Approval***

 

The rights, privileges,restrictions and conditions attaching to the Exchangeable Shares may be changedonly with the approval of the holders thereof. Any such approval or any otherapproval or consent to be given by the holders of the Exchangeable Shares willbe sufficiently given if given in accordance with applicable law and subject toa minimum requirement that such approval or consent be evidenced by aresolution passed by not less than two-thirds of the votes cast thereon (otherthan shares beneficially owned by the Trust, or any of its subsidiaries andother affiliates) at a meeting of the holders of the Exchangeable Shares dulycalled and held at which holders of at least 10% of the then outstandingExchangeable Shares are present in person or represented by proxy. In the eventthat no such quorum is present at such meeting within one-half hour after thetime appointed therefor, then the meeting will be adjourned to such place andtime (not less than ten days later) as may be determined at the originalmeeting and the holders of Exchangeable Shares present in person or representedby proxy at the adjourned meeting will constitute a quorum thereat and maytransact the business for which the meeting was originally called. At theadjourned meeting, a resolution passed by the affirmative vote of not less thantwo-thirds of the votes cast thereon (other than shares beneficially owned bythe Trust or any of its subsidiaries and other affiliates) will constitute theapproval or consent of the holders of the Exchangeable Shares.

 

***Actions by the Trust Under the Support Agreement and the Voting andExchange Trust Agreement***

 

Under the Exchangeable ShareProvisions, Baytex has agreed to take all such actions and do all such thingsas are necessary or advisable to perform and comply with its obligations under,and to ensure the performance and compliance by the Trust and ExchangeCo withtheir obligations under, the Support Agreement and the Voting and ExchangeTrust Agreement.

 

***Non-Resident and Tax-Exempt Holders***

 

The obligation of Baytex,the Trust or ExchangeCo to deliver Trust Units to a Non-Resident holder in respectof the exchange of such holder’s Exchangeable Shares may be satisfied bydelivering such Trust Units to the transfer agent who shall sell such TrustUnits on the stock exchange on which they are listed and deliver the proceedsof sale to the Non-Resident holder.

 

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**VOTING AND EXCHANGE TRUSTAGREEMENT**

** **

***VotingRights***

*** ***

Inaccordance with the Voting and Exchange Trust Agreement, the Trust has issuedone (1) special voting right (“Special Voting Right”) to Valiant Trust Company,the Voting and Exchange Trust Agreement trustee (the “Trustee”), for thebenefit of the holders (other than the Trust and ExchangeCo) of theExchangeable Shares. The Special Voting Right carries a number of votes,exercisable at any meeting at which Trust unitholders are entitled to vote,equal to one vote for each Exchangeable Share outstanding. With respect to anywritten consent sought from the Trust unitholders, each vote attached to theSpecial Voting Right will be exercisable in the same manner as set forth above.

 

Eachholder of an Exchangeable Share on the record date for any meeting at whichTrust unitholders are entitled to vote will be entitled to instruct the Trusteeto exercise that number of votes attached to the Special Voting Right whichrelate to the Exchangeable Shares held by such holder. The Trustee willexercise each vote attached to the Special Voting Right only as directed by therelevant holder and, in the absence of instructions from a holder as to voting,will not exercise such votes.

 

TheTrustee is required to send to the holders of the Exchangeable Shares thenotice of each meeting at which the Trust unitholders are entitled to vote,together with the related meeting materials and a statement as to the manner inwhich the holder may instruct the Trustee to exercise the votes attaching tothe Special Voting Right, at the same time as the Trust sends such notice andmaterials to the Trust unitholders. The Trustee is also required to send to theholders copies of all information statements, interim and annual financialstatements, reports and other materials sent by the Trust to the Trustunitholders at the same time as such materials are sent to the Trustunitholders. To the extent such materials are provided to the Trustee by theTrust, the Trustee will also send to the holders all materials sent by thirdparties to Trust unitholders, including dissident proxy circulars and tenderand exchange offer circulars, as soon as possible after such materials are firstsent to Trust unitholders.

 

Allrights of a holder of Exchangeable Shares to exercise votes attached to theSpecial Voting Right will cease upon the exchange of all such holder’sExchangeable Shares for Trust Units. With the exception of administrative changesfor the purpose of adding covenants for the protection of the holders of theExchangeable Shares, making necessary amendments or curing ambiguities orclerical errors (in each case provided that the Board of Directors ofExchangeCo and Baytex are of the opinion that such amendments are notprejudicial to the interests of the holders of the Exchangeable Shares), theVoting and Exchange Trust Agreement may not be amended without the approval ofthe holders of the Exchangeable Shares.

 

***OptionalExchange Right***

*** ***

Uponthe occurrence and during the continuance of:

(a)                                  an insolvency event;or

 

(b)                                 circumstances inwhich the Trust or ExchangeCo may exercise a Retraction Call Right, but electnot to exercise such Retraction Call Right,

 

aholder of Exchangeable Shares will be entitled to instruct the Trustee toexercise the Optional Exchange Right with respect to any or all of theExchangeable Shares held by such holder, thereby requiring the Trust orExchangeCo to purchase such Exchangeable Shares from the holder. Immediatelyupon the occurrence of (i) an insolvency event, (ii) any event which will, withthe passage of time or the giving of notice, become an insolvency event, or(iii) the election by the Trust and ExchangeCo not to exercise a RetractionCall Right which is then exercisable by the Trust and ExchangeCo, Baytex, theTrust or ExchangeCo will give notice thereof to the Trustee. As soon aspracticable thereafter, the Trustee will then notify each affected holder of

 

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Exchangeable Shares (who has not already provided instructionsrespecting the exercise of the Optional Exchange Right) of such event orpotential event and will advise such holder of its rights with respect to theOptional Exchange Right.

 

Thepurchase price payable by the Trust or ExchangeCo for each Exchangeable Shareto be purchased under the Optional Exchange Right will be satisfied by theissuance of that number of Trust Units equal to the Exchange Ratio as at thelast business day prior to the day of closing of the purchase and sale of suchExchangeable Share under the Exchange Right (the “Exchange Price”).

 

If,as a result of solvency provisions of applicable law, Baytex is unable toredeem all of a holder’s Exchangeable Shares which such holder is entitled tohave redeemed in accordance with the Exchangeable Share provisions, the holderwill be deemed to have exercised the Optional Exchange Right with respect tothe unredeemed Exchangeable Shares and the Trust or ExchangeCo will be requiredto purchase such shares from the holder in the manner set forth above.

 

**B. Memorandum and Articles of Association**

 

TheCompany was incorporated in Canada under the *Business Corporations Act*(Alberta)on June 3, 1993.  On August 5,1993, the Company filed Articles of Amendment to delete the private companyrestrictions.  On October 13, 1993,Articles of Amendment were filed to amend the Company’s capital structure tocreate Class A Shares and Class B Non-Voting Shares.  On October 21, 1997, the Company  filed Articles of Amalgamation to amalgamate with its wholly-ownedsubsidiary, Dorset Exploration Ltd.  OnMay 28, 1999, the Company filed Articles of Amendment to eliminate the Class BShares and to change the designation of the Class A Shares in the share capitalof the Company from “Class A Shares” to “common shares”.  On January 1, 2002, the Company filedArticles of Amalgamation to amalgamate with its wholly-owned subsidiaries, OGYPetroleums Ltd. and Triumph Energy Corporation.  On September 2, 2003, the Company was amalgamated withBaytex Acquisition Corp. pursuant to the Arrangement.

 

TheArticles of the Company place no restrictions on businesses the Company maycarry on.

 

TheArticles of the Company and By-Law No. 1 of the Company may be viewed atthe Company’s registered office which is 1400, 350 – 7th AvenueS.W., Calgary, Alberta T2P 3N9.

 

**Directors**

 

Directorsneed not hold shares in the Company to qualify and be appointed as a directorof the Company.  The Articles of theCompany provide that the minimum number of directors of the Company shall be 3and the maximum number of directors of the Company shall be 11.

 

Pursuantto the *Business Corporations Act*(Alberta), except in certain prescribed circumstances the directors of theCompany are required to disclose to the board of the directors of the Companyany personal interest that they may have in any material contract prior to theapproval of such contract and are required to abstain from voting as a directorfor the approval of such contract. Directors are permitted to vote on their owncompensation.  Material creditarrangements with lenders must be approved by ordinary resolution of the boardof directors.

 

Everydirector of the Company is entitled to be indemnified out of the assets of theCompany against all costs, charges and expenses, including any amount paid tosettle an action or satisfy a judgment, reasonably incurred by him in respectof any civil, criminal or administrative action or proceeding to which he ismade a party by reason of being or having been a director of the Company.

 

TheCompany has imposed no mandatory retirement age for its Directors.

 

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**Shareholders Rights**

 

TheCompany is authorized to issue an unlimited number of common shares and anunlimited number of exchangeable shares.

 

Theholders of any common shares are entitled to dividends if, as and when declaredby the directors, to one vote per share at meetings of the holders of commonshares of the Company and, upon liquidation, to receive such assets of theCompany as are distributable to the holders of the common shares.

 

Exceptas required by applicable law, the holders of the Exchangeable Shares are notentitled as such to receive notice of or attend any meeting of the shareholdersof the Company or to vote at any such meeting. See Item 10 – ExchangeableShares.

 

Fundamentalamendments to the rights of the shareholders of the Company can only beeffected by alteration of the Articles of the Company, which requires a specialresolution of the shareholders of the Company. There are no limitations on the rights to own securities of the Companyother than pursuant to the *Investment CanadaAct* (Canada) described elsewhere in this Form 20-F.

 

**Shareholders Meetings**

 

Therequirements to hold meetings of the shareholders of Company are described bythe *Business Corporations Act*(Alberta) and By-Law No. 1 of the Company and the Articles of theCompany.  Shareholders’ meetings may beheld at any place within the Province of Alberta or at any of the followingcities: Vancouver, British Columbia; Victoria, British Columbia; Winnipeg,Manitoba; Toronto, Ontario; Ottawa, Ontario; Montreal, Quebec; or Halifax, NovaScotia.  The time and place ofshareholders meetings is determined by a resolution of the board of directors.

 

Incertain circumstances, and subject to the provisions of the *Business Corporations Act* (Alberta),shareholders may requisition a meeting of the shareholders without a resolutionof the board of directors of the Company.

 

Thecalling of shareholder meetings is also subject to securities legislation inCanada, which prescribes the process by which the Company must send proxymaterials to its shareholders.  Undersuch securities legislation, proxy materials will generally be mailed toshareholders not less than 21 days before the date of the shareholders meeting.

 

Theproxy materials relating to any shareholders meeting will include a notice ofthe meeting setting out the time and place of the meeting and the nature of thebusiness to be transacted at the meeting, a form of proxy and management proxycircular containing, together with certain other prescribed information,sufficient description of the matters to be considered at the meeting such thatthe shareholder can form a reasoned judgment concerning such matters.

 

**Change of Control**

 

Neitherthe Articles nor By-Laws of the Company restrict the transfer of shares. Therefore, any change of control of the Company or merger, acquisition orcorporate restructuring involving the Company would only be subject togenerally applicable laws.

 

**C. MaterialContracts**

 

**NOTES**

** **

Pursuantto the Arrangement, Notes were issued to the Trust in return for TrustUnits.  The Notes are unsecured, payableon demand and bear interest from the date of issue at an interest rate equal to12% per annum, payable monthly.  Baytexis permitted to make payments against the principal amount of the Notesoutstanding from time to time without notice or bonus.  Unless the Note is called, Baytex is not requiredto make any payment in respect of principal until December 31, 2033,subject to extension in the limited 

 

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circumstancesprovided in the Note Indenture. Principal and interest on the Notes are payable in lawful money ofCanada directly to the holders of Notes. The Trust is the holder of all of the issued and outstanding Notes.  The Notes are unsecured debt obligations ofBaytex and rank *pari passu* withall other unsecured indebtedness of Baytex, but subordinate to all secureddebt.

 

**NPI AGREEMENT**

 

Coincidentwith the Arrangement becoming effective, Baytex and the Trust entered into aNet Profits Intersts Agreement, pursuant to which Baytex granted and set overto the Trust the right to receive certain payments (the “NPI”) on petroleum andnatural gas properties held by Baytex.

 

Pursuant tothe terms of the NPI Agreement, the Trust is entitled to a payment from Baytexfor each month equal to the amount by which ninety-nine percent of the grossproceeds from the sale of production attributable to the properties for suchmonth (the “NPI Revenues”) exceed ninety-nine percent of certain deductiblecosts for such period.  Baytex mayacquire and fund additional properties from residual revenues, borrowings orfrom its working capital.

 

If Baytexwishes to dispose of any properties which will result in proceeds in excess ofa threshold amount, the Board of Directors of Baytex shall approve suchdisposition; however, if the asset value (calculated in accordance with theterms of the NPI Agreement) of any interests included in such disposition isgreater than a threshold percentage of the asset value of all the Property Interestsheld by Baytex, such disposition must be approved by a Special Resolution ofthe unitholders.  The term of the NPIAgreement will be for so long as there are petroleum and natural gas rights towhich the NPI applies.

 

**D. Exchange Controls**

 

TheInvestment Canada Act generally prohibits implementation of a reviewableinvestment by an individual,government or agency thereof, corporation, partnership, trust or joint venturethat is not a “Canadian” as defined in the Investment Canada Act (a“non-Canadian”), unless after review, the minister responsible for theInvestment Canada Act is satisfied that the investment is likely to be of netbenefit to Canada.  An investment incommon shares of the Company by a non-Canadian (other than a “WTO investor” asdefined in the Investment Canada Act) would be reviewable under the InvestmentCanada Act if it was an investment to acquire direct control of the Company andthe value of the assets of the Company was $5,000,000 or more.

 

With regard toan investment in common shares of the Company by a WTO Investor, it would bereviewable under the Investment Canada Act if it was an investment to acquiredirect control of the Company and the value of the assets of the Company equalsor exceeds a specified amount (the “Review Threshold”), which is

 

49

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revised everyyear.  The Review Threshold is $237million for investments completed in 2004 and is indexed as of the first ofJanuary every year.

