Baytex Energy 40F 2004 Annual report | BTE Filing

Exhibit 99.1

BAYTEX ENERGY TRUST

RENEWAL ANNUAL INFORMATION FORM

2004

March 21, 2005

GLOSSARY OF TERMS

Capitalized terms in this Annual Information Form have the meanings set forth below:

Entities

Baytex, the Corporation or the Company means Bayex Energy Ltd.;

Baytex ExchangeCo means Baytex ExchangeCo Ltd.;

Board of Directors means the board of directors of Baytex;

Crew means Crew Energy Inc;

Trust, we, us or our means Baytex Energy Trust and all its controlled entities on a consolidated basis;

Trustee means Valiant Trust Company our trustee; and

Unitholders means holders of our Trust Units.

Independent Engineering

Sproule means Sproule Associates Limited, independent petroleum consultants of Calgary, Alberta;

Sproule Report means the report dated February 28, 2005 entitled “Evaluation of the P&NG Reserves of Baytex Energy Trust as of December 31, 2004; and

NI 51-101 means National Instrument 51-101 Standards of Disclosure for Oil and Natural Gas Activities.

Securities

DRIP Plan means our distribution reinvestment plan

Exchangeable Shares means the exchangeable shares of Baytex which are exchangeable for Trust Units;

Exchange Ratio means the ratio at which Exchangeable Shares may be converted to Trust Units;

Notes means the 12% unsecured subordinated promissory notes issued by Baytex and held by us pursuant to the plan of arrangement completed on September 2, 2003 and other promissory notes issued by Baytex or any of our subsidiaries or affiliates to us from time to time;

Note Indenture means the note indenture relating to the issuance of the Notes;

NPI means the net profit interest in the petroleum substances owned by Baytex held by us;

“NPI Agreement” means the net profit interest agreement, as amended and restated, between Baytex and the Trust providing for the creation of the NPI;

Special Voting Right means the special voting rights issued by us entitling holders of Exchangeable Shares to voting rights at meetings of Unitholders;

Support Agreement means the support agreement between us, Baytex, Baytex ExchangeCo and Valiant Trust Company;

Trust Indenture means the amended and restated trust indenture between us and Baytex made as of September 2, 2003;

Trust Unit means a unit issued by us, each unit representing an equal undivided beneficial interest in our assets.

Trust Unit Rights Incentive Plan means our trust unit rights incentive plan; and

Voting and Exchange Trust Agreement means the voting and exchange trust agreement entered into on September 2, 2003 between us, Baytex ExchangeCo and Valiant Trust Company.

ABBREVIATIONS

Oil and Natural Gas Liquids

Bbl		Barrel
Mbbl		thousand barrels
Mmbbl		million barrels
NGLs		natural gas liquids
Stb		stock tank barrels of oil
Mstb		thousand stock tank barrels of oil
Bbl/d		barrels per day

Natural Gas

Mcf		thousand cubic feet
Mmcf		million cubic feet
Bcf		billion cubic feet
Mcf/d		thousand cubic feet per day
Mmcf/d		million cubic feet per day
m³		cubic metres
Mmbtu		million British Thermal Units
GJ		Gigajoule

Other

BOE or boe		barrel of oil equivalent, using the conversion factor of 6 Mcf of natural gas being equivalent to one bbl of oil. BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 Mcf: 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
Mboe		thousand barrels of oil equivalent
Mmboe		million barrels of oil equivalent
Boe/d		barrels of oil equivalent per day
WTI		West Texas Intermediate.
API		the measure of the density or gravity of liquid petroleum products derived from a specific gravity.
Psi		means pounds per square inch.

CONVERSIONS

The following table sets forth certain conversions between Standard Imperial Units and the International System of Units (or metric units).

To Convert From	To	Multiply By

Mcf	cubic metres	28.174
cubic metres	cubic feet	35.494
Bbl	cubic metres	0.159
cubic metres	Bbl	6.289
Feet	Metres	0.305
Metres	Feet	3.281
Miles	Kilometres	1.609
Kilometres	Miles	0.621
Acres	Hectares	0.405
Hectares	Acres	2.471
Gigajoules	Mmbtu	0.950

CONVENTIONS

Certain terms used herein are defined in NI 51-101 and, unless the context otherwise requires, shall have the same meanings in this Annual Information Form as in NI 51-101. Unless otherwise indicated, references in this Annual Information Form to “$” or “dollars” are to Canadian dollars. All financial information contained in this Annual Information Form has been presented in Canadian dollars in accordance with generally accepted accounting principles in Canada. Words importing the singular number only include the plural, and vice versa, and words importing any gender include all genders. All operational information contained in this Annual Information Form relates to our consolidated operations unless the context otherwise requires.

SPECIAL NOTE REGARDING FORWARD LOOKING STATEMENTS

Certain statements contained in this Annual Information Form, and in certain documents incorporated by reference into this Annual Information Form, constitute forward-looking statements. These statements relate to future events or our future performance. All statements other than statements of historical fact are forward-looking statements. The use of any of the words “anticipate”, “plan”, “continue”, “estimate”, “expect”, “may”, “will”, “project”, “predict”, “potential”, “should”, “believe” and similar expressions are intended to identify forward-looking statements. These statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements. We believe the expectations reflected in those forward-looking statements are reasonable but no assurance can be given that these expectations will prove to be correct and such forward-looking statements included in, or incorporated by reference into, this Annual Information Form should not be unduly relied upon. These statements speak only as of the date of this Annual Information Form or as of the date specified in the documents incorporated by reference into this Annual Information Form, as the case may be.

In particular, this Annual Information Form, and the documents incorporated by reference, contain forward-looking statements pertaining to the following:

• the performance characteristics of our oil and natural gas assets;

• oil and natural gas production levels;

• the size of the oil and natural gas reserves;

• projections of market prices and costs and the related sensitivities of distributions;

• supply and demand for oil and natural gas;

• expectations regarding our ability to raise capital and to continually add to reserves through acquisitions and development;

• treatment under governmental regulatory regimes;

• capital expenditure programs;

• the existence, operation and strategy of our commodity price risk management program;

• the approximate and maximum amount of forward sales and hedging to be employed by us;

• our acquisition strategy, the criteria to be considered in connection therewith and the benefits to be derived there from;

• the impact of Canadian federal and provincial governmental regulation on us relative to other oil and gas issuers of similar size;

• the goal to grow or sustain production and reserves through prudent management and acquisitions;

• the emergence of a creed of growth opportunities; and

• our ability to benefit from the combination of growth opportunities and the ability to grow through capital markets.

The actual results could differ materially from those anticipated in these forward-looking statements as a result of the risk factors set forth below and elsewhere in this Annual Information Form, and in certain documents incorporated by reference into this Annual Information Form:

• volatility in market prices for oil and natural gas;

• liabilities inherent in oil and natural gas operations;

• uncertainties associated with estimating oil and natural gas reserves;

• competition for, among other things, capital, acquisitions of reserves, undeveloped lands and skilled personnel;

• incorrect assessments of the value of acquisitions;

• geological, technical, drilling and processing problems; and

• the other factors discussed under “Risk Factors”.

Statements relating to “reserves” or “resources” are deemed to be forward-looking statements, as they involve the implied assessment, based on current estimates and assumptions that the resources and reserves described can be profitably produced in the future. The foregoing lists of factors are not exhaustive. The forward-looking statements contained in this Annual Information Form and the documents incorporated by reference herein are expressly qualified by this cautionary statement. We do not undertake any obligation to publicly update or revise any forward-looking statements. See “Risk Factors”.

BAYTEX ENERGY TRUST

General

We are an open-end unincorporated investment trust governed by the laws of the Province of Alberta and created pursuant to the Trust Indenture. Our head and principal office is located at Suite 2200, 205 - 5th Avenue S.W., Calgary, Alberta, T2P 2V7.

We were formed on July 24, 2003 and commenced operations on September 2, 2003 as a result of the completion of a plan of arrangement under the Business Corporations Act (Alberta) on September 2, 2003 involving us, Baytex, Crew, Baytex Acquisition Corp., Baytex ExchangeCo, Baytex Resources Ltd. and Baytex Exploration Ltd. Pursuant to the plan of arrangement, former holders of common shares of Baytex received common shares of Crew and Trust Units or Exchangeable Shares, or a combination thereof, in accordance with the elections made by such shareholders, and Baytex became a subsidiary of the Trust.

Inter-Corporate Relationships

The following table provides the name, the percentage of voting securities owned by us and the jurisdiction of incorporation, continuance or formation of our subsidiaries either, direct and indirect, as at the date hereof.

	Percentage of voting securities (directly or indirectly)		Jurisdiction of Incorporation/ Formation
Baytex Energy Ltd.	100	%	Alberta
Baytex ExchangeCo Ltd.	100	%	Alberta
Baytex Marketing Ltd.	100	%	Alberta
Baytex Energy (USA) Ltd.	100	%	Delaware

Our Organizational Structure

The following diagram describes the inter-corporate relationships among us and our material subsidiaries as well as the flow of cash from the oil and gas properties held by such subsidiaries to us and from us to Unitholders.

Notes:

(1) Unitholders own 100% of our equity.

(2) Baytex has a total of 1,876,004 Exchangeable Shares issued and outstanding as at December 31, 2004.

(3) Cash distributions are made on a monthly basis to Unitholders based upon our cash flow. Our primary sources of cash flow are NPI payments from Baytex and interest on the principal amount of the Notes. In addition to such amounts, prepayments in respect of principal on the Notes may be made from time to time to us before the maturity of the Notes.

GENERAL DEVELOPMENT OF OUR BUSINESS

History and Development

In October 2002, Baytex signed a five-year crude oil supply agreement with a U.S. based refining company. This agreement calls for the delivery, beginning in January 2003, of up to 20,000 bbl/d of Lloyd Blend oil production at a fixed differential of 29 percent of the West Texas Intermediate price. This pricing arrangement effectively removes the additional pricing volatility associated with heavy oil on two-thirds of our heavy oil production. This contract forms part of our risk management program and should help to reduce the impact on our cash flow from dramatic swings in commodity prices in the future.