 

A non-Canadian, whether a WTO Investor or otherwise,would acquire control of the Company for the purposes of the Investment CanadaAct if he acquired a majority of the common shares of the Company.  The acquisition of less than a majority butone-third or more of the common shares of the Company would be presumed to bean acquisition of control of the Company unless it could be established theCompany was not controlled in fact by the acquirer through the ownership ofcommon shares.

 

Certain transactions in relation to the common sharesof the Company would be exempt from the Investment Act, including:

 

•                  an acquisition of common shares ofthe Company by a person in the ordinary course of that person’s business as atrader or dealer in securities;

 

•                  an acquisition of control of the Companyin connection with the realization of a security interest granted for a loan orother financial assistance and not for any purpose related to the provision ofthe Investment Canada Act; and

 

•                  an acquisition of control of theCompany by reason of an amalgamation, merger, consolidation or corporatereorganization following which the ultimate direct or indirect control in factof the Company, though the ownership of voting interests, remains unchanged.

 

The Company’s ability to declare and pay dividendsis governed by the covenants in the indentures governing its Senior SecuredNotes and in the documentation relating to its credit facilities.

 

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**E. Taxation**

 

The followingparagraphs set forth material Canadian federal income tax considerations withthe purchase, ownership and disposition of the senior secured notes.  The discussion is restricted tonon-residents of Canada who are residents of the United States and who holdsuch senior secured notes as capital property.   The tax considerations set forth below are based upon theprovisions of the *Income Tax Act* (Canada) (the “ITA”), and on the Conventionbetween Canada and the United States of America with Respect to Taxes on Incomeand on Capital, as well as regulations, rulings, judicial decisions andadministrative practices now in effect in Canada.

 

***Tax Consequences for Non-Resident Holders***

*** ***

A “Non-Resident Holder” of initial notes or exchange notes issomeone who, for the purposes of the ITAat all relevant times, is not, and is not deemed to be, resident in Canada,does not use or hold and is not deemed to use or hold the senior secured notesin carrying on a business in Canada, deals at arm’s length with Baytex, is notan authorized foreign bank and is not an insurer that carries on an insurancebusiness in Canada or elsewhere.

 

Pursuant to the ITA, interest paid or credited or deemed to be paidor credited by Baytex on the senior secured notes, to a Non-Resident Holderwill be exempt from Canadian withholding tax. No other taxes on income (including taxable capital gains) will bepayable pursuant to the ITA by a Non-Resident Holder in respect of theacquisition, ownership or disposition of the initial notes or exchange notesincluding exchange of the exchange notes for the initial notes.

 

**F. Dividends and Paying Agents**

 

Not Applicable

 

**G. Statement by Experts**

 

Not Applicable

 

51

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**H. Documents on Display**

 

We filereports and other information with the Securities Exchange Commission (the“SEC”).  You may read and copy anyreports, statements or other information on file at the SEC’s public referenceroom at 450 Fifth Street, NW, Washington, D.C. 20549.  You can request copies ofthose documents upon payment of a duplicating fee to the SEC.  You may also review a copy of thosedocuments at the SEC’s regional offices in New York, New York.  Please call the SEC at 1-800-SEC-0330 forfurther information on the operation of the public reference rooms.  You can review our SEC filings by accessingthe EDGAR system through the SEC’s Internet site at www.sec.gov.

 

You may alsoaccess our disclosure documents and any reports, statements or otherinformation that we file with the Canadian provincial securities commissions orother similar regulatory authorities through the Internet on the CanadianSystem for Electronic Document Analysis and Retrieval, which is commonly knownby the acronym SEDAR, and which may be accessed at www.sedar.com.

 

In addition, you may request a copy of any ofthese filings, including the documents incorporated by reference in this annualreport, at no cost, by writing or telephoning us at the following address ortelephone number:

 

Baytex Energy Ltd.

Suite 2200, Bow Valley Square II

205 - 5th Avenue S.W.

Calgary, Alberta, Canada T2P 2V7

Telephone: (403) 269-4282

Attention: Investor Relations

 

This document contains summaries of the termsof certain agreements that we believe to be accurate in all materialrespects.  However, we refer you to the actualagreements for complete information relating to those agreements.  All summaries are qualified in theirentirety by this reference.  We willmake copies of those documents available to you upon your request to us.

 

**I. Subsidiary Information**

 

Not Applicable

 

**Item 11. Quantitative andQualitative Disclosures About Market Risk**

 

We are exposed to all of the normal risks inherent within the oil andgas sector, including commodity price risk, foreign-currency rate risk,interest rate risk and credit risk. We manage our operations in a mannerintended to minimize our exposure, as described the section in Item 5entitled “Risk and Risk Management”.

 

**Credit Risk**

 

Credit risk is the risk of loss resulting from non-performance ofcontractual obligations by a customer or joint venture partner.  A substantial portion of our accountsreceivable are with customers in the energy industry and are subject to normalindustry credit risk.  We assess thefinancial strength of our customers and joint venture partners through regularcredit reviews in order to minimize the risk of non-payment.

 

**Foreign Exchange Risk**

 

Baytex’s financial results are impacted by fluctuations in the exchangerate between the Canadian dollar and the U.S. dollar.  Crude oil and, to a large extent, natural gas prices are based onreference prices generally denominated in U.S. dollars, while the majority ofour expenses are denominated in Canadian dollars.  The

 

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exchange rate also impacts the valuation of our U.S. dollar denominatedlong-term debt.  Changes to the exchangerate between U.S. and Canadian dollars can adversely affect us.  When the value of the U.S. dollar increases,we receive higher revenue and when the value of the U.S. dollar declines, wereceive lower revenue on the same amount of production sold at the sameprices.  When the value of the U.S.dollar increases, our U.S. increases and we incur a foreign exchange loss.  When the value of the U.S. dollar declines,our U.S. dollar denominated long-term debt decreases and we have a foreignexchange gain.  A change of $0.01 in theU.S. to CDN dollar would impact Baytex’s income by approximately $4,790,000 andits cash flow by $3,730,000.

 

**Commodity Price Risk**

 

Our financial condition, results of operations and capital resourcesare highly dependent upon the prevailing market prices of oil and naturalgas.  These commodity prices are subjectto wide fluctuations and market uncertainties due to a variety of factors thatare beyond our control.  Factorsinfluencing oil and natural gas prices include the level of global demand forcrude oil, the foreign supply of oil and natural gas, the establishment of andcompliance with production quotas by oil exporting countries, weatherconditions which determine the demand for natural gas, the price andavailability of alternative fuels and overall economic conditions. It isimpossible to predict future oil and natural gas prices with any degree ofcertainty. Sustained weakness in oil and natural gas prices may adverselyaffect our financial condition and results of operations, and may also reducethe amount of oil and natural gas reserves that we can produce economically.Any reduction in our oil and natural gas reserves, including reductions due toprice fluctuations, can have an adverse affect on our ability to obtain capitalfor our development activities. Similarly, any improvements in oil and natural gas prices can have afavorable impact on our financial condition, results of operations and capital resources.If the WTI oil price were to change by US$1.00 per bbl, the impact on Baytex’sincome would be approximately $830,000 and the impact on Baytex’s cash flowwould be approximately $1,300,000. If natural gas prices were to change byUS$0.50 per mcf, the impact on Baytex’s income would be approximately$6,100,000 and the impact on cash flow would be approximately $9,900,000.

 

We periodically use hedges with respect to a portion of our oil andnatural gas production to mitigate our exposure to price changes. While the useof these derivative arrangements limits the downside risk of price declines,such use may also limit any benefits which may be derived from price increases.

 

**Interest Rate Risk**

 

Interest rate risk exists principally with respect to our indebtednessthat bears interest at floating rates. At December 31, 2003, we had no outstanding debt at floatingrates.  If interest rate were to changeby on full percentage point, the net impact on Baytex’s income would beapproximately $190,000 and the net impact on Baytex’s cash flow would beapproximately $310,000.

 

Summarized below are Baytex’s sensitivities to various risks, based onits 2003 operations:

 
|                                                  |   | **Estimated  2003 impact on:** |      |
|-------------------------------------------------------|--------|--------------------------------|-----------|
| **Sensitivities**                                     |   | **Net  Income**                |      | **Cash  Flow** |   |
| Crude oil – US$1.00/bbl change in WTI            |   | $                              | 830,000   |   | $ | 1,300,000 |   |
|                                                  |   |                           |      |   |   |
| Natural Gas – US$0.50/mcf change                 |   | $                              | 6,100,000 |   | $ | 9,900,000 |   |
|                                                  |   |                           |      |   |   |
| Foreign Exchange - $0.01 change in U.S. to CDN dollar |   | $                              | 4,791,000 |   | $ | 3,730,000 |   |
|                                                  |   |                           |      |   |   |
| Interest rate – 1% change                        |   | $                              | 190,000   |   | $ | 310,000 |   |

 

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**Item 12. Description of SecuritiesOther than Equity Securities**

 

Not Applicable

 

**PART II**

 

**Item 13.****Defaults, Dividend Arrearages and Delinquencies**

 

**A. Indebtedness**

 

There has been nomaterial default in the payment or principal or interest on our outstandingindebtedness since the date of filing our last annual report on Form 40-F.

 

**B. Preferred Shares**

 

We currently haveno preferred shares outstanding.

 

**Item 14****. Material Modifications to the Rights of SecurityHolders and Use of Proceeds**

 

Not Applicable

 

**Item 15.****Controls and Procedures**

 

**(a)****Evaluation ofdisclosure controls and procedures.**

 

The Company’sChief Executive Officer and Chief Financial Officer (its principal executiveofficer and principal financial officer, respectively) have concluded, based ontheir evaluation as of the end of the period covered by this annual report (the“evaluation date”), that the Registrant’s and the Company’s disclosure controlsand procedures are effective to ensure that information required to bedisclosed by it in reports filed or submitted by it under the SecuritiesExchange Act of 1934, as amended, is recorded, processed, summarized andreported within the time periods specified in the Securities and ExchangeCommission’s rules and forms, and includes controls and procedures designed toensure that information required to be disclosed by it in such reports isaccumulated and communicated to the Company’s management, including its ChiefExecutive Officer and Chief Financial Officer, as appropriate to allow timelydecisions regarding required disclosure.

 

**(b) Changes in internalcontrols.**

 

There have beenno significant changes to the Company’s internal control over financialreporting or in other factors that could significantly affect internal controlover financial reporting subsequent to the evaluation date and prior to thefiling date of this annual report.

 

**Item 16****[Reserved]**

 

**Item 16A****. Audit Committee Financial Expert**

 

The Board ofDirectors has determined that Mr. Naveen Dargan, an individual serving on theaudit committee of the Company’s Board of Directors, is an audit committeefinancial expert, as that term is defined in Item 401(h)(2) of Regulation S-Xunder the Securities Exchange Act of 1934, as amended.  The Board of Directors has also determinedthat Mr. Dargan is independent.

 

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**Item 16B****.Code of Ethics**

 

The Company’s code of ethics, which is applicable to its principalexecutive officer and senior financial officers, is posted on its website atwww.baytex.ab.ca.  In the event that theCompany:

 

(i)                                     amends any provision of its Codeof Ethics that applies to the Company’s principal executive officer, principalfinancial officer, principal accounting officer or controller or personsperforming similar functions that relates to any element of the code of ethicsdefinition enumerated in Item 16 B of Form 20-F, or

 

(ii)                                  grants a waiver, including animplicit waiver, from a provision of its Code of Ethics to any of the Company’sprincipal executive officer, principal financial officer, principal accountingofficer, or controller or persons performing similar functions that relates toany element of the code of ethics definition as enumerated in Item 16B of Form20-F,

 

the Company will disclose on its website any amendment to, or waiverof, a provision of its Code of Ethics within five business days following thedate of any such amendment or waiver, and will, in the case of a waiver, namethe persons to whom the waiver was granted.

 

**Item 16C****. Principal Accountant Fees and Services**

 

The followingtable provides information about the fees billed to Baytex for professionalservices rendered by Deloitte & Touche LLP, the Registrant’s principalaccountant, during fiscal 2003 and 2002:

 
|                         |   | **Aggregate  fees billed by the  Principal Accountant** |   |
|------------------------------|--------|---------------------------------------------------------|--------|
|                         |   | **2003**                                                |   | **2002** |   |
|                         |   | **($thousands)**                                        |   |
| Audit and Audit-related fees |   | 315                                                     |   | 159 |   |
| Tax fees                     |   | 157                                                     |   | 112 |   |
| Total                        |   | 472                                                     |   | 271 |   |

 

*Audit and Audit-RelatedFees*.  Audit and audit-related fees consist of feesfor the audit of the Registant’s annual financial statements, services that arenormally provided in connection with statutory and regulatory filings orengagements, or audit of certain subsidiaries and financial aspects of theRegistrant.

 

*Tax Fees. *Tax fees includedtax planning and various taxation matters.

 

The Company’sAudit Committee has the sole authority to review in advance, and grant anyappropriate pre-approvals, of all audit and non-audit services to be providedby the independent auditors and, in connection therewith, to approval all feesand other terms of engagement.