On September 2, 2003, we completed a plan of arrangement under the Business Corporations Act (Alberta) involving Baytex, Crew, Baytex Acquisition Corp., Baytex ExchangeCo, Baytex Resources Ltd., Baytex Exploration Ltd. and us pursuant to which former holders of common shares of Baytex received common shares of Crew and Trust Units or Exchangeable Shares, or a combination thereof, in accordance with the elections made by such shareholders, and Baytex became a subsidiary of the Trust. Coincident with the plan of arrangement becoming effective, certain of Baytex’s exploration assets were acquired by Crew, and the common shares of Crew were distributed to the former holders of Baytex common shares on the basis of one-third of a common share of Crew for each such share held. The estimated fair market value at September 2, 2003 of the securities issued pursuant to the reorganization was $11.76 per Trust Unit and $0.55 per one-third of a common share of Crew.

On December 12, 2003 we completed a public offering of 6,500,000 Trust Units at a price of $10.00 per Trust Unit for gross proceeds of $65,000,000. The net proceeds of the offering were used to fund our ongoing capital expenditure and acquisition program.

On September 22, 2004, we completed the acquisition of a Calgary based private oil and gas company, for cash consideration of $109 million before adjustments. The acquisition was financed with Baytex’s credit facilities and added approximately 3,000 boe/d of 65% gas weighted production. The assets acquired were located in two geographically focused areas of southern Alberta, Sedalia/Garden Plains and Turin/Parkland, and also included 110,000 net acres of undeveloped land. Production from this acquisition represented approximately 9.3% of our pre-transaction production. Ninety-five percent of the production was from operated, high working interest properties with ownership and control of most key facilities and infrastructure within the operating areas. This acquisition added a significant inventory of drilling opportunities including low risk development and medium risk exploration to our light oil and natural gas portfolio. Opportunities also exist for re-entries, recompletions, tie-ins and workovers. Subsequent to the acquisition, the private company was amalgamated into Baytex.

On October 18, 2004, we implemented our DRIP Plan which provides eligible Unitholders the advantage of accumulating additional Trust Units by reinvesting their cash distributions paid by us. The cash distributions are reinvested at our discretion, either by acquiring Trust Units issued from treasury at 95% of the “Average Market Price” (which is defined in the DRIP Plan as the average trading price of the Trust Units on the Toronto Stock Exchange for the period commencing on the second business day after the distribution record date and ending on the second business day immediately prior to the distribution payment date, such period not to exceed 20 trading days) or by acquiring Trust Units at prevailing market rates. No commissions, service charges or brokerage fees are payable by participants in connection with Trust Units acquired under the DRIP Plan. The DRIP Plan is presently available to Canadian Unitholders only. Residents of the United States may not participate in the DRIP Plan at this time.

On December 20, 2004 we completed a public offering of 3,600,000 Trust Units at a price of $12.80 per Trust Unit for gross proceeds of $46,080,000. The net proceeds of the offering were used to repay outstanding bank indebtedness.

On December 22, 2004, we completed the acquisition of certain strategic oil and natural gas interests in the West Stoddart area of northeast British Columbia for $90 million before adjustments. The assets acquired consisted of approximately 3,300 boe/d of primarily high netback liquids-rich natural gas production comprised of 10.0 mmcf/d of natural gas, 1,300 bbl/d of NGL’s and 330 bbl/d of light oil. Production from this acquisition represented approximately 9.6% of our existing production. Production was mainly from three year round access properties near Fort St. John, British Columbia (West Stoddart, North Cache and Cache Creek). The primary producing zones are the Doig, Halfway, Charlie Lake, Baldonnel and Cretaceous zones. The assets represent a new core area for us and are 100% operated with an average working interest of 91%. The acquisition also included an identified project inventory including drilling, recompletions, fracture stimulation and well optimizations and approximately 17,000 net acres of undeveloped land contiguous to the principal producing properties.

Trends

There are a number of trends in the oil and gas industry that are shaping the near term future of our business. One trend has been the continuation of oil and gas companies converting to royalty trusts. These conversions occur because the equity markets generally value trusts at higher multiples than exploration and development firms.

Efforts of trusts to replace annual production declines have resulted in continued high levels of competition for the acquisition of oil and natural gas properties and related assets. This increased competition has raised valuation parameters for corporate and asset acquisitions. Those trusts with opportunities to economically replace production through internal development drilling should be in a favourable position relative to those more exposed to replacing production through acquisitions.

Another trend is the continuing volatility of commodity prices. World oil inventories experienced a significant drawdown in 2004 and the rate of recovery will largely be dependent on weather, Iraq’s export recovery, middle-eastern conflict, and OPEC’s discipline. As long as inventories remain low, the high crude oil prices the industry experienced over the past year could continue. Natural gas inventories are at more normal levels; however, natural gas prices tend to be more volatile than oil prices due to supply and demand factors within North America. As weather is a key factor in determining gas demand, future gas prices are highly unpredictable.

Although commodity prices are higher than historical levels, the appreciation of the Canadian dollar in 2003 and 2004 relative to its US counterpart has offset a portion of the economic benefit of higher prices on Canadian oil and gas producers including trusts. Any further strengthening of the Canadian dollar may result in decreased revenue and affect the royalty trusts’ ability to maintain current distribution levels.

DESCRIPTION OF OUR BUSINESS AND OPERATIONS

Baytex Energy Trust

We are an open-end unincorporated investment trust governed by the laws of the Province of Alberta and created pursuant to the Trust Indenture. We were established to, among other things:

• invest in shares of Baytex and acquire the common shares of Baytex and the Notes pursuant to the plan of arrangement which was completed on September 2, 2003;

• acquire the NPI under the NPI Agreement;

• acquire or invest in other securities of Baytex and in the securities of any other entity including without limitation bodies corporate, partnerships or trusts, and borrowing funds or otherwise obtaining credit for that purpose;

• dispose of any part of the property of the Trust, including, without limitation, any securities of Baytex;

• temporarily hold cash and investments for the purposes of paying the expenses and the liabilities of the Trust, making other permitted investments under the Trust Indenture, pay amounts payable by the Trust in connection with the redemption of any Trust Units, and make distributions to Unitholders; and

• pay costs, fees and expenses associated with the foregoing purposes or incidental thereto.

We are prohibited from acquiring any investment which (a) would result in the cost amount to us of all “foreign property”(as defined in the Income Tax Act (Canada)) which is held by us to exceed the amount prescribed by applicable tax laws or (b) would result in us not being considered either a “unit trust” or a “mutual fund trust” for purposes of the Income Tax Act (Canada).

Our principal undertaking is to issue Trust Units and other securities and to acquire and hold royalties and other interests. Baytex carries on the business of acquiring and holding interests in oil and natural gas properties and assets related thereto. Cash flow from these properties is flowed from Baytex to us by way of interest payments and principal repayments on the Notes and through NPI payments.

The Trustee may declare payable to Unitholders all or any part of our income. Currently the only income we receive is from the interest and principal payments received on the Notes and NPI payments. We make monthly cash distributions to Unitholders on our income, after expenses, if any, and any cash redemptions of Trust Units.

Cash distributions are made on the 15^th day (or if such date is not a business day, on the next business day) following the end of each calendar month to Unitholders of record on or about the last business day of each such calendar month.

Our current distribution policy permits us to use between 30% and 40% of our available cash for capital expenditures to fund both exploration and development expenditures and minor property acquisitions, but excluding major acquisitions. Baytex’s senior subordinated notes also contain certain limitations on maximum cumulative distributions. Restricted payments include the declaration or payment of any dividend or distribution to us and the payment of interest or principal on subordinated debt owed to us. Baytex is restricted from making any restricted payments, including distributions to us, if a default or event of default under the note indenture has occurred and is continuing. If no such default or event of default has occurred and is continuing, Baytex may make a distribution to us provided at the time either (A) (i) its ratio of consolidated debt to consolidated cash flow from operations does not exceed 3 to 1, (ii) its fixed charge coverage ratio for the preceding four fiscal quarters is greater than 2.5 to 1 and (iii) the aggregate of all restricted payments declared or made after July 9, 2003 does not exceed the sum of 80% of the consolidated cash flow from operations accrued on a cumulative basis since July 9, 2003 plus the net cash proceeds received by Baytex from the issuance of deeply subordinated intercompany debt or the receipt of capital contributions from the Trust plus net proceeds received by Baytex from the issuance of and upon conversion of debt and other securities or (B) the aggregate amount of all restricted payments declared or made after July 9, 2003 does not exceed the sum of permitted restricted payments not previously made plus US$30,000,000.

NPI

We are a party to a net profit interest agreement with Baytex pursuant to which we have the right to receive a NPI on petroleum and natural gas rights held by Baytex from time to time. Pursuant to the terms of the agreement, we are entitled to a payment from Baytex for each month equal to the amount by which 99% of the gross proceeds from the sale of production attributable to such property interests for such month exceed ninety-nine (99%) percent of certain deductible costs for such period. Baytex is entitled to set off amounts reimbursable to it against NPI payments payable by Baytex. The term of the agreement is for so long as there are petroleum and natural gas rights to which the NPI applies.

Notes

A Note was issued by Baytex to us under the Note Indenture in connection with the plan of arrangement completed on September 2, 2003. Similar Notes have been issued by Baytex to us for inter-corporate debt from time to time.

The Notes are unsecured, payable on demand and bear interest from the date of issue at an interest rate equal to 12% per annum. Interest is payable for each month during the term on the 10th day of the month following such month.

Although Baytex is permitted to make payments against the principal amount of the Notes outstanding from time to time without notice or bonus, Baytex is not required to make any payment in respect of principal until December 31, 2033, subject to extension in the limited circumstances.

In contemplation of the possibility that additional Notes may be distributed to Unitholders upon the redemption of their Trust Units, the Note Indenture provides that if persons other than us (the “Non-Fund Holders”) own Notes having an aggregate principal amount in excess of $1,000,000, either we or the Non-Fund Holders will be entitled, among other things, to require the Note Trustee appointed under the Trust Indenture to exercise the powers and remedies available under the Note Indenture upon an event of default and, with the Trust, the Non-Fund Holders may provide consents, waivers or directions relating generally to the variance of the Notes Indenture and the rights of noteholders. The Note Indenture allows us flexibility to delay payments of interest or principal otherwise due to it while payment is made to other noteholders, and to allow other noteholders to be paid out before the Trust. Any delayed payments will be due 5 days after demand.