 

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**Item 16D****. Exemptions from Listing Standards for AuditCommittees**

 

Not Applicable

 

**Item 16 E****. Purchase of Equity Securities by the Issuer andAffiliated Purchasers**

 

Not Applicable

 

**Item 17****. Financial Statements**

 

Audited AnnualFinancial Statements:

 
| Report of Independent  Registered Chartered Accountants |   |
|---------------------------------------------------------|--------|
| Consolidated  Balance Sheets                            |   |
| Consolidated  Statements of Operations and Deficit      |   |
| Consolidated  Statements of Cash Flows                  |   |
| Notes to  Consolidated Financial Statements             |   |

 

**Item 18. Financial Statements**

 

Not Applicable

 

**Item 19. Exhibits**

 

**Number Exhibit**

 

4.1  Articlesof Amalgamation of the Registrant

 

4.2  By-laws ofthe Registrant

 

4.3  ArragementAgreement

 

10.1  NoteIndenture dated September 2, 2003 for the issue of 12% Unsecured, SubordinatedPromissory Notes

 

10.2  NetProfits Interests Agreement dated September 2, 2003

 

10.3  NoteIndenture dated July 9, 2003 between the Registrant and The Bank of Nova ScotiaTrust Company of New York providing for the issuance of 9 5/8 % Senior Subordinated Notes due 2010

 

31.1  Certifications of Chief Executive Officerpursuant to Section 302 of the Sarbanes-Oxley Act

 

31.2  Certifications of Chief Financial Officerpursuant to Section 302 of the Sarbanes-Oxley Act

 

32.1  Certifications of Chief Executive Officerand Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act

 

**Signature**

 

The registranthereby certifies that it meets all the requirements for filing on Form 20-F andthat it has duly caused and authorized the undersigned to sign this annualreport on its behalf.

 
|   | Baytex Energy Ltd.                                                      |
|--------|-------------------------------------------------------------------------|
|   |                                                                    |
|   |                                                                    |
|   | By:        /s/ Daniel G.  Belot |   |
|   | Name:                                                                   | Daniel G. Belot |
|   | Title:                                                                  | Vice President, Finance and  Chief Financial Officer |
|        |                                                                         |  |  |

 

 

Dated:July 14, 2004

 

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**Report of Independent Registered Chartered Accountants**

**To the Board of Directors of Baytex Energy Ltd.**

 

We have audited the consolidated balance sheets of Baytex Energy Ltd.(the “Company”) as at December 31, 2003 and 2002 and the consolidatedstatements of operations and deficit and of cash flows for each of the years inthe three year period ended December 31, 2003.  These financial statements are the responsibility of themanagement of the Company.  Ourresponsibility is to express an opinion on these financial statements based onour audits.

 

We conducted our audits in accordance with Canadian generally acceptedauditing standards and the standards of the Public Company Accounting OversightBoard (United States).  Those standardsrequire that we plan and perform an audit to obtain reasonable assurancewhether the financial statements are free of material misstatement.  An audit includes examining, on a testbasis, evidence supporting the amounts and disclosures in the financialstatements.  An audit also includesassessing the accounting principles used and significant estimates made bymanagement, as well as evaluating the overall consolidated financial statementpresentation.

 

In our opinion, these consolidated financial statements present fairly,in all material respects, the financial position of the Company as atDecember 31, 2003 and 2002 and the results of its operations and its cashflows for each of the years in the three year period ended December 31,2003 in accordance with Canadian generally accepted accounting principles.

 
|                     |   | (signed) /s/ Deloitte & Touche LLP |
|--------------------------|--------|----------------------------------------|
| Calgary, Alberta, Canada |   | Registered  Chartered Accountants      |
| June 29, 2004            |   |                                   |

 

**COMMENT BY AUDITORS FOR U.S. READERS ON CANADA-U.S.REPORTING DIFFERENCES**

 

**To the Board of Directors of Baytex Energy Ltd.**

 

The standards of the Public CompanyAccounting Oversight Board (United States) for auditors require the addition ofan explanatory paragraph (following the opinion paragraph) when there arechanges in accounting principles that have a material effect on thecomparability of the financial statements. As discussed in Note 3 to the consolidated financial statements ofBaytex Energy Ltd. (the “Company”), in 2003, the Company adoptedrecommendations with respect to determining stock-based compensation to conformto new recommendations of Section 3870 of the Canadian Institute ofChartered Accountants and in 2002, the Company changed its method foraccounting for foreign currency translation to conform to new recommendationsof Section 1650 of the Canadian Institute of Chartered Accountants.  Our report to the board of directors ofBaytex Energy Ltd. dated June 29, 2004 is expressed in accordance with Canadianauditing standards, which do not require a reference to such changes inaccounting principles in the auditors’ report when the changes are properlyaccounted for and adequately disclosed in the financial statements.

 
|                     |   | (signed) /s/ Deloitte & Touche LLP |
|--------------------------|--------|----------------------------------------|
| Calgary, Alberta, Canada |   | Registered  Chartered Accountants      |
| June 29, 2004            |   |                                   |

 

F-1

----

 

**BaytexEnergy Ltd.**

**Consolidated BalanceSheets**

**Asat December 31, 2003 and 2002**

**(thousandsof Canadian dollars)**

 
|                                          |   | **2003**  |    | **2002** |   |
|-----------------------------------------------|--------|-----------|---------|----------|--------|
| **Assets**                                    |   |      |    |     |   |
| Current assets                                |   |      |    |     |   |
| Cash and cash equivalents                     |   | $         | 53,731  |     | $      | 4,098 |   |
| Accounts receivable                           |   | 48,608    |    | 52,667   |   |
| Crude oil inventory                           |   | 5,900     |    | —   |   |
|                                          |   | 108,239   |    | 56,765   |   |
|                                          |   |      |    |     |   |
| Deferred charges and other assets             |   | 7,764     |    | 8,679    |   |
| Petroleum and natural gas properties (note 5) |   | 748,988   |    | 932,316  |   |
|                                          |   | $         | 864,991 |     | $      | 997,760 |   |
|                                          |   |      |    |     |   |
| **Liabilities**                               |   |      |    |     |   |
| Current liabilities                           |   |      |    |     |   |
| Accounts payable and accrued liabilities      |   | $         | 80,360  |     | $      | 92,563 |   |
| Due to Baytex Energy Trust                    |   | 61,032    |    | —   |   |
|                                          |   | 141,392   |    | 92,563   |   |
|                                          |   |      |    |     |   |
| Long-term debt (note 7)                       |   | 769,903   |    | 326,977  |   |
| Exchangeable shares (note 9)                  |   | 42,243    |    | —   |   |
| Deferred credits (note 8)                     |   | —    |    | 12,181   |   |
| Provision for future site restoration costs   |   | 23,483    |    | 21,950   |   |
| Future income taxes (note 13)                 |   | 176,516   |    | 184,402  |   |
|                                          |   | 1,153,537 |    | 638,073  |   |
| Commitments and contingencies (note 17)       |   |      |    |     |   |
|                                          |   |      |    |     |   |
| **Shareholders’  Equity**                |   |      |    |     |   |
| Common shares (note 10)                       |   | —    |    | 398,176  |   |
| Contributed surplus (note 11)                 |   | 224       |    | —   |   |
| Deficit                                       |   | (288,770  | )       | (38,489  | )      |
|                                          |   | (288,546  | )       | 359,687  |   |
|                                          |   | $         | 864,991 |     | $      | 997,760 |   |

 

See accompanying notes to the consolidated financialstatements.

 

**Onbehalf of the Board**

 

 
| **Naveen Dargan**                |   | **W. A. Blake Cassidy**          |
|----------------------------------|--------|----------------------------------|
| ***Director***Baytex Energy Ltd. |   | ***Director***Baytex Energy Ltd. |

 

F-2

----

 

**BaytexEnergy Ltd.**

**Consolidated Statements ofOperations and Deficit**

**YearsEnded December 31, 2003, 2002 and 2001**

**(thousandsof Canadian dollars, except per share data)**

 
|                                                                        |   | **2003** |     | **2002** |   | **2001** |   |
|-----------------------------------------------------------------------------|--------|----------|----------|----------|--------|----------|--------|
| **Revenue**                                                                 |   |     |     |     |   |     |   |
| Petroleum and natural gas sales                                             |   | $        | 351,404  |     | $      | 365,860  |   | $ | 329,700 |   |
| Royalties                                                                   |   | (54,244  | )        | (58,922  | )      | (57,805  | )      |
|                                                                        |   | 297,160  |     | 306,938  |   | 271,895  |   |
| **Expenses**                                                                |   |     |     |     |   |     |   |
| Operating                                                                   |   | 86,034   |     | 75,228   |   | 83,439   |   |
| General and administrative                                                  |   | 8,927    |     | 6,743    |   | 5,262    |   |
| Stock-based compensation (note 11)                                          |   | 739      |     | —   |   | —   |   |
| Net profits interest (note 18)                                              |   | 15,398   |     | —   |   | —   |   |
| Interest (note 7)                                                           |   | 45,079   |     | 25,217   |   | 32,942   |   |
| Costs on redemption and exchange of notes (note 7)                          |   | 44,771   |     | —   |   | —   |   |
| Foreign exchange (gain) loss (note 7)                                       |   | (52,101  | )        | (2,691   | )      | 16,262   |   |
| Gain on exchangeable shares                                                 |   | (3,513   | )        | —   |   | —   |   |
| Depletion and depreciation                                                  |   | 110,463  |     | 106,834  |   | 367,384  |   |
| Site restoration costs                                                      |   | 2,973    |     | 2,799    |   | 3,912    |   |
| Reorganization costs (note 4)                                               |   | 18,851   |     | —   |   | —   |   |
|                                                                        |   | 277,621  |     | 214,130  |   | 509,201  |   |
|                                                                        |   |     |     |     |   |     |   |
| **Income  (loss) before income taxes**                                      |   | 19,539   |     | 92,808   |   | (237,306 | )      |
|                                                                        |   |     |     |     |   |     |   |
| **Income  taxes (recovery)** (note 13)                                      |   |     |     |     |   |     |   |
| Current                                                                     |   | 9,663    |     | 9,716    |   | 7,128    |   |
| Future                                                                      |   | (11,500  | )        | 37,956   |   | (107,327 | )      |
|                                                                        |   | (1,837   | )        | 47,672   |   | (100,199 | )      |
|                                                                        |   |     |     |     |   |     |   |
| **Net  income (loss)**                                                      |   | 21,376   |     | 45,136   |   | (137,107 | )      |
|                                                                        |   |     |     |     |   |     |   |
| **Retained  earnings (deficit), beginning of year, as previously reported** |   | (38,489  | )        | (75,954  | )      | 52,555   |   |
|                                                                        |   |     |     |     |   |     |   |
| **Reorganization  of share capital**(note 4)                                |   | (271,657 | )        | —   |   | —   |   |
|                                                                        |   |     |     |     |   |     |   |
| **Accounting  policy change for foreign exchange** (note 3)                 |   | —   |     | (7,671   | )      | 927      |   |
|                                                                        |   |     |     |     |   |     |   |
| **Deficit,  beginning of year, as restated**                                |   | (38,489  | )        | (83,625  | )      | 53,482   |   |
|                                                                        |   |     |     |     |   |     |   |
| **Deficit,  end of year**                                                   |   | $        | (288,770 | )        | $      | (38,489  | )      | $ | (83,625 | ) |
|                                                                        |   |     |     |     |   |     |   |
| **Net income (loss) per share**(note 12)                                    |   |     |     |     |   |     |   |
| Basic                                                                       |   | $        | 0.60     |     | $      | 0.86     |   | $ | (2.77 | ) |
| Diluted                                                                     |   | $        | 0.60     |     | $      | 0.85     |   | $ | (2.77 | ) |

 

See accompanying notes to the consolidatedfinancial statements.

 

F-3

----

 

**BaytexEnergy Ltd.**

**Consolidated Statements ofCash Flows**

**YearsEnded December 31, 2003, 2002 and 2001**

**(thousandsof Canadian dollars)**

 
|                                                     |   | **2003** |     | **2002** |     | **2001** |     |
|----------------------------------------------------------|--------|----------|----------|----------|----------|----------|----------|
| **Cash  provided by (used in):**                         |   |     | * * |     | * * |     | * * |
| **Operating  activities**                                |   |     |     |     |     |     |     |
| Net income (loss)                                        |   | $        | 21,376   |     | $        | 45,136   |     | $ | (137,107 | ) |
| Items not affecting cash:                                |   |     |     |     |     |     |     |
| Stock based compensation (note 11)                       |   | 739      |     | —   |     | —   |     |
| Amortization of deferred charges                         |   | 1,027    |     | 1,052    |     | 946      |     |
| Gain on exchangeable shares                              |   | (3,513   | )        | —   |     | —   |     |
| Costs on redemption and exchange of notes (note 7)       |   | 44,771   |     | —   |     | —   |     |
| Foreign exchange (gain) loss                             |   | (52,101  | )        | (2,691   | )        | 16,262   |     |
| Depletion and depreciation                               |   | 110,463  |     | 106,834  |     | 367,384  |     |
| Site restoration costs                                   |   | 2,973    |     | 2,799    |     | 3,912    |     |
| Future income taxes (recovery)                           |   | (11,500  | )        | 37,956   |     | (107,327 | )        |
|                                                     |   | 114,235  |     | 191,086  |     | 144,070  |     |
| Change in non-cash working capital (note 14)             |   | (7,828   | )        | 1,272    |     | 5,682    |     |
| (Increase) decrease in deferred charges and other assets |   | 211      |     | (1,057   | )        | —   |     |
| Decrease in deferred credits                             |   | (2,213   | )        | (18,694  | )        | 18,694   |     |
|                                                     |   | 104,405  |     | 172,607  |     | 168,446  |     |
| **Financing  activities**                                |   |     |     |     |     |     |     |
| Issue of senior subordinated term notes                  |   | —   |     | —   |     | 227,895  |     |
| Redemption of senior secured notes (note 7)              |   | (89,950  | )        | —   |     | —   |     |
| Decrease in bank loan and other debt                     |   | —   |     | (76,254  | )        | (88,474  | )        |
| Increase in deferred charges and other assets            |   | (7,425   | )        | —   |     | (9,037   | )        |
| Increase in deferred credits                             |   | —   |     | 12,181   |     | —   |     |
| Issue of common shares (note 10)                         |   | 37,049   |     | 3,497    |     | 1,444    |     |
| Repurchase of common shares                              |   | —   |     | (55      | )        | (860     | )        |
| Change in non-cash working capital                       |   | 61,032   |     | —   |     | —   |     |
|                                                     |   | 706      |     | (60,631  | )        | 130,968  |     |
| **Investing  activities**                                |   |     |     |     |     |     |     |
| Corporate acquisitions (note 19)                         |   | —   |     | —   |     | (249,152 | )        |
| Items not affecting cash:                                |   |     |     |     |     |     |     |
| Shares issued on acquisition                             |   | —   |     | —   |     | 68,104   |     |
| Assumption of long-term debt                             |   | —   |     | —   |     | 36,356   |     |
| Assumption of working capital                            |   | —   |     | —   |     | (2,734   | )        |
|                                                     |   | —   |     | —   |     | (147,426 | )        |
| Petroleum and natural gas property expenditures          |   | (186,756 | )        | (182,048 | )        | (189,283 | )        |
| Disposal of petroleum and natural gas properties         |   | 137,493  |     | 55,580   |     | 62,582   |     |
| Properties held for sale                                 |   | —   |     | (46,895  | )        | 46,895   |     |
| Change in non-cash working capital (note 14)             |   | (6,215   | )        | 65,485   |     | (72,182  | )        |
|                                                     |   | (55,478  | )        | (107,878 | )        | (299,414 | )        |
| **Change  in cash and cash equivalents during the year** |   | 49,633   |     | 4,098    |     | —   |     |
| **Cash and  cash equivalents, beginning of year**        |   | 4,098    |     | —   |     | —   |     |
| **Cash and  cash equivalents, end of year**              |   | $        | 53,731   |     | $        | 4,098    |     | $ | — |   |

 

See accompanying notes to the consolidatedfinancial statements.