Disclosure of Reserves Data and Other Oil and Gas Information

The statement of reserves data and other oil and gas information set forth below (the “Statement”) is dated December 31, 2004. The effective date of the Statement is December 31, 2004 and the preparation date of the Statement is February 28, 2005. The Report of Management and Directors on Oil and Gas Disclosure in Form 51-101F3 and the Report on Reserves Data by Sproule in Form 51-101F2 are attached as Appendices A and B to this Annual Information Form.

The reserves data set forth below (the “Reserves Data”) is based upon the Sproule Report. The Reserves Data summarizes our oil, liquids and natural gas reserves and the net present values of future net revenue for these reserves using constant prices and costs and forecast prices and costs. The Reserves Data conforms with the requirements of NI 51-101. We engaged Sproule to provide an evaluation of proved and proved plus probable reserves and no attempt was made to evaluate possible reserves.

All of our reserves are in Canada and, specifically, in the provinces of Alberta, Saskatchewan and British Columbia

It should not be assumed that the estimates of future net revenues presented in the tables below represent the fair market value of the reserves. There is no assurance that the constant prices and costs assumptions and forecast prices and costs assumptions will be attained and variances could be material. The recovery and reserve estimates of crude oil, natural gas liquids and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, natural gas and natural gas liquid reserves may be greater than or less than the estimates provided herein. For more information as to the risks involved, see “Risk Factors”.

We are classified as a unit trust for income tax purposes, and are taxable on income not distributed to public Unitholders. We have and expect to continue to allocate all of our taxable income to Unitholders. Accordingly, no provision for income taxes is required at the Trust level and all information for the most recent oil and gas reserves has been presented on a pre-tax basis only.

Reserves Data (Constant Prices and Costs)

SUMMARY OF OIL AND GAS RESERVES

AND NET PRESENT VALUES OF FUTURE NET REVENUE

AS OF December 31, 2004

CONSTANT PRICES AND COSTS

	RESERVES
	LIGHT AND MEDIUM OIL		HEAVY OIL		NATURAL GAS		NATURAL GAS LIQUIDS		TOTAL RESERVES
RESERVES CATEGORY	Gross	Net	Gross	Net	Gross	Net	Gross	Net	Gross	Net
	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Bcf)	(Bcf)	(Mbbl)	(Mbbl)	(Mboe)	(Mboe)
PROVED
Developed Producing	4,425.8	3,973.4	21,004.5	18,470.4	98.9	81.9	2,877.0	2,275.9	44,795.2	38,372.2
Developed Non-Producing	517.2	426.2	15,864.8	13,116.7	7.7	6.4	421.1	333.1	18,084.3	14,939.8
Undeveloped	1,772.3	1,513.9	19,843.7	17,349.5	7.9	6.3	385.7	307.5	23,322.5	20,217.8
TOTAL PROVED	6,715.3	5,913.5	56,712.9	48,936.5	114.5	94.6	3,683.8	2,916.5	86,202.0	73,529.8
PROBABLE	2,667.8	2,367.4	25,490.1	21,722.2	45.8	38.3	595.5	457.1	36,378.9	30,933.5
TOTAL PROVED PLUS PROBABLE	9,383.0	8,280.9	82,203.0	70,658.7	160.3	132.9	4,279.3	3,373.5	122,580.9	104,463.3

	NET PRESENT VALUES OF FUTURE NET REVENUE
	BEFORE INCOME TAXES DISCOUNTED AT
RESERVES CATEGORY	0%	10%
	($Million)	($Million)
PROVED
Developed Producing	893.7	677.1
Developed Non-Producing	292.6	195.4
Undeveloped	338.8	214.6
TOTAL PROVED	1,525.0	1,087.0
PROBABLE	648.8	374.4
TOTAL PROVED PLUS PROBABLE	2,173.8	1,461.4

TOTAL FUTURE NET REVENUE

(UNDISCOUNTED)

AS OF DECEMBER 31, 2004

CONSTANT PRICES AND COSTS

RESERVES CATEGORY	REVENUE	ROYALTIES	OPERATING COSTS	DEVELOPMENT COSTS	WELL ABANDONMENT COSTS	FUTURE NET REVENUE BEFORE INCOME TAXES
	($Million)	($Million)	($Million)	($Million)	($Million)	($Million)
Proved Reserves	2,901	445	751	164	16	1,525
Proved Plus Probable Reserves	4,116	631	1,059	236	16	2,174

FUTURE NET REVENUE

BY PRODUCTION GROUP

AS OF DECEMBER 31, 2004

CONSTANT PRICES AND COSTS

RESERVES CATEGORY	PRODUCTION GROUP	FUTURE NET REVENUE BEFORE INCOME TAXES (discounted at 10%/year)
		($Million)
Proved Reserves	Light and Medium Crude Oil (excluding solution gas and other by-products)	111.9
	Heavy Oil (including solution gas and other by-products)	632.3
	Natural Gas (including by-products and solution gas from oil wells)	342.9

Proved Plus Probable Reserves	Light and Medium Crude Oil (excluding solution gas and other by-products)	144.0
	Heavy Oil (including solution gas and other by-products)	880.1
	Natural Gas (including by-products and solution gas from oil wells)	437.3

Reserves Data (Forecast Prices and Costs)

SUMMARY OF OIL AND GAS RESERVES

AND NET PRESENT VALUES OF FUTURE NET REVENUE

AS OF DECEMBER 31, 2004

FORECAST PRICES AND COSTS

	RESERVES
	LIGHT AND MEDIUM OIL		HEAVY OIL		NATURAL GAS		NATURAL GAS LIQUIDS		TOTAL RESERVES
RESERVES CATEGORY	Gross	Net	Gross	Net	Gross	Net	Gross	Net	Gross	Net
	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Bcf)	(Bcf)	(Mbbl)	(Mbbl)	(Mboe)	(Mboe)
PROVED
Developed Producing	4,107.7	3,688.2	20,161.2	17,926.0	95.5	79.0	2,867.0	2,269.3	43,060.7	37,047.9
Developed Non-Producing	509.6	420.5	15,815.0	13,420.2	7.6	6.3	420.9	333.0	18,019.4	15,231.8
Undeveloped	1,768.9	1,527.9	19,898.0	17,877.5	7.8	6.2	384.6	306.6	23,359.5	20,750.6
TOTAL PROVED	6,386.2	5,636.5	55,874.2	49,223.7	111.0	91.6	3,672.5	2,908.9	84,439.6	73,030.3

PROBABLE	2,430.8	2,165.3	24,887.1	21,840.4	44.1	36.9	590.2	454.1	35,258.0	30,605.8

TOTAL PROVED PLUS PROBABLE	8,817.0	7,801.7	80,761.3	71,064.2	155.1	128.4	4,262.7	3,363.1	119,697.6	103,636.1

	NET PRESENT VALUES OF FUTURE NET REVENUE BEFORE INCOME TAXES DISCOUNTED AT
RESERVES CATEGORY	0%	5%	10%	15%	20%
	($Million)	($Million)	($Million)	($Million)	($Million)
PROVED
Developed Producing	668.6	596.3	538.5	493.6	457.9
Developed Non-Producing	180.6	148.2	125.1	107.8	94.5
Undeveloped	187.5	145.1	114.2	91.0	73.2
TOTAL PROVED	1,036.7	889.6	777.8	692.5	625.5

PROBABLE	414.8	307.2	241.5	197.1	165.3

TOTAL PROVED PLUS PROBABLE	1,451.5	1,196.8	1,019.3	889.6	790.8

TOTAL FUTURE NET REVENUE
(UNDISCOUNTED)
AS OF DECEMBER 31, 2004
FORECAST PRICES AND COSTS

RESERVES CATEGORY	REVENUE	ROYALTIES	OPERATING COSTS	DEVELOPMENT COSTS	WELL ABANDONMENT COSTS	FUTURE NET REVENUE BEFORE INCOME TAXES
	($Million)	($Million)	($Million)	($Million)	($Million)	($Million)
Proved Reserves	2,358	337	787	172	25	1,037

Proved Plus Probable Reserves	3,312	467	1,118	250	25	1,452

FUTURE NET REVENUE
BY PRODUCTION GROUP
AS OF DECEMBER 31, 2004
FORECAST PRICES AND COSTS

RESERVES CATEGORY	PRODUCTION GROUP	FUTURE NET REVENUE BEFORE INCOME TAXES (discounted at 10%/year)
		($Million)
Proved Reserves	Light and Medium Crude Oil (excluding solution gas and other by-products)	95.0
	Heavy Oil (including solution gas and other by-products)	394.1
	Natural Gas (including by-products and solution gas from oil wells)	288.7

Proved Plus Probable Reserves	Light and Medium Crude Oil (excluding solution gas and other by-products)	120.2
	Heavy Oil (including solution gas and other by-products)	535.1
	Natural Gas (including by-products and solution gas from oil wells)	363.8

Definitions and Other Notes

In the tables set forth above in “Disclosure of Reserves Data” and elsewhere in this Annual Information Form the following definitions and other notes are applicable:

1. “Gross” means:

(a) in relation to our interest in production and reserves, our interest (operating and non-operating) share before deduction of royalties and without including any of our royalty interests;

(b) in relation to wells, the total number of wells in which we have an interest; and

2. “Net” means:

(a) in relation to our interest in production and reserves, our interest (operating and non-operating) share after deduction of royalties obligations, plus our royalty interest in production or reserves.

(b) in relation to wells, the number of wells obtained by aggregating our working interest in each of our gross wells; and

(c) in relation to our interest in a property, the total area in which we have an interest multiplied by our working interest.

3. Definitions used for reserve categories are as follows:

Reserve Categories

Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, from a given date forward, based on

(a) analysis of drilling, geological, geophysical and engineering data;

(b) the use of established technology; and

Reserves are classified according to the degree of certainty associated with the estimates.

(a) Proved reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.

(b) Probable reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.

“Economic Assumptions” will be the prices and costs used in the estimate, namely:

(a) constant prices and costs as at the last day of the Trust’s financial year; and

(b) forecast prices and costs.

Development and Production Status

Each of the reserve categories (proved and probable) may be divided into developed and undeveloped categories:

(a) Developed reserves are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (for example, when compared to the cost of drilling a well) to put the reserves on production. The developed category may be subdivided into producing and non-producing.

(i) Developed producing reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty.

(ii) Developed non-producing reserves are those reserves that either have not been on production, or have previously been on production, but are shut-in, and the date of resumption of production is unknown.

(b) Undeveloped reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (for example, when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves classification (proved, probable) to which they are assigned.

Levels of Certainty for Reported Reserves

The qualitative certainty levels referred to in the definitions above are applicable to individual reserve entities (which refers to the lowest level at which reserves calculations are performed) and to reported reserves (which refers to the highest level sum of individual entity estimates for which reserves are presented). Reported reserves should target the following levels of certainty under a specific set of economic conditions:

(a) at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimated proved reserves; and

(b) at least a 50 percent probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus probable reserves.

(c) A qualitative measure of the certainty levels pertaining to estimates prepared for the various reserves categories is desirable to provide a clearer understanding of the associated risks and uncertainties. However, the majority of reserves estimates will be prepared using deterministic methods that do not provide a mathematically derived quantitative measure of probability. In principle, there should be no difference between estimates prepared using probabilistic or deterministic methods.

4. The Alberta royalty tax credit (ARTC) is included in the cumulative cash flow amounts. ARTC is based on the program announced November 1989 by the Alberta government with modifications effective January 1, 1995. We qualify for the maximum ARTC.

5. “Exploration well” means a well that is not a development well, a service well or a stratigraphic test well.

6. “Development costs” means costs incurred to obtain access to reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas from reserves. More specifically, development costs, including applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:

(a) gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground draining, road building, and relocating public roads, gas lines and power lines, pumping equipment and wellhead assembly;

(b) drill and equip development wells, development type stratigraphic test wells and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment and wellhead assembly;

(c) acquire, construct and install production facilities such as flow lines, separators, treaters, heaters, manifolds, measuring devices and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems; and

(d) provide improved recovery systems.

7. “Development well” means a well drilled inside the established limits of an oil and gas reservoir, or in close proximity to the edge of the reservoir, to the depth of a stratigraphic horizon known to be productive.

8. “Exploration costs” means costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects that may contain oil and gas reserves, including costs of drilling exploratory wells and exploratory type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property and after acquiring the property. Exploration costs, which include applicable operating costs of support equipment and facilities and other costs of exploration activities, are:

(a) costs of topographical, geochemical, geological and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews and others conducting those studies;

(b) costs of carrying and retaining unproved properties, such as delay rentals, taxes (other than income and capital taxes) on properties, legal costs for title defence, and the maintenance of land and lease records;

(d) costs of drilling and equipping exploratory wells; and

(e) costs of drilling exploratory type stratigraphic test wells.

9. “Service well” means a well drilled or completed for the purpose of supporting production in an existing field. Wells in this class are drilled for the following specific purposes: gas injection (natural gas, propane, butane or flue gas), water injection, steam injection, air injection, salt water disposal, water supply for injection, observation or injection for combustion.

10. Numbers may not add due to rounding.

11. The estimates of future net revenue presented in the tables above do not represent fair market value.

Pricing Assumptions

The following sets forth the benchmark reference prices, as at December 31, 2004, reflected in the Reserves Data. The forecast prices and cost assumptions were provided to us by Sproule, our independent qualified reserves evaluator.

Forecast Prices and Costs

These are prices and costs that are:

(a) generally acceptable as being a reasonable outlook of the future; and

(b) if and only to the extent that, there are fixed or presently determinable future prices or costs to which Baytex is legally bound by a contractual or other obligation to supply a physical product, including those for an extension period of a contract that is likely to be extended, those prices or costs rather than the prices and costs referred to in paragraph (a).

The forecast cost and price assumptions include increases in actual wellhead selling prices and take into account inflation with respect to future operating and capital costs. Crude oil, heavy oil, natural gas and natural gas liquids benchmark reference pricing, as at December 31, 2004, inflation and exchange rates utilized in the Sproule Report were as follows:

SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS
AS OF DECEMBER 31, 2004
FORECAST PRICES AND COSTS

	OIL
Year	WTI Cushing Oklahoma	Edmonton Par Price 40 API	Hardisty Heavy 12 API	NATURAL GAS AECO Gas Price	INFLATION RATES(1) %/Year	EXCHANGE RATE(2)
	($US/Bbl)	($Cdn/Bbl)	($Cdn/Bbl)	($Cdn/Mmbtu)		($US/$Cdn)
2005	44.29	51.25	28.91	6.97	2.5	0.84
2006	41.60	48.03	28.12	6.66	2.5	0.84
2007	37.09	42.64	26.19	6.21	2.5	0.84
2008	33.46	38.31	25.06	5.73	2.5	0.84
2009	31.84	36.36	23.60	5.37	1.5	0.84
2010	32.32	36.91	24.12	5.47	1.5	0.84
2011	32.80	37.47	24.64	5.57	1.5	0.84
2012	33.30	38.03	25.17	5.67	1.5	0.84
2013	33.79	38.61	25.71	5.77	1.5	0.84
2014	34.30	39.19	26.26	5.87	1.5	0.84
2015	34.82	39.78	26.82	5.98	1.5	0.84
2016	35.34	40.38	27.22	6.07	1.5	0.84

Escalation Rate of 1.5% thereafter.

Notes:

(1) Inflation rates for forecasting prices and costs.

(2) Exchange rates used to generate the benchmark reference prices in this table.

Constant Prices and Costs

These are prices and costs that are:

(a) Our prices and costs as of December 31, 2004, held constant throughout the estimated lives of the properties to which the estimate applies; and

(b) if, and only to the extent that, there are fixed or presently determinable future prices of costs to which we are legally bound by a contractual or other obligation to supply a physical product, including those for an extension period of a contract that is likely to be extended, those prices or costs rather than the prices and costs referred to in paragraph (a).

The constant crude oil and natural gas benchmark reference pricing and the exchange rate utilized in the Sproule Report were as follows:

SUMMARY OF PRICING ASSUMPTIONS
AS OF DECEMBER 31, 2004
CONSTANT PRICES AND COSTS(1)

	OIL
Year	WTI Cushing Oklahoma	Edmonton Par Price 40 API	Hardisty Heavy 12 API	NATURAL GAS AECO Gas Price	EXCHANGE RATE(2)
	($US/bbl)	($Cdn/bbl)	($Cdn/bbl)	($Cdn/Mcf)	($US/$Cdn)
December 31, 2004	43.45	46.53	32.97	6.78	0.8308

Notes:

(1) This summary table identifies benchmark reference pricing schedules that might apply to a reporting issuer.

(2) The exchange rate used to generate the benchmark reference prices in this table.

Weighted average prices realized by us for the year ended December 31, 2004, were $6.46/Mcf for natural gas, $48.64/bbl for light crude oil and $30.32/bbl for heavy oil. The heavy oil price includes the effect of our long term sales contract.

Reconciliations of Changes in Reserves and Future Net Revenue

RECONCILIATION OF TRUST NET RESERVES
BY PRINCIPAL PRODUCT TYPE
FORECAST PRICES AND COSTS (2)

	Light and Medium Crude Oil						Heavy Oil
	Proved		Probable		Proved + Probable		Proved		Probable		Proved + Probable
	(Mbbl)		(Mbbl)		(Mbbl)		(Mbbl)		(Mbbl)		(Mbbl)

December 31, 2003	4,714		1,493		6,207		51,884		21,557		73,441
Extensions	0		0		0		4,606		1,330		5,936
Improved Recovery	21		56		77		2,591		706		3,298
Technical Revisions	(63	)	13		(50	)	(429	)	(595	)	(1,025	)
Acquisitions	2,162		665		2,827		10		4		14
Dispositions	(699	)	(128	)	(826	)	0		0		0
Economic Factors	34		66		101		(2,284	)	(1,161	)	(3,396	)
Production	(532	)	0		(532	)	(7,204	)	0		(7,204	)
December 31, 2004	5,637		2,165		7,802		49,224		21,841		71,064

	Natural Gas Liquids					Natural Gas including solution gas
	Proved		Probable	Proved+ Probable		Proved		Probable		Proved + Probable
	(Mbbl)		(Mbbl)	(Mbbl)		(Mmcf)		(Mmcf)		(Mmcf)

December 31, 2003	183		65	248		65,600		19,993		85,593
Extensions	0		0	0		3,107		2,046		5,153
Improved Recovery	0		0	0		433		16		449
Technical Revisions	7		0	7		480		3,165		3,644
Acquisitions	2,760		385	3,146		38,664		12,365		51,028
Dispositions	0		0	0		(90	)	(60	)	(150	)
Economic Factors	(7	)	5	(2	)	(1,686	)	(724	)	(2,409	)
Production	(35	)	0	(35	)	(14,908	)	0		(14,908	)
December 31, 2004	2,909		454	3,363		91,600		36,800		128,400

	Oil Equivalent (1)
	Proved		Probable		Proved + Probable
	(MMboe)		(MMboe)		(MMboe)

December 31, 2003	67.7		26.4		94.2
Extensions	5.1		1.7		6.8
Improved Recovery	2.7		0.8		3.4
Technical Revisions	(0.4	)	—		(0.4	)
Acquisitions	11.4		3.1		14.5
Dispositions	(0.7	)	(0.1	)	(0.9	)
Economic Factors	(2.4	)	(1.2	)	(3.7	)
Production	(10.3	)	—		(10.3	)
December 31, 2004	73.0		30.6		103.6

Notes:

(1) Oil equivalent amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil. BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 mcf: 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

(2) Numbers may not add due to rounding.