 

F-4

----

 

**Baytex Energy Ltd.**

**Notes to the ConsolidatedFinancial Statements**

**Years Ended December 31, 2003, 2002 and 2001**

(all tabularamounts in thousands of Canadian dollars, except per share amounts)

 

**1.****                                     ****BASIS OF PRESENTATION**

 

On September 2, 2003, Baytex Energy Ltd. (the “Company” or“Baytex”) completed a Plan of Arrangement (the “Arrangement”) involving Baytex, Baytex Energy Trust (the “Trust”),and Crew Energy Inc. (“Crew”).  Holdersof common shares of Baytex elected or were deemed to have elected to receiveeither Trust Units or Exchangeable Shares of Baytex for their common shares onthe basis of one Trust Unit or Exchangeable Share, respectively, for eachcommon share held.  Coincident with theArrangement becoming effective, certain of Baytex’s exploration assets wereacquired by Crew, and the common shares of Crew were distributed to the formerholders of Baytex common shares on the basis of one-third of a common share ofCrew for each common share of Baytex held. Subsequent to the Arrangement, the Company is a subsidiary of the Trust.

 

Prior to the Arrangement, the consolidated financial statementsincluded the accounts of the Company and its subsidiaries and partnership.  After giving effect to the Arrangement, theconsolidated financial statements include the accounts of the Company and itssubsidiaries and have been prepared by management in accordance with Canadiangenerally accepted accounting principles as described in Note 2. The reconciliationof the financial statements to United States generally accepted accountingprinciples is contained in Note 20.

 

**2.****                                     ****SIGNIFICANT ACCOUNTING POLICIES**

 

***Consolidation***

 

Theconsolidated financial statements include the accounts of the Company and itswholly owned subsidiaries from the respective dates of acquisition of thesubsidiary companies.  Inter-companytransactions and balances are eliminated upon consolidation.

 

***MeasurementUncertainty***

 

The preparation of the consolidated financial statements requiresmanagement to make estimates and assumptions that affect the reported amountsof assets and liabilities and disclosure of contingent assets and liabilitiesat the date of the consolidated financial statements and revenues and expensesduring the reporting period.  Actualresults can differ from those estimates.

 

In particular, amounts recorded for depreciation and depletion andamounts used for ceiling test calculations are based on estimates of petroleumand natural gas reserves and future costs required to develop thosereserves.  The Company’s reserveestimates are evaluated annually by an independent engineering firm.  By their nature, these estimates of reservesand the related future cash flows are subject to measurement uncertainty, andthe impact on the consolidated financial statements of future periods could bematerial.

 

***Cash and CashEquivalents***

 

Cash and cash equivalents include monies on deposit and short-terminvestments, accounted for at cost, which have an initial maturity date of notmore than 90 days.

 

***Crude OilInventory***

 

Crude oilinventory, consisting of production in transit in pipelines at the balancesheet date pursuant to a long-term crude oil supply agreement, is valued at thelower of cost or net realizable value.

 

F-5

----

 

***Petroleum and Natural Gas Operations***

 

The Company follows the full cost method of accounting for itspetroleum and natural gas operations whereby all costs relating to theexploration for and development of petroleum and natural gas reserves arecapitalized in one Canadian cost centre and charged against income, as set outbelow.  Such costs include landacquisition, drilling of productive and non-productive wells, geological andgeophysical, production facilities, carrying costs directly related to unprovedproperties and corporate expenses directly related to acquisition, explorationand development activities and do not include any costs related to productionor general overhead expenses.  Thesecosts along with estimated future capital costs that are based on current costsand that are incurred in developing proved reserves are depleted anddepreciated on a unit of production basis using estimated gross provedpetroleum and natural gas reserves.  Forpurposes of this calculation, petroleum and natural gas reserves are convertedto a common unit of measurement on the basis of their relative energy contentwhere six thousand cubic feet of gas equates to one barrel of oil.  Costs of acquiring and evaluating unproved propertiesare excluded from costs subject to depletion and depreciation until it isdetermined whether proved reserves are attributable to the properties orimpairment occurs.  Unproved propertiesare evaluated for impairment on an annual basis.

 

Gains or losses on the disposition of petroleum and natural gasproperties are recognized only when crediting the proceeds to costs wouldresult in a change of 20 percent or more in the depletion rate.

 

The net amount at which petroleum and natural gas properties arecarried is subject to a cost recovery test (the “ceiling test”).  Under this test, an estimate is made of theultimate recoverable amount from future net revenues using proved reserves plusthe net costs of major development projects and unproved properties, lessfuture removal and site restoration costs, overhead, financing costs and incometaxes, using period end prices and costs. If the net carrying costs exceed the ultimate recoverable amount,additional depletion and depreciation is provided.

 

***Provision for Future Site Restoration Costs***

 

Estimates are made of the future site restoration costs relating to theCompany’s petroleum and natural gas properties at the end of their economiclife, based on year end values, in accordance with current legislativerequirements and industry practice. Annual charges are provided on a unit of production method.  Actual expenditures incurred are appliedagainst the provision for future site restoration costs.

 

***Joint Interests***

 

A portion of the Company’s exploration, development and productionactivities is conducted jointly with others. These consolidated financial statements reflect only the Company’sproportionate interest in such activities.

 

***Foreign Currency Translation***

 

Foreign currency denominated monetary items are translated intoCanadian dollars at the exchange rate in effect at the balance sheet date.  Exchange gains and losses on long-termmonetary items that do not qualify for hedge accounting are recognized in income.

 

Revenue and expenses are translated at the monthly average rate ofexchange.  Translation gains and lossesare included in net income.

 

F-6

----

 

***Deferred Charges and Other Assets***

 

Financingcosts related to the exchange of the senior subordinated notes have beendeferred and are amortized over the term of the notes on a straight-line basis.

 

***FinancialInstruments***

 

The Company formally documents its risk management objectives andstrategies to manage exposures to fluctuations in commodity prices, interestrates and foreign currency exchange rates. The risk management policies include the permitted use of derivativefinancial instruments, including swaps and collars, used to manage thesefluctuations.  All transactions of thisnature entered into by the Company are related to an underlying financialinstrument or to future petroleum and natural gas production.  The Company does not use derivativefinancial instruments for trading or speculative purposes.  Gains and losses on derivative contracts arerecognized in income based on the underlying financial instrument or the futurepetroleum and natural gas production in same period that the transactions aresettled.  The fair values of derivativeinstruments are not recorded in the consolidated balance sheet.

 

Gains and losses related to derivative financial instruments that havebeen closed prior to the end of the term are deferred and recognized in theconsolidated statement of operations over the original term of the instrument.

 

***Future IncomeTaxes***

 

The Company is subject to corporate income taxes and follows theliability method of accounting for income taxes.  Income taxes are accounted for under the liability method of taxallocation, which determines future income taxes based on the differences betweenassets and liabilities reported for financial accounting purposes and thosereported for tax purposes.  Futureincome taxes are calculated using tax rates anticipated to apply in periodsthat temporary differences are expected to reverse.

 

***Flow-through Shares***

 

The Company had financed a portion of its exploration and developmentactivities through the issue of flow-through shares.  Under the terms of the flow-through share agreements, the taxattributes of the related expenditures are renounced to the subscribers.  Accordingly, the carrying value of theexpenditures incurred and the shares issued are recorded net of tax benefitsrenounced to the subscribers. The Company records the gross carrying value ofthe expenditures and records a future tax liability for the tax benefitsrenounced to subscribers.

 

**Stock-based Compensation**

 

Employees of Baytex have the right to participate in the Trust UnitRights Incentive Plan (the “Plan”), which is described in note 10.  The exercise price of the rights grantedunder the Plan may be reduced in future periods in accordance with the terms ofthe Plan.  Therefore, it is not possibleto determine a fair value for the rights granted under the Plan using atraditional option pricing model and compensation expense has been determinedbased on the intrinsic value of the rights at the date of exercise or at thedate of the consolidated financial statements for unexercised rights.

 

F-7

----

 

Compensation expense associated with rights granted under the plan isrecognized in earnings over the vesting period of the Plan with a correspondingincrease or decrease in contributed surplus. Changes in the intrinsic value of unexercised rights after the vestingperiod are recognized in income in the period of change with a correspondingincrease or decrease in contributed surplus. The exercise of trust unit rights are recorded as an increase in trustunits with a corresponding reduction in contributed surplus.

 

This method of determining compensation expense may result in largefluctuations, even recoveries, in compensation expense due to changes in theunderlying trust unit price. Recoveries of compensation expense will only berecognized to the extent of previously recorded cumulative compensation expenseassociated with rights outstanding at the date of the financial statements.

 

***Per-share Amounts***

 

Basic net income per share is computed by dividing net income by theweighted average number of common shares outstanding during the year.  Diluted per share amounts reflect thepotential dilution that could occur if outstanding stock options wereexercised.  The treasury stock method isused to determine the dilutive effect of stock options, whereby any proceedsfrom the exercise of stock options or other dilutive instruments are assumed tobe used to purchase common shares at the average market price during theperiod.

 

**3.****                                     ****CHANGES INACCOUNTING POLICIES**

 

***Stock-basedCompensation Plan***

 

The Company has elected to prospectively adopt amendments to CanadianInstitute of Chartered Accountants (“CICA”) Handbook Section 3870,“Stock-based Compensation and Other Stock-based Payments” pursuant to thetransitional provisions contained therein. Under this amended standard, the Company must account for compensationexpense based on the fair value of rights granted to its employees under theTrust Unit Rights Incentive Plan.  Asthe Company is unable to determine the fair value of the rights granted,compensation expense has been determined based on the intrinsic value of therights at the exercise date or at the date of the consolidated financialstatements for unexercised rights. Compensation expense of $0.22 million was recorded as non cash expensefor all the unit rights granted during 2003, with a corresponding amountrecorded as contributed surplus.

 

The adoption of these amendments also impacted the stock options of theCompany outstanding prior to the Plan of Arrangement.  Compensation expense of $0.52 million was recorded for all stockoptions granted on or after January 1, 2003, with a corresponding amountrecorded as contributed surplus.  Forstock options granted prior to January 1, 2003, the pro forma earningsimpact of related stock-based compensation expense is disclosed (see Note 11).

 

***Foreign Currency***

 

Effective January 1, 2002, the Company retroactively adopted theCICA amended accounting standard with respect to accounting for foreigncurrency translation.  As a result ofthe amendments, all exchange gains and losses on long-term monetary items thatdo not qualify for hedge accounting are recognized in income.  Previously, these exchange gains and losseswere deferred and amortized over the remaining life of the monetary item.  The impact of the amended standard on theyear ended December 31, 2002 was to increase net income by $1.8million.  The effect of this change onthe December 31, 2001 consolidated balance sheet is an elimination of theunrealized foreign exchange loss of $13.7 million, a decrease in future incometaxes of $6.0 million, and an increase in the deficit of $7.7 million.

 

F-8

----

 

**4.****                                     ****TRANSFER OF ASSETS AND LIABILITIES PURSUANT TO PLAN OFARRANGEMENT**

 

Under the Plan of Arrangement (note 1), the Company transferred to Crewa portion of the Company’s producing and exploratory petroleum and natural gasassets.  As this was a related partytransaction, assets and liabilities were transferred at carrying value asfollows:

 
| Petroleum and natural gas assets and equipment                  |   | $      | 21,244 |   |
|-----------------------------------------------------------------|--------|--------|--------|--------|
| Future income tax asset                                         |   | 3,278  |   |
| Total assets transferred                                        |   | 24,522 |   |
| Provision for future site restoration                           |   | (559   | )      |
| Net assets transferred and reduction in share capital (note 10) |   | $      | 23,963 |   |

 

Under the Plan of Arrangement, the share capital of the Company wasreorganized and the holders of old common shares of Baytex elected or weredeemed to have elected to receive either Trust Units or Exchangeable Shares ofBaytex for their old common shares. This reorganization of share capital resulted in a charge of $271.6million to the deficit.

 

Reorganization costs of $18.9 million were expensed in the consolidatedstatements of operations as a result of the Plan of Arrangement.

 

**5.****                                     ****PETROLEUM AND NATURAL GAS PROPERTIES**

 
|                                   |   | **As  at December 31,** |      |
|----------------------------------------|--------|------------------------------|-----------|
|                                   |   | **2003**                     |      | **2002** |   |
| Petroleum and natural gas properties   |   | $                            | 1,916,378 |   | $ | 1,989,246 |   |
| Accumulated depletion and depreciation |   | (1,167,390                   | )         | (1,056,930 | ) |
|                                   |   | $                            | 748,988   |   | $ | 932,316 |   |

 

During 2003, $4.4 million (2002 - $6.7 million) of corporate expensesrelating to exploration and development activities were capitalized.  No corporate expenses have been capitalizedsince the effective date of the Plan of Arrangement on September 2,2003.  In calculating the depletion anddepreciation provision for 2003, $51.1 million (2002 - $80.3 million) of costsrelating to undeveloped properties and materials and supplies of $4.0 million(2002- $5.5 million) were excluded from costs subject to depletion anddepreciation.

 

As a result of the ceiling test performed at December 31, 2001,the Company recorded additional depletion and depreciation on its petroleum andnatural gas properties of $234.5 million ($131.3 million net of income tax).