RECONCILIATION OF TRUST INTEREST RESERVES
EXCLUDING SOLUTION GAS AND ANY ROYALTY INTEREST

BY PRINCIPAL PRODUCT TYPE
FORECAST PRICES AND COSTS (2)

	Light and Medium Crude Oil						Heavy Oil
	Proved)		Probable		Proved + Probable		Proved		Probable		Proved + Probable
	(Mbbl)		(Mbbl)		(Mbbl)		(Mbbl)		(Mbbl)		(Mbbl)
December 31, 2003	5,159		1,649		6,808		57,568		23,606		81,174
Extensions	0		0		0		5,118		1,478		6,596
Improved Recovery	23		62		85		2,879		785		3,664
Technical Revisions	121		4		125		(477	)	(661	)	(1,138	)
Acquisitions	2,538		777		3,315		11		4		15
Dispositions	(739	)	(135	)	(873	)	0		0		0
Economic Factors	38		74		112		(915	)	(324	)	(1,240	)
Production	(754	)	0		(754	)	(8,309	)	0		(8,309	)
December 31, 2004	6,386		2,431		8,817		55,874		24,887		80,761

	Natural Gas Liquids						Natural Gas including solution gas
	Proved		Probable		Proved+ Probable		Proved		Probable		Proved + Probable
	(Mbbl)		(Mbbl)		(Mbbl)		(Mmcf)		(Mmcf)		(Mmcf)
December 31, 2003	260		95		355		81,175		24,641		105,816
Extensions	0		0		0		3,884	��	2,558		6,441
Improved Recovery	0		0		0		541		20		561
Technical Revisions	14		(3	)	11		1,663		3,972		5,635
Acquisitions	3,449		492		3,941		46,061		13,899		59,960
Dispositions	0		0		0		(130	)	(85	)	(215	)
Economic Factors	(10	)	7		(3	)	(2,108	)	(904	)	(3,012	)
Production	(41	)	0		(41	)	(20,087	)	0		(20,087	)
December 31, 2004	3,673		590		4,263		110,999		44,101		155,100

	Oil Equivalent(1)
	Proved		Probable		Proved + Probable
	(MMboe)		(MMboe)		(MMboe)
December 31, 2003	76.5		29.5		106.0
Extensions	5.8		1.9		7.7
Improved Recovery	3.0		0.9		3.8
Technical Revisions	(0.1	)	0		(0.1	)
Acquisitions	13.7		3.6		17.3
Dispositions	(0.8	)	(0.1	)	(1.0	)
Economic Factors	(1.2	)	(0.4	)	(1.6	)
Production	(12.5	)	0		(12.5	)
December 31, 2004	84.4		35.3		119.7

Notes:

(1) Oil equivalent amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil. BOE’s may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 mcf: 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

(2) Numbers may not add due to rounding.

RECONCILIATION OF CHANGES IN
NET PRESENT VALUES OF FUTURE NET REVENUE
DISCOUNTED AT 10% PER YEAR

PROVED RESERVES
CONSTANT PRICES AND COSTS

PERIOD AND FACTOR	2004
	($Million)
Estimated Future Net Revenue at Beginning of Year	793.7

Sales and Transfers of Oil and Gas Produced, Net of Production Costs and Royalties	(135.1	)
Net Change in Prices, Production Costs and Royalties Related to Future Production	(15.7	)
Changes in Previously Estimated Development Costs Incurred During the Period	29.2
Changes in Estimated Future Development Costs	89.3
Extensions and Improved Recovery	99.7
Acquisitions of Reserves	179.7
Dispositions of Reserves	(12.7	)
Net Change Resulting from Revisions in Quantity Estimates (Technical Revisions)	(5.4	)
Accretion of Discount	91.1
Miscellaneous Changes	(26.8	)

Estimated Future Net Revenue at End of Year	1,087.0

Additional Information Relating to Reserves Data

Proved and Probable Undeveloped Reserves

Undeveloped reserves are attributed by Sproule in accordance with standards and procedures contained in the COGE Handbook. Proved undeveloped reserves are those reserves that can be estimated with a high degree of certainty and are expected to be recovered from known accumulations where a significant expenditure is required to render them capable of production. Probable undeveloped reserves are those reserves that are less certain to be recovered than proved reserves and are expected to be recovered from known accumulations where a significant expenditure is required to render them capable of production.

The funds available for capital expenditures under a trust business model are lower than for a traditional oil and gas business model as a portion of the cash flow that a trust generates is distributed to its unitholders. As a result, we are required to develop our assets in a more efficient and methodical fashion to reduce risk by technically assessing the results of each of our development programs before committing additional capital. This staged approach to development means that in some cases it will take longer than two years to develop our proved undeveloped and probable undeveloped reserves. We plan to develop the majority of our proved undeveloped and probable undeveloped reserves over the next four years. A staged approach to this development refers to our practice of developing reserves through a series of sequential capital investments. These investments are budgeted and incurred annually for a given area. Once the development program is executed,we then measure and analyze the results of that investment program, make any changes that are necessary, and then repeat the process until all economic oil and gas reserves are developed.

Significant Factors or Uncertainties

We have a significant amount of proved non-producing and proved undeveloped reserves assigned to the Tangleflags and Carruthers heavy oil properties in Saskatchewan and to the Ardmore and Cold Lake heavy oil properties in Alberta. At the current prices, these well re-completions and new wells are economic. However, should oil prices fall materially, these activities may not be economic and we could defer their implementation.

Future Development Costs

The following table sets forth development costs deducted in the estimation of our future net revenue attributable to the reserve categories noted below.

	Forecast Prices and Costs		Constant Prices and Costs
Year	Proved Reserves	Proved Plus Probable Reserves	Proved Reserves
	($ Million)	($ Million)	($ Million)

2005	84.5	97.1	82.4
2006	46.0	70.6	43.8
2007	19.7	40.3	18.3
2008	15.2	33.0	13.7
2009	1.9	1.9	1.7
Total Undiscounted (all years)	172.1	249.7	164.0
Total Discounted at 10%/year	150.3	213.3	143.9

We expect to fund the development costs of our reserves through a combination of internally generated cash flow, debt and sale of Trust Units. We withhold approximately 30 - 40% of cash flow to assist in funding development activities.

There can be no guarantee that funds will be available or that the Board of Directors will allocate funding to develop all of the reserves attributed in the Sproule Report. Failure to develop those reserves would have a negative impact on our future cash flow.

The interest or other costs of external funding are not included in the reserves and future net revenue estimates and would reduce reserves and future net revenue to some degree depending upon the funding sources utilized. We do not anticipate that interest or other funding costs would make development of any property uneconomic.

Estimated future well abandonment costs related to us have been taken into account by Sproule in determining reserves that should be attributed to us. In determining the aggregate future net revenue, reasonable estimated future well abandonment costs, net of downhole equipment salvage value, were deducted from the gross revenue amount.

Both the constant and forecast price and cost assumptions assumed the continuance of current laws and regulations.

The extended character of all factual data supplied to Sproule was accepted by Sproule as represented. No field inspection was conducted.

Other Oil and Gas Information

Oil and Natural Gas Properties

The following is a description of our principal oil and natural gas properties on production or under development as at December 31, 2004. The term “net”, when used to describe our share of production, means the total of our working interest share before deduction of royalties owned by others. Reserve amounts are stated, before deduction of royalties, at December 31, 2004, based on forecast cost and price assumptions as evaluated in the Sproule Report (see “Description of our Business and Operations – Disclosure of Reserves Data and Other Oil and Gas Information”). Unless otherwise specified, gross and net acres and well count information are as at December 31, 2004. Information in respect of production is average working interest production, for the year ended December 31, 2004, except where otherwise indicated.

Our crude oil and natural gas operations are organized into two operating districts - the Heavy Oil District and the Conventional Oil and Gas District. Each district constitutes an extensive portfolio of operated properties and development prospects with considerable upside potential. We have established skilled technical teams to operate each district. Each team has a mandate to apply its specific knowledge and expertise to its operating area. This focused approach aids in the evaluation of exploration, development and acquisition opportunities and improves cost efficiency.

Heavy Oil District

The Heavy Oil District accounts for approximately sixty percent of our current production, approximately three-quarters of our reserves and 50 percent of our cash flow from operations. Heavy oil operations consist largely of cold conventional production from wells with multi-zone potential. Production is generated primarily from vertical, slant and horizontal wells using progressive cavity pump technology to generate large volumes of heavy oil combined with gas, water and sand. Initial production from these wells usually averages between 40 and 100 bbl/d of low gravity crude ranging from 12 to 18 API. Once produced, the oil is trucked or pipelined to markets in both Canada and the United States. After being sold by us, the crude oil is then upgraded into lighter grades of crude or refined into petroleum products such as fuel oil, lubricants and asphalt.

In 2004, production in the Heavy Oil District averaged approximately 22,700 bbl/d of heavy oil and 9.0 mmcf/d of natural gas (24,200 boe/d). We drilled 115 gross (113.7 net) wells in the Heavy Oil District resulting in 95 gross (95.0 net) oil wells, three gross (2.2 net) gas wells, seven gross (6.5 net) stratigraphic test wells, and 10 gross (10.0 net) dry and abandoned wells, for a success rate of 91.3 percent (91.2 net).

The Heavy Oil District possesses a large inventory of development projects within the west-central Saskatchewan, Cold Lake/Ardmore, and Peace River/Seal heavy oil deposits. Our ability to generate relatively low-cost replacement production through conventional cold production methods allows us to optimize the timing and level of our capital investment program.

We will continue to build value through internal property development and selective acquisitions. Future heavy oil activity will focus on the development of the Seal and Ardmore properties along with continued infill drilling at the adjacent Cold Lake property and throughout the Saskatchewan properties. Company net undeveloped lands in this district totalled 344,892 acres at year-end 2004.

Ardmore: Ardmore is one of the key heavy oil development and production areas for us. Acquired in 2002 with production of 2,200 bbl/d, this property has been developed in the Sparky, McLaren and Colony formations. Average production during 2004 was approximately 4,200 bbl/d of oil and 1.0 mmcf/d of natural gas (4,400 boe/d). Current production is 3,800 bbl/d and 950 mmcf/d of natural gas (4,000 boe/d). We have applied leading-edge slotted liner production technology to improve production and increase wellbore stability. Slotted-liner wells in the area are capable of producing up to 300 bbl/d of heavy oil and continue to be used extensively for pool development projects. Twenty-six oil wells and three dry wells were drilled in the area during 2004 and 20 to 25 wells are anticipated to be drilled during 2005. During 2004, operating expenses were reduced to $5.50/bbl primarily by building a water disposal facility and conserving solution gas produced in conjunction with the heavy oil. It is expected that operating expenses will be reduced by an additional $0.75/bbl as a result of the construction of a sand disposal facility in late 2004. We also added 6,500 acres of new lands through Crown land sales in 2004 that are prospective for Colony oil pool development. Company net undeveloped lands were 39,120 acres at year-end 2004.

Cold Lake: We acquired the Cold Lake heavy oil property in 2001. This year-round drilling area is located on the Cold Lake First Nations lands, with heavy oil production generated largely from the Colony formation. Average production was 1,000 bbl/d during 2004. We drilled 12 oil wells and three dry wells in the Cold Lake area during 2004. Up to 15 new drills are anticipated during 2005. Company net undeveloped lands were 18,062 acres at year-end 2004.

Seal: The Seal property is a highly prospective property located in the Peace River oil sands area of northwest Alberta. We hold a 100 percent working interest in approximately 100 sections of land, of which 42 sections were acquired in 2004. The Seal oil deposits can be produced through horizontal well-bores at initial rates of approximately 200 bbl/d per well without the use of capital intensive steam injection methods. A seven-well stratigraphic test program completed during the first quarter of 2004 has led to our current development program on the western block of these land holdings. Two horizontal wells drilled at the end of 2004 are currently producing a total of approximately 400 bbl/d. The prospective undeveloped area of the western block of the our holdings is over 25,000 acres. During 2005, we plan to drill up to six additional stratigraphic test wells to further delineate this land block and up to 15 horizontal producers in the immediate area that are currently producing. In addition, other industry operators are currently drilling horizontal production wells on adjoining sections that will help define the productive capability of our other lands. Company net undeveloped lands in this area were 63,680 acres at year-end 2004.

Tangleflags: We acquired the Tangleflags property in 2000. Tangleflags is characterized by multiple-zone reservoirs with production from the Colony, McLaren, Waseca, Sparky, General Petroleum and Lloydminster formations. Provincial government regulations generally prohibit production from more than one formation at a time. As such, this property possesses long-term development potential from a considerable number of up-hole recompletion opportunities. Average production during 2004 was approximately 3,800 bbl/d of heavy oil and 1.2 mmcf/d of natural gas (4,000 boe/d). Ongoing projects in the area include up to 15 development wells during 2005, uphole recompletions after depletion of deeper producing intervals, and optimization of the solution gas gathering system. Company net undeveloped lands were 11,160 acres at year-end 2004.

Carruthers: The Carruthers property was obtained by Baytex in 1997. The property consists of separate “North” and “South” oil pools in the Cummings formation. Typical vertical oil wells initially produce approximately 40 bbl/d with ultimate recoveries of approximately 60,000 barrels of reserves. During 2004, average production was approximately 3,200 bbl/d of heavy oil and 850 mmcf/d of natural gas (3,300 boe/d). We drilled 1.2 net natural gas wells and 14 net oil wells in South Carruthers and three horizontal oil wells, in North Carruthers during 2004. This area represents a very stable production base with continued development drilling expected to total 10 to 15 wells annually. Company net undeveloped lands were 14,425 acres at year-end 2004.

Marsden/Epping/Macklin/ Silverdale: This area of Saskatchewan is characterized by low access costs and higher quality oil of 13 to 18 API gravity produced with low sand content. Initial production rates are typically 70 bbl/d and primary recovery factors can be as high as 30 percent of the original oil in place. This oil is also receptive to waterflood recovery schemes to further increase recovery. Average production in this area during 2004 was approximately 4,600 bbl/d. Twenty oil wells were drilled in 2004, increasing production to over 4,900 bbl/d by year-end. In addition, ongoing flowline installation and water disposal projects have combined to keep operating costs below $5.50/bbl. Drilling in 2005 will add up to 15 new oil wells, mostly through development of the Macklin pool. In Epping, waterflood and solution gas tie-in projects are planned for 2005. Company net undeveloped lands were 20,932 acres at year-end 2004.

Conventional Oil and Gas District

The Conventional Oil and Gas district produces light and medium gravity crude oil, natural gas and natural gas liquids from various fields in Alberta and British Columbia. In 2004, production averaged approximately 46 mmcf/d of natural gas and 2,200 bbl/d of hydrocarbon liquids (9,800 boe/d). In 2004, the Conventional District drilled 23 gross (20.9 net) wells resulting in four gross (4.0 net) oil wells, 14 gross (12.4 net) gas wells and five gross (4.5 net) dry and abandoned wells for a success rate of 78 percent. The Company undeveloped lands in the Conventional district were 453,166 net acres at year-end 2004. During 2004, property acquisitions at Garden Plains, Turin and Stoddart were added to the Conventional District.

Stoddart, British Columbia: The Stoddart asset acquisition was completed on December 22, 2004. Oil and liquids rich gas production from this largely year-round-access area comes from the Doig, Halfway, Baldonnal, Coplin and Bluesky formations. Oil is treated at two Baytex-operated batteries and natural gas is compressed at four Baytex-operated sites and sent for further processing at the outside-operated West Stoddart and Taylor Younger plants. Year-end 2004 production was approximately 11 mmcf/d and 1,600 bbl/d of hydrocarbon liquids (3,400 boe/d). We plan to drill four wells and recomplete up to seven wells in 2005 in the Stoddart area. Company net undeveloped lands were 25,343 acres at December 31, 2004.

Garden Plains/Sedalia, Alberta: In 2001, Baytex acquired its initial position in this area and significantly increased its presence with a 2004 acquisition of a private company. December 2004 gas production was approximately 10 mmcf/d (1,700 boe/d). This area has advantages of year-round access and multi-zone potential (Second White Specks, Viking and Mannville). Most of the gas production is processed by two Baytex-operated gas plants. We plan to drill four wells during 2005 in this area. Company net undeveloped lands were 77,498 acres at year-end 2004.

Turin, Alberta: This multi-zone, year-round access property was acquired in 2004. December 2004 production was approximately 2 mmcf/d of natural gas and 900 bbl/d liquids (1,200 boe/d). Production comes from the Second White Specks, Milk River, Bow Island, Mannville, Sawtooth and Livingstone formations. Oil production is treated at three Baytex-operated batteries and gas is processed at two outside-operated gas plants. We plan to drill up to 10 wells and recomplete 10 other wells during 2005 in the Turin area. Company net undeveloped lands were 31,335 acres at December 31, 2004.

Red Earth/Goodfish, Alberta: This winter-access, multi-zone property was acquired by Baytex in 1997. Relatively shallow decline oil production from Granite Wash and Slave Point pools is treated at two Company-operated sweet oil batteries. Natural gas production from the Bluesky formation is handled at two gas plants, one of which is Company-operated. Production during 2004 from this area averaged approximately 8 mmcf/d and 1,000 bbl/d hydrocarbon liquids (2,300 boe/d). We drilled eight wells in 2004 resulting in four oil wells, two gas wells and two abandoned wells and plans to drill one well in 2005. Company net undeveloped lands were 44,448 acres at year-end 2004.

Bon Accord, Alberta: This multi-zone property was acquired by Baytex in 1997. Production is from the Belly River, Viking and Mannville formations and averaged approximately 6 mmcf/d of gas and 300 bbl/d of hydrocarbon liquids or 1,300 boe/d in 2004. Natural gas is processed at two Company-operated plants and oil is treated at three Company-operated batteries. In late 2004, we drilled two gas wells (1.5 net) which will be put on production in 2005, and plans to drill one well during 2005. Company net undeveloped lands were 47,725 at year-end 2004.

Leahurst, Alberta: Production averaged approximately 8 mmcf/d (1,300 boe/d) in 2004 from this multi-zone, year-round access area. Natural gas from the Edmonton, Belly River, Viking and Mannville formations is processed at several plants, one of which is Company-operated. In 2004, we drilled five Mannville natural gas wells resulting in three gas wells and two abandonments. We also successfully recompleted nine wells for coal-bed methane production from the Horseshoe Canyon Coals during 2004. In 2005, we plan to drill 15 wells and recomplete seven wells in the Leahurst area. Company net undeveloped lands were 35,310 acres at year-end 2004.

Nina/Darwin, Alberta: Both properties in this winter-access area produce natural gas from the Bluesky formation. Natural gas production is processed at two Company-operated gas plants. Production during 2004 averaged approximately 5 mmcf/d (800 boe/d). Six net wells were drilled in 2004 resulting in three producing gas wells. Company net undeveloped lands were 46,203 acres at year-end 2004.

The following table indicates our average daily production from our important fields for the year ended December 31, 2004.

	Light and Medium Crude Oil	Heavy Oil	Gas
	(Bbl/d)	(Bbl/d)	(Mcf/d)
Tangleflags	—	3,794	1,212
Carruthers	—	3,155	850
Ardmore	—	4,196	993
Cold Lake	—	1,042	—
Lashburn	—	1,034	—
Silverdale	—	2,954	—
Marsden	—	1,657	—
Neilburg	—	1,049	—
Poundmaker	—	665	2,122
Red Earth	1,043	—	—
Sounding Lake	334	—	—
Bon Accord	303	—	6,392
Turin	235	—	—
Goodfish	—	—	7,493
Leahurst	—	—	7,635
Darwin/Nina	—	—	5,394
Richdale	—	—	4,381
Viking	—	—	2,289
Hamburg/Chinchaga	55	—	3,815
Tangent	—	—	3,661
Other Minor properties	202	3,157	8,640
Total	2,172	22,703	54,877

Oil and Gas Wells

The following table sets forth the number and status of wells in which we have a working interest as at December 31, 2004.

	Oil Wells					Natural Gas Wells
	Producing			Non-Producing		Producing		Non-Producing
	Gross		Net	Gross	Net	Gross	Net	Gross	Net

Alberta	481		387.2	265	219.7	453	360.5	270	208.0
British Columbia	36		35.7	34	33.0	22	21.4	22	18.3
Saskatchewan	894		836.5	464	446.5	35	31.6	45	40.6
Total	1,411	��	1,259.4	763	699.2	510	413.5	337	266.9

Properties with no Attributable Reserves

The following table sets out our undeveloped land holdings as at December 31, 2004.

	Undeveloped Acres
	Gross	Net

Alberta	716,495	552,770
British Columbia	103,400	76,895
Saskatchewan	178,025	168,393
Total	997,920	798,058

We expect that rights to explore, develop and exploit 181,765 net acres of our undeveloped land holdings, absent further action, will expire by December 31, 2005

Forward Contracts

For details of our material commitments to sell natural gas and crude oil which were outstanding at December 31, 2004 see Notes 16 and 17 to the Consolidated Financial Statements on pages 50 contained in our 2004 Annual Report which pages are incorporated herein by reference.