 

**6.**                                      **BANK CREDIT FACILITIES**

 

OnSeptember 3, 2003, the Company entered into a new credit agreement with asyndicate of chartered banks.  Thecredit facilities can be drawn in either Canadian or U.S. funds and bearinterest at the agent bank’s prime lending rate, bankers’ acceptance rates plusapplicable margins or LIBOR rates plus applicable margins.  The facilities aggregating $165 million aresubject to semi-annual review beginning in November 2003 and are securedby a floating charge over all of the Company’s assets.  At December 31, 2003, there were noamounts outstanding under the bank credit facilities.

 

F-9

----

 

**7.****                                     ****LONG-TERM DEBT**

 
|                                                                             |   | **As  at December 31,** |    |
|----------------------------------------------------------------------------------|--------|------------------------------|---------|
|                                                                             |   | **2003**                     |    | **2002** |   |
| Senior secured notes (2002 US$57,000,000)                                        |   | $                            | —  |   | $ | 90,037 |   |
| 10.5% senior subordinated notes (2003 - US$247,000; 2002 –  US$150,000,000) |   | 319                          |    | 236,940 |   |
| 9.625% senior subordinated notes (2003 -US$179,699,000)                          |   | 232,243                      |    | — |   |
| 12% unsecured, subordinated promissory note                                      |   | 527,398                      |    | — |   |
| 12% unsecured, subordinated promissory note                                      |   | 9,943                        |    | — |   |
|                                                                             |   | $                            | 769,903 |   | $ | 326,977 |   |

 

***Senior SecuredNotes***

 

On November 13, 1998, the Company issued US$57 million of seniorsecured notes, bearing interest at 7.23 percent payable quarterly withprincipal repayable on November 13, 2004. In May 2003, the Company redeemed the outstanding senior secured notesfor a total cash payment of $90 million, resulting in a cost of $4.7 million onthe redemption.  Foreign exchange gainswere included in income until the redemption of the notes.

 

***SeniorSubordinated Notes***

 

On February 12, 2001, the Company issuedUS$150 million of senior subordinated notes (“Old Notes”) bearing interest at10.5 percent payable semi-annually with principal repayable onFebruary 15, 2011.  These notes areunsecured and are subordinate to the Company’s bank credit facilities.

 

On July 9, 2003, the Company completed an exchange offer relatedto its Old Notes.  The Company issuedUS$179.7 million of 9.625 percent senior subordinated notes due July 15,2010 (“New Notes”) in exchange for US$149.8 million of the Old Notes and incurreda non-cash loss of $40.0 million on the completion of this transaction, whichwas recognized in income.  The New Notes are unsecured and aresubordinate to the Company’s bank credit facilities.

 

***Unsecured,subordinated promissory note***

 

On September 2, 2003, the Company issued$627.4 million of unsecured, subordinated promissory notes to the Trust.  A total of $100.0 million of the unsecured,subordinated promissory notes were cancelled on the grant to the Trust of a netprofits interest in certain petroleum and natural gas properties.  The notes bear interest at 12 percentpayable monthly with principal repayable on September 1, 2033.  These notes are unsecured and aresubordinate to the Company’s bank credit facilities and senior subordinatednotes.

 

***Unsecured,subordinated promissory note***

 

During 2003, the Company issued a total of$9.9 million of unsecured, subordinated promissory notes to ExchangeCo.  The notes bear interest at 12 percentpayable monthly with principal repayable on September 1, 2033.  These notes are unsecured and are subordinateto the Company’s bank credit facilities and senior subordinated notes.

 

F-10

----

 

***Interest Expense***

 

The Company has incurred interest expense onits outstanding debt as follows:

 
|                                     |   | **2003** |   | **2002** |   | **2001** |   |
|------------------------------------------|--------|----------|--------|----------|--------|----------|--------|
| Bank loan                                |   | $        | 675    |     | $      | 760      |   | $ | 4,620 |   |
| Amortization of deferred charges         |   | 1,027    |   | 1,052    |   | 946      |   |
| Senior subordinated notes                |   | 21,846   |   | 23,405   |   | 27,376   |   |
| Unsecured, subordinated promissory notes |   | 21,531   |   | —   |   | —   |   |
| Total interest                           |   | $        | 45,079 |     | $      | 25,217   |   | $ | 32,942 |   |

 

The totalinterest expense on the Company’s long-term debt during 2003 was $43.4 million(2002 - $23.4 million; 2001 - $27.4 million).

 

**8.****                                     ****DEFERRED CREDITS**

 
|                              |   | **As  at December 31,** |   |
|-----------------------------------|--------|------------------------------|--------|
|                              |   | **2003**                     |   | **2002** |   |
| Deferred interest swap settlement |   | $                            | — |   | $ | 12,181 |   |
|                                   |        |                              |        |  |  |  |  |

 

In August 2002, the Company terminatedall outstanding interest rate swap agreements for total proceeds of $14.1million.  This amount was deferred andwas being amortized as a reduction of interest expense over the original termsof the agreements.  The amortization wasterminated when the senior secured notes were redeemed and when the exchange offer related to the OldNotes was concluded (note 7).  The residual balance was included in thecost on redemption and exchange of notes.

 

During 2001, the Company renegotiated certainderivative contracts related to 2002 commodity prices and received a netpayment of $18.7 million.  This amountwas recognized in income during 2002.

 

**9.             EXCHANGEABLE SHARES**

 

***ExchangeableShares***

 

The Company is authorized to issue an unlimited number of exchangeableshares.  The exchangeable shares can beconverted (at the option of the holder) into trust units at any time up toSeptember 2, 2013.  The exchangeableshares are automatically redeemable at September 2, 2013.  Up to 1.9 million exchangeable shares may beredeemed annually by the Company for either cash or the issue of trust unitspurchased from the Trust.  The number oftrust units issued upon conversion is based upon the exchange ratio in effectat the conversion date.  The exchangeratio is calculated monthly based on the cash distribution paid by the Trustdivided by the weighted average trust unit price of the five-day trading periodending on the record date.  The exchangeratio at December 31, 2003 was 1.04530 trust units per exchangeableshare.  Cash distributions are not paidon the exchangeable shares.  Theexchangeable shares are not publicly traded. Because the exchangeable shares may be redeemed for cash, or by theissue of trust units purchased from the Trust, the exchangeable shares areconsidered a liability.  The cashrequired to redeem the exchangeable shares or to purchase trust units is basedon the fair value of the trust units.

 
| **Exchangeable  Shares**                                  |   | **Number  of  shares** |   | **Amount** |   |
|-----------------------------------------------------------|--------|------------------------|--------|------------|--------|
| Issued September 2, 2003 pursuant to the Arrangement |   | 4,732                  |   | $          | 55,699 |   |
| Exchanged for trust units of the Trust                    |   | (1,007                 | )      | (9,943     | )      |
| Adjustment to fair value                                  |   | —                 |   | (3,513     | )      |
| Balance December 31, 2003                            |   | 3,725                  |   | $          | 42,243 |   |

 

**10.****                              ****SHAREHOLDERS’ CAPITAL**

 

***Common Shares***

 

The Company is authorized to issue an unlimited number of commonshares.  Under the Arrangement, theCompany’s former issued and outstanding common shares were exchanged for Trustunits or exchangeable shares.  One newcommon share was issued to the Trust, under the Arrangement, for one dollar.

 

F-11

----

 

Under the Plan of Arrangement, former shareholders of the Companyreceived one unit of the Trust or one exchangeable share and one-third of ashare of Crew for each former common share held.

 
| **Former  common shares of Baytex Energy Ltd.**             |   | **Number  of  shares** |   | **Amount** |    |
|-------------------------------------------------------------|--------|------------------------|--------|------------|---------|
| Balance December 31, 2000                              |   | 45,797                 |   | $          | 326,727 |   |
| Issued for corporate acquisitions (note 18)                 |   | 6,119                  |   | 68,104     |    |
| Stock options exercise                                      |   | 314                    |   | 1,444      |    |
| Normal course issuer bid                                    |   | (222                   | )      | (860       | )       |
| Future tax related to flow-through shares                   |   | —                 |   | (721       | )       |
| Balance December 31, 2001                              |   | 52,008                 |   | 394,734    |    |
| Exercise of stock options                                   |   | 820                    |   | 3,497      |    |
| Normal course issuer bid                                    |   | (9                     | )      | (55        | )       |
| Balance December 31, 2002                              |   | 52,819                 |   | 398,176    |    |
| Flow-through shares issued                                  |   | 103                    |   | 810        |    |
| Future tax related to flow-through shares                   |   | —                 |   | (336       | )       |
| Exercise of stock options (note 11)                         |   | 5,115                  |   | 36,239     |    |
| Transfer of assets under Plan of Arrangement (note 4)       |   | —                 |   | (23,963    | )       |
| Balance September 2, 2003 prior to Plan of Arrangement |   | 58,037                 |   | 410,926    |    |
| Trust units issued                                          |   | (53,305                | )      | (377,419   | )       |
| Exchangeable shares issued                                  |   | (4,732                 | )      | (33,507    | )       |
| Balance December 31, 2003                              |   | —                 |   | $          | —  |   |

 

***Flow-through shares***

 

In accordance with the terms of flow-through share offerings enteredinto by the Company and pursuant to certain provisions of the Income Tax Act(Canada), the Company fulfilled its commitment to renounce for income taxpurposes exploration expenditures of $0.8 million in 2003 to the subscribers ofthe flow-through shares.

 

***Normal courseissuer bid***

 

During the year ended December 31, 2002, the Company acquired9,200 (2001 – 222,400) of its common shares through a normal course issuer bidprogram at an average cost of $6.03 per share (2001 - $3.87 per share).  The shares purchased under the normal courseissuer bid were cancelled.  InJanuary 2003, the Company renewed the normal course issuer bid to purchaseup to 5.2 million common shares of the Company during the 12-month periodbeginning January 7, 2003.  Thenormal course issuer bid was terminated on September 2, 2003, with noshares purchased.

 

**11.****                              ****STOCK-BASED COMPENSATION**

 

Effective September 2, 2003, the Trust established a Trust UnitRights Incentive Plan to replace the stock option plan of the Company.  The Company’s employees are entitled toparticipate in the Trust Unit Rights Incentive Plan.  A total of 5,800,000 Trust Unit Rights are reserved for issueunder the Plan.  Trust Unit Rights

 

F-12

----

 

are granted atthe market price of the trust units at the time of the grant, vest over threeyears and have a term of five years.

 

The Trust Unit Rights Incentive Plan allows for the exercise price ofthe rights to be reduced in future periods by a portion of the futuredistributions provided a certain threshold return on assets is met.  The Company has determined that the amountof the reduction cannot be reasonably estimated, as it is dependent upon anumber of factors including, but not limited to, future trust unit prices,production of oil and natural gas, determination of amounts to be withheld fromfuture distributions to fund capital expenditures, and the purchase and sale ofoil and natural gas assets.  Therefore,it is not possible to determine a fair value for the rights granted under theplan.

 

Compensation expense is therefore determined based on the amount thatthe market price of the trust unit exceeds the exercise price for rights issuedas at the date of the consolidated financial statements and is recognized inincome over the vesting period of the plan. The adoption of the amendments related to accounting for unit-basedcompensation results in compensation expense for year ended December 31,2003 was $0.22 million (note 3).

 

The number of unit rights issued and exercise prices are detailedbelow:

 
|                                 |   | **Number  of  Rights** |   | **Weighted  average  exercise price (1)** |   |
|--------------------------------------|--------|------------------------|--------|-------------------------------------------|--------|
| Initial grant September 9, 2003 |   | 2,593                  |   | $                                         | 10.23  |   |
| Granted                              |   | 380                    |   | $                                         | 9.60   |   |
| Cancelled                            |   | (118                   | )      | $                                         | 10.23  |   |
| Balance December 31, 2003       |   | 2,855                  |   | $                                         | 10.15  |   |

 

----

(1) Exerciseprice reflects grant price less reduction in exercise price as discussed above.

 

The following table summarizes information about the unit rightsoutstanding at December 31, 2003:

 
|                           |   | **Number  Outstanding at  December 31,  2003** |   | **Weighted  Average  Remaining  Term** |   | **Weighted  Average  Exercise  Price** |   | **Number  Exercisable  at  December  31, 2003** |   | **Weighted  Average  Exercise  Price** |   |
|--------------------------------|--------|-----------------------------------------------------|--------|----------------------------------------|--------|----------------------------------------|--------|-------------------------------------------------|--------|----------------------------------------|--------|
|                           |   |                                                |   | **(years)**                            |   |                                   |   |                                            |   |                                   |   |
| Balance December 31, 2003 |   | 2,855                                               |   | 4.7                                    |   | $                                      | 10.15  |                                            | — |                                   | — |   |
|                                |        |                                                     |        |                                        |        |                                        |        |                                                 |        |                                        |        |  |

 

The Company had a stock option plan prior to the Plan ofArrangement.  The outstanding stockoptions of the Company were exercised or cancelled as follows:

 

F-13

----

 
|                           |   | **Number  of  options** |   | **Weighted  averageexercise price** |   |
|--------------------------------|--------|-------------------------|--------|-------------------------------------|--------|
| Balance December 31, 2001 |   | 4,468                   |   | $                                   | 6.19   |   |
| Granted                        |   | 1,682                   |   | $                                   | 7.61   |   |
| Exercised                      |   | (820                    | )      | $                                   | 4.27   |   |
| Cancelled                      |   | (204                    | )      | $                                   | 5.78   |   |
| Balance December 31, 2002 |   | 5,126                   |   | $                                   | 6.98   |   |
| Granted                        |   | 121                     |   | $                                   | 9.28   |   |
| Exercised                      |   | (5,115                  | )      | $                                   | 7.07   |   |
| Cancelled                      |   | (132                    | )      | $                                   | 5.44   |   |
| Balance December 31, 2003 |   | —                  |   | —                              |   |

 

The adoption of the amendments related to accounting for unit-basedcompensation also impacted the accounting for stock options granted by theCompany to employees before the implementation of the Plan of Arrangement.  Compensation expense of $0.52 million wasrecorded for all stock options granted by the Company on or afterJanuary 1, 2003, with a corresponding amount recorded as trust units onexercise of the options, with expenses in the first and second quartersincreased by $0.32 million and $0.20 million, respectively.  Accordingly, quarterly net income in suchquarters previously reported as $32.9 million and $41.8 million would berevised to $32.6 million and $41.6 million, respectively.  There were no changes to the expenses or thenet loss of the third quarter of 2003.