Additional Information Concerning Abandonment and Reclamation Costs

The following table set forth information respecting future abandonment and reclamation costs for surface leases, wells, facilities, and pipelines which are expected to be incurred by us for the periods indicated.

	Abandonment and Reclamation Costs escalated at 1.5% per year Undiscounted ($ Million)	Abandonment and Reclamation Costs escalated at 1.5% per year Discounted at 10%% ($ Million)
Total as at December 31, 2004	303.0	48.0
Anticipated to be paid in 2005	2.85	2.71
Anticipated to be paid in 2006	2.89	2.50
Anticipated to be paid in 2007	2.93	2.33

We will be liable for our share of ongoing environmental obligations and for the ultimate reclamation of the surface leases, wells, facilities, and pipelines held by it upon abandonment. Ongoing environmental obligations are expected to be funded out of cash flow.

We estimate the costs to abandon and reclaim all of our producing and shut in wells, facilities, and pipelines. In the table above, no estimate of salvage value is netted against the estimated cost. Using public data and our own experience, we estimate the amount and timing of future abandonment and reclamation expenditures at an operating area level. Wells within each operating area are assigned an average cost per well to abandon and reclaim the well. The estimated expenditures are based on current regulatory standards and actual abandonment cost history.

The number of net wells for which Sproule estimated we will incur reclamation and abandonment costs is 1,806 wells. This estimate includes all proved producing wells as well as proved undeveloped and probable undeveloped wells. The latter two well groups had not been drilled as of December 31, 2004. Abandonment and reclamation costs have been estimated over a 50 year period. Facility reclamation costs are scheduled to be incurred in the year following the end of the reserve life of its associated producing area. Only well abandonment costs, net of downhole salvage value were deducted by Sproule in estimating future net revenue in the Sproule Report. The additional company liability associated with the wells not assigned reserves by Sproule, pipelines and facility reclamation costs, net of salvage, which was estimated to be $146.4 million ($32.4 million discounted at 10%), was not deducted in estimating future net revenue.

Tax Horizon

We are classified as a unit trust for income tax purposes, and are taxable on income not distributed to public Unitholders. We have, and we expect to continue, to allocate all of our taxable income to Unitholders. Accordingly, no provision for income taxes is required at the Trust level and the information for the most recent oil and gas reserves has been presented on a pre-tax basis.

Capital Expenditures

The following table summarizes capital expenditures (net of certain proceeds related to our activities for the year ended December 31, 2004.

Property acquisition costs
Proved properties	$	75,142
Unproved properties	8,744
Exploration costs	4,567
Development costs	81,171
Corporate Acquisition	111,042
Total	$	280,666

Exploration and Development Activities

The following table sets forth the gross and net exploratory and development wells in which we participated during the year ended December 31, 2004.

	Exploratory Wells		Development Wells
	Gross	Net	Gross	Net
Oil	—	—	104	103.7
Natural Gas	—	—	16	14.1
Service	—	—	7	6.5
Dry	11	10.5	—	—
Total:	11	10.5	127	124.3

Production Estimates

The following table sets out the volume of our production estimated for the year ended December 31, 2005 which is reflected in the estimate of future net revenue disclosed in the tables contained under “- Disclosure of Reserves Data”.

	Light and Medium Oil	Heavy Oil	Natural Gas	Natural Gas Liquids	BOE
	(Bbl/d)	(Bbl/d)	(Mmcf/d)	(Bbl/d)	(Boe/d)
2005	2,400	22,000	60	1,600	36,000

Production History, Prices Received And Capital Expenditures

The following tables summarize certain information in respect of production, product prices received, royalties paid, operating expenses and resulting netback for the periods indicated below.

	Quarter Ended				Quarter Ended
	2004				2003
	Dec.31	Sept. 30	June 30	Mar. 31	Dec. 31	Sept. 30	June 30	Mar. 31
Average Daily Production
Light and Medium Crude Oil (Bbl/d)	2,786	1,890	1,952	2,058	1,982	1,989	2,167	2,969
Heavy Oil (Bbl/d)	22,490	22,083	22,927	23,322	24,400	25,123	22,816	23,278
Gas (Mmcf/d)	55.5	50.9	57.2	56.0	58.9	61.8	57.5	74.0
Combined (Boe/d)	34,525	32,454	34,411	34,709	36,195	37,412	34,574	38,580

Average Price Received
Light and Medium Crude Oil ($/Bbl)	50.46	52.63	47.55	43.50	37.46	35.40	38.24	46.21
Heavy Oil ($/Bbl)	17.95	22.48	21,42	21,81	20.85	22.69	21.45	26.06
Gas ($/Mcf)	6.60	6.16	6.61	6.43	5.56	5.79	6.21	7.17
Combined ($/Boe)	26.38	28.04	27.92	27.63	25.23	26.69	26.97	33.32

Royalties Paid
Light and Medium Crude Oil ($/Bbl)	8.00	6.68	6.36	6.02	5.44	5.96	7.21	8.50
Heavy Oil ($/Bbl)	4.22	5.09	3.43	3.39	2.70	3.32	3.37	4.63
Gas ($/Mcf)	1.29	1.20	1.51	1.38	1.22	1.14	1.51	1.64
Combined ($/Boe)	5.47	5.73	5.15	4.87	4.12	4.43	5.22	6.66

Production Costs
Light and Medium Crude Oil ($/Bbl)	8.57	11.67	9.97	8.35	10.42	11.31	8.91	4.40
Heavy Oil ($/Bbl)	8.61	7.93	7.28	7.51	7.44	7.10	7.65	7.21
Gas ($/Mcf)	0.83	0.87	0.82	0.77	0.72	0.84	0.71	0.66
Combined ($/Boe)	7.63	7.43	6.78	6.78	6.74	6.75	6.77	5.91

Transportation
Light and Medium Crude Oil ($/Bbl)	0.56	0.97	1.26	1.03	1.06	0.97	1.11	0.80
Heavy Oil ($/Bbl)	1.71	1.76	1.65	1.79	1.61	1.49	1.61	1.51
Gas ($/Mcf)	0.17	0.18	0.19	0.19	0.19	0.17	0.16	0.15
Combined ($/Boe)	1.43	1.53	1.48	1.56	1.45	1.34	1.40	1.25

Netback Received
Light and Medium Crude Oil ($/Bbl)	33.33	33.31	29.94	28.10	20.54	17.11	21.01	32.51
Heavy Oil ($/Bbl)	3.41	7.70	9.06	9.12	9.11	10.78	8.82	12.71
Gas ($/Mcf)	4.31	3.91	4.09	4.09	3.44	3.46	3.83	4.72
Combined ($/Boe)	11.85	13.35	14.51	14.42	12.92	14.16	13.58	19.49

ADDITIONAL INFORMATION RESPECTING BAYTEX ENERGY TRUST

The following is a summary of certain provisions of the Trust Indenture. For a complete description of our indenture, reference should be made to the Trust Indenture, a copy of which has been filed on SEDAR at www.sedar.com.

Trust Units

An unlimited number of Trust Units may be created and issued pursuant to the Trust Indenture. Each Trust Unit entitles the holder thereof to one vote at any meeting of the holders of Trust Units and represents an equal fractional undivided beneficial interest in any distribution from us (whether of net income, net realized capital gains or other amounts) and in any of our net assets in the event of termination or winding-up of the Trust. All Trust Units outstanding from time to time are entitled to an equal share of any distributions by us, and in the event of termination or winding-up of the Trust, in any of our net assets. All Trust Units rank among themselves equally and rateably without discrimination, preference or priority. Each Trust Unit is

transferable, is not subject to any conversion or pre-emptive rights and entitles the holder thereof to require us to redeem any or all of the Trust Units held by such holder (see “Redemption Right”) and to one vote at all meetings of Unitholders for each Trust Unit held.

The Trust Units do not represent a traditional investment and should not be viewed by investors as “shares” in either Baytex or the Trust. As holders of Trust Units, Unitholders do not have the statutory rights normally associated with ownership of shares of a corporation including, for example, the right to bring “oppression” or “derivative” actions. The price per Trust Unit will be a function of anticipated distributable income from Baytex and the ability of Baytex to effect long term growth in the value of the Trust. The market price of the Trust Units will be sensitive to a variety of market conditions including, but not limited to, interest rates, exchange rates, commodity prices and our ability to acquire additional assets. Changes in market conditions may adversely affect the trading price of the Trust Units.

The Trust Units are not “deposits” within the meaning of the Canada Deposit Insurance Corporation Act (Canada) and are not insured under the provisions of that Act or any other legislation. Furthermore, we are not a trust company and, accordingly, are not registered under any trust and loan company legislation as we do not carry on or intend to carry on the business of a trust company.

Special Voting Units

In order to allow us flexibility in pursuing corporate acquisitions, the Trust Indenture allows for the creation of Special Voting Units which enables us to provide voting rights to holders of Exchangeable Shares and, in the future, to holders of other exchangeable shares that may be issued by Baytex or our other subsidiaries in connection with other exchangeable share transactions.

An unlimited number of Special Voting Units may be created and issued pursuant to the Trust Indenture. Holders of Special Voting Units are not entitled to any distributions of any nature whatsoever from us and are entitled to such number of votes at meetings of Unitholders as may be prescribed by the Board of Directors. Except for the right to vote at meetings of Unitholders, the Special Voting Units do not confer upon the holders thereof any other rights.

Under the terms of the Voting and Exchange Trust Agreement, we have issued one Special Voting Right to Valiant Trust Company for the benefit of every person who received Exchangeable Shares pursuant to the plan of arrangement which was completed on September 2, 2003. See “Additional Information Respecting Baytex – Share Capital�� below.

Unitholder Limited Liability

The Trust Indenture provides that no Unitholder, in its capacity as such, will incur or be subject to any liability in contract or in tort in connection with us or our obligations or affairs and, in the event that a court determines Unitholders are subject to any such liabilities, the liabilities will be enforceable only against, and will be satisfied only out of our assets. Pursuant to the Trust Indenture, we have agreed to indemnify and hold harmless each Unitholder from any cost, damages, liabilities, expenses, charges or losses suffered by a Unitholder from or arising as a result of such Unitholder not having such limited liability.