 

Compensation expense for options granted during 2003 was based on theestimated fair values at the time of the grant and the expense was recognizedover the vesting period of the option. For options granted prior to January 1, 2003, the pro forma incomeimpact of related stock-based compensation expense is as follows:

 
|                             |   | **Year  Ended December 31** |   |
|----------------------------------|--------|----------------------------------|--------|
|                             |   | **2003**                         |   | **2002** |   |
| Net income as reported           |   | $                                | 21,376 |   | $ | 45,136 |   |
| Stock-based compensation expense |   | (5,522                           | )      | (612 | ) |
| Pro forma                        |   | $                                | 15,854 |   | $ | 44,524 |   |
|                             |   |                             |   |   |   |
| Net income per share:            |   |                             |   |   |   |
| Basic as reported                |   | $                                | 0.60   |   | $ | 0.86 |   |
| Pro forma                        |   | $                                | 0.44   |   | $ | 0.85 |   |
| Diluted as reported              |   | $                                | 0.60   |   | $ | 0.85 |   |
| Pro forma                        |   | $                                | 0.44   |   | $ | 0.83 |   |

 

The weighted average fair market value of options granted during theyear ended December 31, 2003 was $4.21 per option (2002 - $3.65 peroption).  The fair value of the stockoptions granted was estimated on the grant date based on the Black-Scholesoption-pricing model using the following assumptions:

 
|                                                        |   | **Year  Ended December 31** |   |
|-------------------------------------------------------------|--------|----------------------------------|--------|
|                                                        |   | **2003**                         |   | **2002** |   |
| Risk-free interest rate                                     |   | 4.5                              |   | 4.0 |   |
| Volatility in the price of the Company’s common shares |   | 52                               |   | 57 |   |
| Expected life (years)                                       |   | 4                                |   | 4 |   |
| Dividends paid                                              |   | Nil                              |   | Nil |   |

 

F-14

----

 

The Company had granted stock appreciation rights (“Rights”) to certainemployees.  Holders of the Rights wereentitled to receive incentive payments based on the difference between marketprice of the Company’s common shares and exercise price of the Rights.  The exercise price of the Rights wasdetermined based on the market price of the Company’s common shares at the timethe Rights were granted.  The Rightsvested over three years and had a term of four years.  During 2002, all 202,334 remaining Rights (2001 – 6,666) wereexercised.  The related compensationexpense has been included in general and administrative expenses.

 

**12.****                              ****NET INCOME PER SHARE**

 

The Company applies the treasury stock method to assess the dilutiveeffect of outstanding stock options on net income per share.  The number of shares used in the calculationof diluted net income per share is determined as follows:

 
|                                                    |   | **2003** |   | **2002** |   | **2001** |   |
|---------------------------------------------------------|--------|----------|--------|----------|--------|----------|--------|
| Weighted average number of shares  outstanding, basic   |   | 35,765   |   | 52,298   |   | 49,503   |   |
| Dilutive effect of stock options                        |   | —   |   | 939      |   | 701      |   |
| Weighted average number of shares  outstanding, diluted |   | 35,765   |   | 53,237   |   | 50,204   |   |

 

At December31, 2003, there were no dilutive instruments outstanding.  The dilutive effect of stock options abovedid not include in 2002 2.8 million stock options and in 2001 1.3 million stockoptions because the respective exercise prices exceeded the average marketprice of the common shares during the year.

 

**13.****                              ****INCOME TAXES (RECOVERY)**

 

The provision for (recoveryof) income taxes has been computed as follows:

 
|                                                                                           |   | **2003** |   | **2002** |   | **2001** |   |
|------------------------------------------------------------------------------------------------|--------|----------|--------|----------|--------|----------|--------|
| *Income (loss) before income taxes*                                                            |   | $        | 19,539 |     | $      | 92,808   |   | $ | (237,306 | ) |
| *Expected income taxes at the statutory rate of 42.5% (2002 – 43.9%;  2001 – 44.0%)* |   | $        | 8,304  |     | $      | 40,743   |   | $ | (104,415 | ) |
| *Increase (decrease) in taxes resulting from:*                                                 |   |     |   |     |   |     |   |
| Crown royalties                                                                                |   | 15,954   |   | 21,153   |   | 19,870   |   |
| Resource allowance                                                                             |   | (18,334  | )      | (26,308  | )      | (22,560  | )      |
| Alberta royalty tax credit                                                                     |   | (213     | )      | (219     | )      | (224     | )      |
| Non-taxable portion of foreign exchange gain                                                   |   | (11,074  | )      | —   |   | —   |   |
| Rate change                                                                                    |   | (5,064   | )      | (138     | )      | 183      |   |
| Stock-based compensation                                                                       |   | 314      |   | —   |   | —   |   |
| Other                                                                                          |   | (1,387   | )      | 2,725    |   | (181     | )      |
| Large corporation tax and provincial capital tax                                               |   | 9,663    |   | 9,716    |   | 7,128    |   |
| Provision for (recovery of) income taxes                                                       |   | $        | (1,837 | )        | $      | 47,672   |   | $ | (100,199 | ) |

 

F-15

----

 

The components of future income taxes are as follows:

 
|                                   |   | **As  at December 31,** |    |
|----------------------------------------|--------|------------------------------|---------|
|                                   |   | **2003**                     |    | **2002** |   |
| Future income tax liabilities:         |   |                         |    |   |   |
| Capital assets                         |   | $                            | 202,657 |   | $ | 202,429 |   |
| Other                                  |   | 2,560                        |    | — |   |
| Future income tax assets:              |   |                         |    |   |   |
| Provision for  future site restoration |   | (8,907                       | )       | (9,638 | ) |
| Reorganization costs                   |   | (19,794                      | )       | (2,833 | ) |
| Loss carry-forward                     |   | —                       |    | (323 | ) |
| Other                                  |   | —                       |    | (5,233 | ) |
| Future income taxes                    |   | $                            | 176,516 |   | $ | 184,402 |   |

 

**14.****                              ****CASH FLOW INFORMATION**

 

***Increase(Decrease) in Non-Cash Working Capital Items***

 
|                 |   | **2003** |   | **2002** |   | **2001** |   |
|----------------------|--------|----------|--------|----------|--------|----------|--------|
| Current assets       |   | $        | (1,840 | )        | $      | 38,528   |   | $ | (23,440 | ) |
| Current  liabilities |   | 48,829   |   | 28,229   |   | (43,060  | )      |
|                 |   | $        | 46,989 |     | $      | 66,757   |   | $ | (66,500 | ) |

 
|                                            |   | **2003** |   | **2002** | ** ** | **2001** | ** ** |
|-------------------------------------------------|--------|----------|--------|----------|------------|----------|------------|
| Changes in non cash working capital related to: |   |     |   |     |       |     |       |
| Operating activities                            |   | $        | (7,828 | )        | $          | 1,272    |       | $ | 5,682 |   |
| Financing activities                            |   | 61,032   |   | —   |       | —   |       |
| Investing activities                            |   | (6,215   | )      | 65,485   |       | (72,182  | )          |
|                                            |   | $        | 46,989 |     | $          | 66,757   |       | $ | (66,500 | ) |

 

During the year the Company made the following cash outlays in respectof interest expense and current income taxes.

 
|                          |   | **2003** |   | **2002** |   | **2001** |   |
|-------------------------------|--------|----------|--------|----------|--------|----------|--------|
| Interest                      |   | $        | 24,449 |     | $      | 25,482   |   | $ | 22,889 |   |
| Current income taxes (refund) |   | $        | 12,557 |     | $      | (3,298   | )      | $ | (15,459 | ) |

 

**15.****                              ****FINANCIAL INSTRUMENTS**

 

The Company’s financial instruments recognized in the consolidatedbalance sheet consist of cash and cash equivalents accounts receivable, currentliabilities and long-term borrowings, and exchangeable shares.  The estimated fair values of the financialinstruments have been determined based on the Company’s assessment of availablemarket information and appropriate valuation methodologies; however, theseestimates may not necessarily be indicative of the amounts that could berealized or settled in a market transaction.

 

The fair values of financial instruments other than long-termborrowings approximate their carrying amounts due to the short-term maturity ofthese instruments.  At December 31,2003, the trading value of the Company’s senior subordinated term notes was 105percent in relation to par (2002- 105 percent).

 

F-16

----

 

**16.****                              ****DERIVATIVECONTRACTS**

 

The nature of the Company’s operations results in exposure tofluctuations 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-relatedlosses in the event of non-performance by counter-parties to thesecontracts.  In 2003, petroleum andnatural gas sales were reduced by $33.8 million (2002 - $8.3 million; 2001 -$9.5 million) due to derivative contracts.

 

At December 31, 2003, the Company had derivative contracts for thefollowing:

 
|         |   | **Period**     |   | **Volume**   |   | **Price**               |   | **Index** |   |
|--------------|--------|----------------|--------|--------------|--------|-------------------------|--------|-----------|--------|
| **Oil**      |   |           |   |         |   |                    |   |      |   |
| Price collar |   | Calendar  2004 |   | 5,000 bbls/d |   | US$24.00 – $28.60  |   | WTI       |   |
| Price collar |   | Calendar  2004 |   | 1,500 bbls/d |   | US$24.00 –  $29.05 |   | WTI       |   |
| Price collar |   | Calendar  2004 |   | 1,500 bbls/d |   | US$24.00 –  $29.08 |   | WTI       |   |
| Price collar |   | Calendar  2004 |   | 1,000 bbls/d |   | US$24.00 –  $29.38 |   | WTI       |   |
| Price collar |   | Calendar 2004  |   | 1,000 bbls/d |   | US$24.00 –  $29.48 |   | WTI       |   |
| Price collar |   | Calendar  2004 |   | 2,000 bbls/d |   | US$24.00 –  $30.55 |   | WTI       |   |
| Price collar |   | Calendar  2004 |   | 3,000 bbls/d |   | US$24.00 –  $32.05 |   | WTI       |   |

 

The fair value of the oil derivative contracts at December 31, 2003is an unrecognized liability of $13.8 million.

 
|                 |   |           |       |                    |       | **Exchange Rate** |       |
|----------------------|--------|----------------|------------|-------------------------|------------|-------------------|------------|
|                 |   | **Period**     | ** ** | **Amount**              | ** ** | **Floor**         | ** ** | **Cap** | ** ** |
| **Foreign currency** |   |           |       |                    |       |              |       |   |   |
| Collar               |   | Calendar  2004 |       | US$3,000,000  per month |       | CAD/USD  $1.3100  |       | CAD/USD  $1.3400 |   |
| Collar               |   | Calendar  2004 |       | US$3,000,000  per month |       | CAD/USD  $1.3280  |       | CAD/USD  $1.3560 |   |
| Collar               |   | Calendar  2004 |       | US$3,000,000  per month |       | CAD/USD  $1.3160  |       | CAD/USD  $1.3365 |   |
| Collar               |   | Calendar  2004 |       | US$3,000,000  per month |       | CAD/USD  $1.3400  |       | CAD/USD  $1.3665 |   |

 

The fair value of the foreign currency contracts at December 31,2003 is an unrecognized asset of $3.7 million.

 
|                   |   | **Period**                            |   | **Principal**  |   | **Rate**                 |   |
|------------------------|--------|---------------------------------------|--------|----------------|--------|--------------------------|--------|
| **Interest rate swap** |   |                                  |   |           |   |                     |   |
|                   |   | November 2003  to July 2010 |   | US$179,699,000 |   | 3-month  LIBOR plus 5.2% |   |

 

The fair value of the interest rate swap at December 31, 2003 isan unrecognized asset of $3.9 million.

 

**17.****                              ****COMMITMENTS AND CONTINGENCIES**

 

In October 2002, the Company enteredinto a long-term crude oil supply contract with a third party that requires thedelivery of up to 20,000 barrels per day of Lloydminster Blend crude oil at aprice fixed at 71% of NYMEX WTI oil price. The contract is for an initial term of five years commencingJanuary 1, 2003.  The contractvolumes increased from 9,000 barrels per day in January 2003 to 20,000barrels per day in October 2003 and thereafter.

 

For the period November 2003 to March 2004, the Company hasentered into natural gas physical sales contracts with third parties for atotal of 9.5 mmcf per day for prices collared between $5.28 and $8.57 per

 

F-17

----

 

mcf.  For the periodApril 2004 to October 2004, the Company has entered into natural gasphysical sales contracts with third parties for a total of 9.5 mmcf per day forprices collared between $4.75 and $6.75 per mcf.

 

The Company is engaged in litigation andclaims arising in the normal course of operations, none of which couldreasonably be expected to materially affect the Company’s financial position orreported results of operations.

 

Under the Net Profits Interests Agreementbetween the Company and the Trust, the Company will establish in 2004 areclamation fund to fund the payment of environmental and site restorationcosts.

 

**18.****                              ****RELATED PARTYTRANSACTIONS**

 

On September 2, 2003, the Company issued$527.4 million of unsecured, subordinated promissory notes to Baytex EnergyTrust.  The notes bear interest at 12percent payable monthly with principal repayable on September 1, 2033.  These notes are unsecured and aresubordinate to the Company’s bank credit facilities and senior subordinatednotes.

 

During 2003, the Company issued a total of$9.9 million of unsecured, subordinated promissory notes to ExchangeCo.  The notes bear interest at 12 percentpayable monthly with principal repayable on September 1, 2033.  These notes are unsecured and aresubordinate to the Company’s bank credit facilities and senior subordinatednotes.

 

On September 2, 2003, Baytex completed the Arrangement wherebyholders of common shares of Baytex elected or were deemed to have elected toreceive either Trust Units of the Trust or Exchangeable Shares of Baytex fortheir common shares on the basis of one Trust Unit or Exchangeable Share,respectively, for each common share held. Coincident with the Arrangementbecoming effective, certain of Baytex’s exploration assets were acquired byCrew, and the common shares of Crew were distributed to the former holders ofBaytex common shares on the basis of one-third of a common share of Crew foreach such share held.

 

Coincident with the Arrangement becoming effective, Baytex and theTrust entered into a Net Profits Interests Agreement, pursuant to which Baytexgranted and set over to the Trust the right to receive certain payments (the“NPI”) on petroleum and natural gas properties held by Baytex.

 

Pursuant to the terms of the NPI Agreement, the Trust is entitled to apayment from Baytex for each month equal to the amount by which ninety-ninepercent of the gross proceeds from the sale of production attributable to theproperties for such month exceed ninety-nine percent of certain deductiblecosts for such period.  Baytex mayacquire and fund additional properties from residual revenues, borrowings orfrom its working capital.

 

If Baytex wishes to dispose of any properties which will result in proceedsin excess of a threshold amount, the Board of Directors of Baytex shall approvesuch disposition; however, if the asset value (calculated in accordance withthe terms of the NPI Agreement) of any interests included in such dispositionis greater than a threshold percentage of the asset value of all the PropertyInterests held by Baytex, such disposition must be approved by a SpecialResolution of the unitholders.  The termof the NPI Agreement will be for so long as there are petroleum and natural gasrights to which the NPI applies.

 

F-18

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**19.****                              ****CORPORATE ACQUISITIONS**

 

Effective May 1, 2001, the Company acquired all of the issued andoutstanding shares of OGY Petroleums Ltd. (“OGY”), a public company involved inthe exploration, development and production of oil and natural gas in WesternCanada.  The acquisition has beenaccounted for by the purchase method of accounting as follows:

 
| **Consideration**                    |   |    |    |
|--------------------------------------|--------|---------|---------|
| Cash                                 |   | $       | 50,683  |   |
| Transaction costs                    |   | 3,100   |    |
|                                 |   | 53,783  |    |
| Issue of 1,169,481 common shares     |   | 14,057  |    |
|                                 |   | $       | 67,840  |   |
| **Net Assets Acquired**              |   |    |    |
| Petroleum and natural gas properties |   | $       | 116,607 |   |
| Future income taxes                  |   | (36,127 | )       |
| Future site restoration costs        |   | (1,844  | )       |
|                                 |   | 78,636  |    |
| Working capital deficiency           |   | (4,809  | )       |
| Long-term debt                       |   | (5,987  | )       |
|                                 |   | $       | 67,840  |   |

 

Effective June 1, 2001, the Company acquired all of the issued andoutstanding shares of Triumph Energy Corporation (“Triumph”), a public companyinvolved in the exploration, development and production of oil and natural gasin Western Canada.  The acquisition hasbeen accounted for by the purchase method of accounting as follows:

 
| **Consideration**                    |   |    |    |
|--------------------------------------|--------|---------|---------|
| Cash                                 |   | $       | 82,337  |   |
| Transaction costs                    |   | 11,306  |    |
|                                 |   | 93,643  |    |
| Issue of 4,949,245 common shares     |   | 54,047  |    |
|                                 |   | $       | 147,690 |   |
| **Net Assets Acquired**              |   |    |    |
| Petroleum and natural gas properties |   | $       | 248,480 |   |
| Future income taxes                  |   | (77,751 | )       |
| Future site restoration costs        |   | (213    | )       |
|                                 |   | 170,516 |    |
| Working capital                      |   | 7,543   |    |
| Long-term debt                       |   | (30,369 | )       |
|                                 |   | $       | 147,690 |   |

 

F-19

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**20.****                              ****DIFFERENCES BETWEEN CANADIAN AND UNITED STATESGENERALLY ACCEPTED ACCOUNTING PRINCIPLES**

 

The consolidated financial statements havebeen prepared in accordance with Canadian generally accepted accountingprinciples (“Canadian GAAP”), which in most respects, conform to generallyaccepted accounting principles in the United States of America (“U.S. GAAP”).The significant differences in those principles, as they apply to the Company,are as follows:

 

(a)                                  UnderU.S. GAAP, the carrying value of petroleum and natural gas properties andrelated facilities, net of deferred income taxes, is limited to the presentvalue of after tax future net revenue from proven reserves, discounted at 10percent, (based on prices and costs at the balance sheet date) plus the lowerof cost or fair value of unproven properties (“ceiling test”).  Under Canadian GAAP, this ceiling test iscalculated without application of a discount factor, but interest and general andadministrative expenses are deducted.

 

As a result of applying the U.S. GAAP ceilingtest in prior years, the Company recorded additional depletion of $340.7million before income tax.  AtDecember 31, 2001, the application of the full cost ceiling test underU.S. GAAP resulted in a write-down of capitalized costs of $234.6 million($131.4 million after tax).  Where theamount of a ceiling test write-down under Canadian GAAP differs from the amountof the write-down under U.S. GAAP, the charge for depletion and depreciationwill differ in subsequent years resulting in U.S. to Canadian GAAP differences.

 

(b)                                 TheFinancial Accounting Standards Board (“FASB”) has issued Statement of FinancialAccounting Standards No. 143, “Accounting for Asset Retirement Obligations”(“FAS 143”).  FAS 143 was adoptedprospectively on January 1, 2003 and requires liability recognition forretirement obligations associated with tangible long-lived assets.  The initial measurement of the assetretirement obligation is required to be at fair value.  The asset retirement cost equal to the fairvalue of the retirement obligation is to be capitalized as part of the cost ofthe related long-lived asset and amortized to expense over the useful life ofthe asset.  The liability accretes untilthe expected settlement of the retirement obligation.

 

This change in accounting policy has beenaccounted for as a cumulative effect adjustment in the consolidated statementof operations as a loss of $7.1 million, net of income taxes of $5.6 million.

 

The change in the asset retirement obligationsince January 1, 2003 is as follows:

 
| Asset retirement obligation January 1, 2003   |   | $      | 52,244 |   |
|----------------------------------------------------|--------|--------|--------|--------|
| Increase in retirement obligations                 |   | 4,010  |   |
| Abandonment expenditures                           |   | (880   | )      |
| Property disposition                               |   | (3,335 | )      |
| Accretion                                          |   | 3,957  |   |
| Asset retirement obligation December 31, 2003 |   | $      | 55,996 |   |

 

Prior to January 1, 2003, under U.S.GAAP, the provision for future site restoration costs is recorded as areduction of capital assets.  UnderCanadian GAAP, effective January 1, 2004, the Company will adopt new Canadianaccounting standards for accounting for asset retirement obligations which areexpected to eliminate this difference in future years.

 

(c)                                  FASB hasissued Statement of Financial Accounting Standards No. 123, “Accounting forStock-based Compensation” (“FAS 123”) which establishes financial accountingand reporting standards for stock-based employee compensation plans as well astransactions in which an entity issues its equity instruments to acquire

 

F-20

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goods or services from non-employees.  As permitted by the FAS 123, the Companyelected to follow the intrinsic value method of accounting for stock-basedcompensation arrangements, as provided for in Accounting Principles BoardOpinion 25 (“APB 25”), for all stock options issued by the Company to employeesbefore the effective date of the Plan of Arrangement.  Since all stock options were granted with exercise price equal tothe market price at the date of the grant, no compensation cost has been chargedto income at the time of the option grants. Had compensation cost for theCompany’s stock options been determined based on the fair market value at thegrant dates of the awards consistent with methodology prescribed by FAS 123,the net income (loss) and net income (loss) per unit for years endedDecember 31, 2003 and 2002 would have been the pro forma amounts indicatedbelow:

 
|                                          |   | **Year  Ended December 31** |    |
|-----------------------------------------------|--------|----------------------------------|---------|
|                                          |   | **2003**                         |    | **2002** |   | **2001** |   |
| Net income (loss) as reported under U.S. GAAP |   | $                                | (26,154 | ) | $ | 22,889 |   | $ | (124,963 | ) |
| Stock based compensation expense              |   | (5,522                           | )       | (612 | ) | (398 | ) |
| Pro forma                                     |   | $                                | (31,676 | ) | $ | 22,277 |   | $ | (125,361 | ) |
|                                          |   |                             |    |   |   |   |   |
| Net income (loss) per unit:                   |   |                             |    |   |   |   |   |
| Basic as reported                             |   | $                                | (0.73   | ) | $ | 0.44 |   | $ | (2.52 | ) |
| Pro forma                                     |   | $                                | (0.88   | ) | $ | 0.43 |   | $ | (2.53 | ) |
|                                          |   |                             |    |   |   |   |   |
| Diluted as reported                           |   | $                                | (0.73   | ) | $ | 0.43 |   | $ | (2.52 | ) |
| Pro forma                                     |   | $                                | (0.88   | ) | $ | 0.42 |   | $ | (2.52 | ) |

 

The weighted average fair market value ofstock options granted by the Company (before the effective date of the Plan ofArrangement) in 2003 was $4.21 per stock option (2002 - $3.65; 2001 -$2.46).  The fair value of the stockoptions granted was estimated on the grant date based on the Black-Scholesoption-pricing model using the following weighted average assumptions:

 
|                                                        |   | **Year  Ended December 31** |   |
|-------------------------------------------------------------|--------|----------------------------------|--------|
|                                                        |   | **2003**                         |   | **2002** |   | **2001** |   |
| Risk-free interest rate                                     |   | 4.5                              |   | 4.0 |   | 5.0 |   |
| Volatility in the price of the Company’s common shares |   | 52                               |   | 57 |   | 61 |   |
| Expected life (years)                                       |   | 4                                |   | 4 |   | 4 |   |
| Dividends paid                                              |   | Nil                              |   | Nil |   | nil |   |

 

APB 25 also requires recognition ofcompensation cost with respect to changes in intrinsic value for variableemployee stock compensation plans.  Asthe stock options granted by the Company were modified as part of the Plan ofArrangement, and in prior years certain stock options were repriced, themodified stock options are subject to variable plan accounting, which resultsin an increase of compensation cost of $12.0 million for the year endedDecember 31, 2003 (2002 – increase in compensation costs of $0.8 million;2003 – reduction on compensation costs of $0.8 million) for U.S. GAAP purposes.

 

After the effective date of the Plan ofArrangement, the Trust established a Trust Unit Incentive Right Plan to replacethe stock option plan of the Company. The Company’s employees are entitled to participate in the Trust UnitRights Incentive Plan. As the exercise price of the unit rights granted underthe plan is subject to downward revisions from time to time, the unit rightsplan is a variable compensation plan under U.S. GAAP.  Accordingly, compensation expense is determined as the excess ofthe market price over the exercise price at the end of each reporting periodand is recognized in income over the vesting period of the rights.  The

 

F-21

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accounting for compensation expense for theunit rights plan does not result in a difference between Canadian and U.S.GAAP.

 

(d)                                 TheCompany adopted the liability method of accounting for income taxes in 2000retroactively without restatement.  Theliability method of accounting for income taxes is similar to Statement ofFinancial Accounting Standards No. 109, which requires the use of the asset andliability method. The Canadian GAAP liability method requires the measurementof future income tax liabilities and assets using income tax rates that reflectenacted income tax rate reductions provided it is more likely than not that theCompany will be eligible for such rate reductions in the period of reversal.U.S. GAAP allows recording of such reductions only when claimed.

 

(e)                                  Statementof Financial Accounting Standards No. 133, “Accounting for Derivativeinstruments and Hedging Activities” (FAS 133), as modified by Statement No. 138“Accounting for Certain Derivative Instruments and Certain Hedging Activities”,establishes accounting and reporting standards requiring that every derivativeinstrument be recorded in the consolidated balance sheet as either an asset orliability measured at its fair value, and that change in the fair value berecognized currently in income unless specific hedge accounting criteria aremet.  This statement requires an entityto establish, at the inception of a hedge, the method it will use for assessingthe effectiveness of the hedging derivative and the measurement approach fordetermining the ineffective aspects of the hedge. Those methods must beconsistent with the entity’s approach to managing risk.  As hedge accounting was not applied to thefinancial derivative contracts, at December 31, 2003, the Company’sfinancial derivative instruments would be recorded as a liability on theconsolidated balance sheet at their fair value of $6.2 million (2002 – $14.3million; 2001 – an asset on the balance sheet of $12.9 million).  FAS 133 also requires that gain and losseson financial derivative instruments be included in the statement of operationswhen terminated prior to the completion of the contract.  As a result, $12.2 million realized on thetermination of interest rate swap derivative contracts would be included as anincrease of the net income for December 31, 2002.   The net loss under U.S. GAAP for the yearended December 31, 2001 was reduced by $18.7 million for the amountrealized on renegotiation of financial derivative contracts

 

(f)                                    Theincome tax effect of the items noted in (a) through (e) for the year endedDecember 31, 2003 is a decrease in income taxes of $21.0 million (2002 –decrease of $15.9 million).

 

(g)                                 Prior toJanuary 1, 2000, the Company recorded the renouncement of tax deductionsresulting from the issuance of flow through shares by reducing petroleum andnatural gas properties and shareholders’ equity by the estimated cost of thetax deductions renounced.  U.S. GAAPrequires that flow-though shares be recorded at their fair value without anyadjustment for the renouncement of tax deductions and that the estimated costsfor the tax deductions be recorded as a future income tax liability rather thana reduction of petroleum and natural gas properties.  Subsequent to January 1, 2000, no differences arose in theaccounting treatment of flowthrough shares under Canadian GAAP and U.S. GAAP.

 

(h)                                 EffectiveJanuary 1, 2002, the Company retroactively adopted the Canadian Instituteof Chartered Accountants (CICA) amended accounting standard with respect toaccounting for foreign currency translation. As a result of the amendments, all exchange gains and losses onlong-term monetary items that do not qualify for hedge accounting arerecognized in income.  Previously underCanadian GAAP, these exchange gains and losses were deferred and amortized overthe remaining life of the monetary item. The effect of this change is to make the accounting for exchange gainsand losses on foreign denominated long-term monetary items consistent underboth Canadian GAAP and U.S. GAAP.  TheU.S. GAAP reconciliation for the years presented have been retroactivelyrestated as there is no longer a difference in accounting principles.

 

F-22

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(i)                                     Statementof Financial Accounting Standards No. 130 “Comprehensive Income” requires thereporting of comprehensive income in addition to net income. Comprehensiveincome includes net income plus other comprehensive income. Management believesthat it has no other comprehensive income; accordingly comprehensive income isequivalent to net income.

 

**Consolidated Statements of Operations**

 

The application of U.S. GAAP would have thefollowing effect on net income as reported:

 
|                                                                                                                                   |   | **Years  Ended December 31** |    |
|----------------------------------------------------------------------------------------------------------------------------------------|--------|-----------------------------------|---------|
|                                                                                                                                   |   | **2003**                          |    | **2002** |   | **2001** |   |
| Net income (loss) for the year – Canadian GAAP                                                                                    |   | $                                 | 21,376  |   | $ | 45,136 |   | $ | (137,107 | ) |
| Adjustments:                                                                                                                           |   |                              |    |   |   |   |   |
| Depletion (a)                                                                                                                          |   | (41,386                           | )       | (2,613 | ) | (11,041 | ) |
| Ceiling test write-down (a)                                                                                                            |   | —                            |    | — |   | (266 | ) |
| Accretion (b)                                                                                                                          |   | (3,957                            | )       | — |   | — |   |
| Compensation cost (c)                                                                                                                  |   | (11,972                           | )       | (1,873 | ) | 787 |   |
| Deferred revenue (e)                                                                                                                   |   | —                            |    | (18,694 | ) | 18,694 |   |
| Interest rate swaps (e)                                                                                                                |   | (12,181                           | )       | 12,181 |   | — |   |
| Financial derivative instruments (e)                                                                                                   |   | 8,109                             |    | (27,193 | ) | 12,893 |   |
| Income taxes (f)                                                                                                                       |   | 21,006                            |    | 15,945 |   | (8,923 | ) |
| Net income (loss) from continuing operations before cumulative effect  of change in accounting policy for asset retirement obligations |   | (19,005                           | )       | 22,889 |   | (124,963 | ) |
| Cumulative effect of change in accounting policy for asset retirement  obligations (b)                                                 |   | (7,149                            | )       | — |   | — |   |
| Net income (loss) for the year – U.S. GAAP                                                                                        |   | $                                 | (26,154 | ) | $ | 22,889 |   | $ | (124,963 | ) |

 
| Net income (loss) from continuing operations before cumulative effect  of change in accounting policy for asset retirement obligations per share |   |   |   |   |   |   |   |
|--------------------------------------------------------------------------------------------------------------------------------------------------|--------|--------|--------|--------|--------|--------|--------|
| Basic                                                                                                                                            |   | $      | (0.53  | )      | $      | 0.44   |   | $ | (2.52 | ) |
| Diluted                                                                                                                                          |   | $      | (0.53  | )      | $      | 0.43   |   | $ | (2.52 | ) |
|                                                                                                                                             |   |   |   |   |   |   |   |
| Net income (loss) per share – U.S. GAAP                                                                                                     |   |   |   |   |   |   |   |
| Basic                                                                                                                                            |   | $      | (0.73  | )      | $      | 0.44   |   | $ | (2.52 | ) |
| Diluted                                                                                                                                          |   | $      | (0.73  | )      | $      | 0.43   |   | $ | (2.52 | ) |

 

F-23

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**Consolidated Balance Sheets**

 

The application of U.S. GAAP would have thefollowing effect on the consolidated balance sheets as reported:

 
|                                     |   | **December 31,  2003** |    |
|------------------------------------------|--------|-----------------------------|---------|
|                                     |   | **As  Reported**            |    | **Increase  (Decrease)** |   | **U.S.  GAAP** |   |
| Assets:                                  |   |                        |    |   |   |   |   |
| Capital assets (a)                       |   | $                           | 748,988 |   | $ | (161,477 | ) | $ | 603,075 |   |
| (b)                                      |   |                        |    | 15,564 |   |   |   |
|                                     |   |                        |    |   |   |   |   |
| Liabilities:                             |   |                        |    |   |   |   |   |
| Asset retirement obligations (b)         |   | —                      |    | 55,996 |   | 55,996 |   |
| Provision for site restoration costs (b) |   | 23,483                      |    | (23,483 | ) | — |   |
| Financial derivative instruments (e)     |   | —                      |    | 6,191 |   | 6,191 |   |
| Future income taxes (f)                  |   | 176,516                     |    | (70,961 | ) | 105,555 |   |
|                                     |   |                        |    |   |   |   |   |
| Shareholders’ equity:               |   |                        |    |   |   |   |   |
| Deficit – see below                 |   | (288,770                    | )       | (148,972 | ) | (437,742 | ) |
|                                          |        |                             |         |  |  |  |  |  |  |  |

 
|                                     |   | **December 31,  2002** |    |
|------------------------------------------|--------|-----------------------------|---------|
|                                     |   | **As  Reported**            |    | **Increase  (Decrease)** |   | **U.S.  GAAP** |   |
| Assets:                                  |   |                        |    |   |   |   |   |
| Capital assets (a)                       |   | $                           | 932,316 |   | $ | (120,091 | ) | $ | 790,275 |   |
| (b)                                      |   |                        |    | (21,950 | ) |   |   |
|                                     |   |                        |    |   |   |   |   |
| Liabilities:                             |   |                        |    |   |   |   |   |
| Provision for site restoration costs (b) |   | 21,950                      |    | (21,950 | ) | — |   |
| Financial derivative instruments (e)     |   | —                      |    | 14,300 |   | 14,300 |   |
| Future income taxes (f)                  |   | 184,402                     |    | (57,398 | ) | 127,004 |   |
| Deferred credits (e)                     |   | 12,181                      |    | (12,181 | ) | — |   |
|                                     |   |                        |    |   |   |   |   |
| Shareholders’ equity:               |   |                        |    |   |   |   |   |
| Shareholders’ capital (g)           |   | 398,176                     |    | 13,942 |   | 412,118 |   |
| Deficit – see below                 |   | (38,489                     | )       | (87,500 | ) | (125,989 | ) |
|                                          |        |                             |         |  |  |  |  |  |  |  |

 

F-24

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|                                                                                  |   | **December 31,** |     |
|---------------------------------------------------------------------------------------|--------|-----------------------|----------|
|                                                                                  |   | **2003**              |     | **2002** |   |
| Deficit - Canadian GAAP                                                               |   | $                     | (288,770 | ) | $ | (38,489 | ) |
| Adjustments to depletion (a)                                                          |   | (169,549              | )        | (128,163 | ) |
| Flow through share differences (g)                                                    |   | (13,942               | )        | (13,942 | ) |
| Accretion expense (b)                                                                 |   | (3,957                | )        | — |   |
| Compensation expense (c)                                                              |   | (13,845               | )        | (1,873 | ) |
| Financial derivative instruments (e)                                                  |   | (6,191                | )        | (14,300 | ) |
| Deferred credits (e)                                                                  |   | —                |     | 12,181 |   |
| Adjustments to future income taxes (f)                                                |   | 79,603                |     | 58,597 |   |
| Shareholders’ Capital (g)                                                        |   | (13,942               | )        | — |   |
| Cumulative effect of change in accounting policy for asset retirement  obligation (b) |   | (7,149                | )        | — |   |
| Deficit - U.S. GAAP                                                                   |   | $                     | (437,742 | ) | $ | (125,989 | ) |

 

**Consolidated Statements of Cash Flow**

 

The application of U.S. GAAP would have thefollowing effect on the operating activities of the consolidated statement ofcash flow:

 
|                                                                 |   | **Years  Ended December 31** |    |
|----------------------------------------------------------------------|--------|-----------------------------------|---------|
|                                                                 |   | **2003**                          |    | **2002** |   | **2001** |   |
| ***Operating  activities***                                          |   |                              |    |   |   |   |   |
| Cash provided by (used in) operating activities – Canadian GAAP |   | $                                 | 104,405 |   | $ | 172,607 |   | $ | 168,446 |   |
| Adjustments:                                                         |   |                              |    |   |   |   |   |
| Deferred revenue (e)                                                 |   | —                            |    | (18,694 | ) | 18,694 |   |
| Interest rate swaps (e)                                              |   | (12,181                           | )       | 12,181 |   | — |   |
| Cash provided by (used in) operating activities – U.S. GAAP     |   | $                                 | 92,224  |   | $ | 166,094 |   | $ | 187,140 |   |

 

**Consolidated Statements of Cash Flows**

 

The consolidated statements of cash flowsincludes, under investing activities, items not affecting cash, related to thenon-cash elements of corporate acquisitions. This disclosure is provided in order to disclose the aggregate costsrelated to such activities and to then deduct the related non-cash amounts toarrive at cash amounts.  Thispresentation is not permitted under U.S. GAAP.

 

F-25

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**Recent Developments in U.S. Accounting**

 

In May 2003, the Financial AccountingStandards Board (FASB) issued Statement of Financial Accounting StandardsNo.150 “Accounting for Certain Financial Instruments with Characteristics ofLiabilities and Equity”, which establishes standards for classification andmeasurement of certain financial instruments. The adoption of this accounting standard did not have a material impacton the Company.

 

In January 2003, the FASB issuedInterpretation No. 46 “Consolidation of Variable Interest Entities” (“FIN46”).  FIN 46 provides criteria foridentifying variable interest entities and for determining what entity, if any,should be included in consolidated financial statements.  In December 2003, the FASB issued FIN46(R) to clarify some of the provisions of FIN 46 and to exempt certainentities from its requirements.  Theadoption on January 1, 2004 of this accounting standard is not anticipatedto have a material impact on the Company.

 

In December 2003, the Securities andExchange Commission issued Staff Accounting Bulletin No. 104 “RevenueRecognition” (“SAB 104”), which will rescind accounting guidance contained inStaff Accounting Bulletin No. 101 related to multiple element revenuearrangements.  The changes noted in SAB104 are not anticipated to have a material impact on the Company’s financialposition, results of operations or cash flows.

 

**21.          RECENT DEVELOPMENTS INCANADIAN ACCOUNTING**

 

In November 2002, the CanadianInstitute of Chartered Accountants (CICA) amended its accounting guideline onhedging relationships, which was originally issued in November 2001.  The guideline addresses the identification,designation, documentation and effectiveness of hedging transactions for thepurposes of applying hedge accounting. It also establishes conditions for applying or discontinuing hedgeaccounting.  Under the new guideline,hedging transactions must be documented and it must be demonstrated that thehedges are sufficiently effective to continue accrual accounting for positionshedged with derivatives.  The newguidline is effective for fiscal years, beginning on or after July 1,2003.  As of January 1, 2004, the companyhas recorded as a deferred charge the unrealized loss of $10.1 million for themark-to-market value of the outstanding non-hedging financial derivatives.  This balance is being recognized over theterm of the previously designated hedged item.

 

Baytex has elected to prospectively adopt amendments to CICA HandbookSection 3870, “Stock-based Compensation and Other Stock-based Payments”,pursuant to the transitional provisions contained therein.  Under this amended standard, Baytex isrequired to account for compensation expense based on the fair value of rightsgranted under its unit-based compensation plan.  As Baytex is unable to determine the fair value of the rightsgranted, compensation expense has been determined based on the intrinsic valueof the rights at the exercise date or at the date of the financial statementsfor unexercised rights.  Compensationexpense of $0.22 million was recorded as compensation expense for all trustunit rights granted on or after January 1, 2003, with a correspondingamount recorded as contributed surplus.

 

The adoption of these amendments also impacted the stock optionsoutstanding prior to the Plan of Arrangement. Compensation expense of $0.52 million was recorded as compensationexpense for all stock options granted on or after January 1, 2003, with acorresponding amount recorded as contributed surplus.  For stock options granted prior to January 1, 2003, the proforma earnings impact of related stock-based compensation expense is disclosedin note 11 of the consolidated financial statements.

 

In March 2003, the CICA issued Section 3110, “AssetRetirement Obligations”.  Thissection requires recognition of a liability at discounted fair value forthe future abandonment and reclamation associated with the petroleum andnatural gas properties.  The fair valueof the liability is capitalized as part of the cost of the related asset andamortized to expense over its useful life. The liability accretes until the date of expected settlement of theretirement obligations.  The newstandard is effective for all fiscal years beginning on or afterJanuary 1, 2004.  The impact of theadoption of this standard is estimated to be an increase in asset retirementobligation on the balance sheet of $33 million at December 31, 2003.

 

In February 2003, theCICA issued Accounting Guideline 14, “Disclosure of Guarantees” (“AcG-14”).AcG-14 establishes the disclosures required for obligations under certainguarantees.  The disclosure requirementsare effective for interim and annual periods beginning on or afterJanuary 1, 2003 and have been made in note 17 of the consolidatedfinancial statements.

 

In 2003, the CICA issued Accounting Guideline 16, “Oil and GasAccounting – Full Cost” (“AcG-16”).  Theguideline is effective for fiscal years beginning on or after January 1,2004.  The new guideline proposesamendments to the ceiling test calculation applied by Baytex.  The ceiling test was changed to a two-stageprocess which is to be performed at least annually.  The first stage of the test is a recognition test which comparesthe undiscounted future cash flow from proved reserves to the net book value ofthe petroleum and natural gas assets to determine if the assets areimpaired.  An impairment loss existswhen the carrying amount of the petroleum and natural gas assets exceeds suchundiscounted cash flow.  The secondstage determines the amount of the impairment loss to be recorded.  The impairment is measured as the amount bywhich the net book value of the petroleum and natural gas assets exceeds thefuture discounted cash flow from proved plus probable reserves.  The adoption of this new guideline onJanuary 1, 2004 is not anticipated to have an impact on the financialresults of Baytex.

 

On November 10, 2003, the CICA issued a draft EIC (D37) on “IncomeTrusts - Exchangeable Units”. The EIC proposes that the retained interest ofthe exchangeable shareholders should be presented on the balance sheet as anon-controlling interest separate and distinct from unitholder’s equity. Thisdraft EIC is currently under review and was not enacted in final form as of thetime of release of Baytex’s consolidated financial statements.

 

In June 2003 the CICAissued Accounting Guideline 15 “Consolidation of Variable Interest Entities”,which deals with the consolidation of entities that are subject to control on abasis other than ownership of voting interests.  This guideline is effective for annual and interim periodsbeginning on or after November 1, 2004. Baytex has assessed that this newguideline is not applicable based on the current structure of Baytex andtherefore will have no impact on the financial statements of Baytex.

 

F-26

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