The Trust Indenture provides that all contracts signed by or on behalf of us must contain a provision to the effect that such obligation will not be binding upon Unitholders personally. Notwithstanding the terms of the Trust Indenture, Unitholders may not be protected from our liabilities to the same extent a shareholder is protected from the liabilities of a corporation. Personal liability may also arise in respect of claims against us (to the extent that claims are not satisfied by us) that do not arise under contracts, including claims in tort, claims for taxes and possibly certain other statutory liabilities. The possibility of any personal liability to Unitholders of this nature arising is considered unlikely in view of the fact that our primary activity is to hold securities, and the majority of our business operations are currently carried on by Baytex.

Our activities and those of Baytex are conducted in such a way and in such jurisdictions as to avoid as much as possible any material risk of liability to Unitholders for claims against us. These activities include by obtaining appropriate insurance, where available, for the operations of Baytex and having contracts signed by or on behalf of us that include a provision that such obligations are not binding upon Unitholders personally.

In addition, on July 1, 2004 the Income Trusts Liability Act (Alberta) came into force, creating a statutory limitation on the liability of unitholders of Alberta income trusts such as us. The legislation provides that a unitholder will not be, as a beneficiary, liable for any act, default, obligation or liability of the trustee that arises after July 1, 2004.

Issuance of Trust Units

The Trust Indenture provides that Trust Units, including rights, warrants and other securities to purchase, to convert into or to exchange into Trust Units, may be created, issued, sold and delivered on such terms and conditions and at such times as the Trustee, upon the recommendation of the Board of Directors may determine. The Trust Indenture also provides that Baytex may authorize the creation and issuance of debentures, notes and other evidences of indebtedness of the Trust which debentures, notes or other evidences of indebtedness may be created and issued from time to time on such terms and conditions to such persons and for such consideration as Baytex may determine.

Cash Distributions

We make cash distributions on the 15th day of each month (or the first business day thereafter) to holders of Trust Units of record on the immediately preceding record date.

The Board of Directors on our behalf reviews our distribution policy from time to time. The actual amount distributed is dependent on the commodity price environment and is at the discretion of the Board of Directors. The current distribution policy targets the use of approximately 30% to 40% of cash available for distribution for capital expenditures. Depending upon commodity prices and the size of the capital budget, it is expected that 30% to 40% of the cash available for distribution will fund a portion of our annual capital expenditure program, including both exploitation expenditures and minor property acquisitions, but excluding major acquisitions.

Pursuant to various agreements with Baytex’s lenders, we are is restricted from making distributions to Unitholders where the distribution would or could have a material adverse effect on us or on our or our subsidiaries’ ability to fulfill its obligations under Baytex’s facilities or upon a material borrowing base shortfall or default.

The following is a summary of the distributions paid or declared by us from inception in September of 2003 to March 15, 2005.

For the Month Ended	Distributions per Unit		Payment Date
September 30, 2003	$	0.15	October 15, 2003
October 31, 2003	$	0.15	November 15, 2003
November 30, 2003	$	0.15	December 15, 2003
December 31, 2003	$	0.15	January 15, 2004
January 31, 2004	$	0.15	February 16, 2004
February 29, 2004	$	0.15	March 15, 2004
March 31, 2004	$	0.15	April 15, 2004
April 30, 2004	$	0.15	May 17, 2004
May 31, 2004	$	0.15	June 15, 2004
June 30, 2004	$	0.15	July 15, 2004
July 31, 2004	$	0.15	August 16, 2004
August 31, 2004	$	0.15	September 15, 2004
September 30, 2004	$	0.15	October 15, 2004
October 31, 2004	$	0.15	November 15, 2004
November 30, 2004	$	0.15	December 15, 2004
December 31, 2004	$	0.15	January 17, 2005
January 31, 2005	$	0.15	February 15, 2005
February 28, 2005	$	0.15	March 15, 2005

Redemption Right

Trust Units are redeemable at any time on demand by the holders thereof upon delivery to us of the certificate or certificates representing such Trust Units, accompanied by a duly completed and properly executed notice requiring redemption. Upon receipt of the notice to redeem Trust Units by us, the holder thereof will only be entitled to receive a price per Trust Unit equal to the lesser of: (i) 90% of the “market price” of the Trust Units on the principal market on which the Trust Units are quoted for trading during the 10 trading day period commencing immediately after the date on which the Trust Units are tendered to us for redemption; and (ii) the closing market price on the principal market on which the Trust Units are quoted for trading on the date that the Trust Units are so tendered for redemption.

For the purposes of this calculation, “market price” is an amount equal to the simple average of the closing price of the Trust Units for each of the trading days on which there was a closing price; provided that, if the applicable exchange or market does not provide a closing price but only provides the highest and lowest prices of the Trust Units traded on a particular day, the market price will be an amount equal to the simple average of the average of the highest and lowest prices for each of the trading days on which there was a trade; and provided further that if there was trading on the applicable exchange or market for fewer than five of the 10 trading days, the market price will be the simple average of the following prices established for each of the 10 trading days: the average of the last bid and last ask prices for each day on which there was no trading; the closing price of the Trust Units for each day that there was trading if the exchange or market provides a closing price; and the average of the highest and lowest prices of the Trust Units for each day that there was trading, if the market provides only the highest and lowest prices of Trust Units traded on a particular day. The closing market price will be: an amount equal to the closing price of the Trust Units if there was a trade on the date; an amount equal to the average of the highest and lowest prices of the Trust Units if there was trading and the exchange or other market provides only the highest and lowest prices of Trust Units traded on a particular day; and the average of the last bid and last ask prices if there was no trading on the date.

The aggregate amount payable by us in respect of any Trust Units surrendered for redemption during any calendar month will be satisfied by way of a cash payment on the last day of the following month. The entitlement of Unitholders to receive cash upon the redemption of their Trust Units is subject to the limitation that the total amount payable by us in respect of such Trust Units and all other Trust Units tendered for redemption in the same calendar month and in any preceding calendar month during the same year will not exceed $100,000; provided that we may, in our sole discretion, waive such limitation in respect of any calendar month. If this limitation is not so waived, the price payable by us in respect of Trust Units tendered for redemption in such calendar month will be paid on the last day of the following month as follows: (i) firstly, by distributing Notes having an aggregate principal amount equal to the aggregate price of the Trust Units tendered for redemption; and (ii) secondly, to the extent that we do not hold Notes having a sufficient principal amount outstanding to effect such payment, by us issuing promissory notes to Unitholders who exercised the right of redemption having an aggregate principal amount equal to any such shortfall, which promissory notes (Redemption Notes) will have terms and conditions substantially identical to those of the Notes.

If at the time Trust Units are tendered for redemption by a Unitholder, the outstanding Trust Units are not listed for trading on the Toronto Stock Exchange and are not traded or quoted on any other stock exchange or market which Baytex considers, in its sole discretion, provides representative fair market value price for the Trust Units or trading of the outstanding Trust Units is suspended or halted on any stock exchange on which the Trust Units are listed for trading or, if not so listed, on any market on which the Trust Units are quoted for trading, on the date such Trust Units are tendered for redemption or for more than five trading days during the 10 trading day period, commencing immediately after the date such Trust Units were tendered for redemption then such Unitholder will be entitled to receive a price per Trust Unit equal to 90% of the fair market value thereof as determined by Baytex as at the date on which such Trust Units were tendered for redemption. The aggregate price payable by us in such circumstances in respect of Trust Units tendered for redemption in any calendar month will be paid on the last day of the third following month by, at the option of the Trust: (i) a cash payment; or (ii) a distribution of Notes and/or Redemption Notes as described above.

It is anticipated that this redemption right will not be the primary mechanism for holders of Trust Units to dispose of their Trust Units. Notes or Redemption Notes which may be distributed in specie to Unitholders in connection with a redemption will not be listed on any stock exchange and no market is expected to develop in such Notes or Redemption Notes. Notes or Redemption Notes may not be qualified investments for trusts governed by registered retirement savings plans, registered retirement income funds, deferred profit sharing plans and registered education savings plans.

Non-resident Unitholders

It is in the best interest of Unitholders that we qualify as a “unit trust” and a “mutual fund trust” under the Income Tax Act (Canada). Certain provisions of the Income Tax Act (Canada) require that we not be established nor maintained primarily for the benefit of non-residents of Canada. Accordingly, in order to comply with such provisions, the Trust Indenture contains restrictions on the ownership of Trust Units by Unitholders who are non-residents. In this regard, we are required, among other things, to take all necessary steps to monitor the ownership of the Trust Units to carry out such intentions. If at any time we become aware that the beneficial owners of 50% or more of the Trust Units then outstanding are or may be non-residents or that such a situation is imminent, we will take such action as may be necessary to carry out the intentions evidenced therein. As at February 28, 2004, approximately 31% of our Trust Units were held by non-residents.

Meetings of Unitholders

The Trust Indenture provides that meetings of Unitholders must be called and held for, among other matters, the election or removal of the Trustee, the appointment or removal of our auditors, the approval of amendments to the Trust Indenture (except as described under “Amendments to the Trust Indenture”), the sale of our property as an entirety or substantially as an entirety, and the commencement of winding-up our affairs. Meetings of Unitholders will be called and held annually for, among other things, the election of the directors of Baytex and the appointment of our auditors.

A meeting of Unitholders may be convened at any time and for any purpose by the Trustee and must be convened, except in certain circumstances, if requisitioned by the holders of not less than 20% of the Trust Units then outstanding by a written requisition. A requisition must, among other things, state in reasonable detail the business purpose for which the meeting is to be called.

Unitholders may attend and vote at all meetings of Unitholders either in person or by proxy and a proxyholder need not be a Unitholder. Two persons present in person or represented by proxy and representing in the aggregate at least 5% of the votes attaching to all outstanding Trust Units will constitute a quorum for the transaction of business at all such meetings. For the purposes of determining such quorum, the holders of any issued Special Voting Units who are present at the meeting will be regarded as representing outstanding Trust Units equivalent in number to the votes attaching to such Special Voting Units.

The Trust Indenture contains provisions as to the notice required and other procedures with respect to the calling and holding of meetings of Unitholders in accordance with the requirements of applicable laws.

Reporting to Unitholders

Our financial statements are audited annually by an independent recognized firm of chartered accountants. Our audited financial statements, together with the report of such chartered accountants, are mailed or otherwise delivered to Unitholders in accordance with applicable securities legislation and our unaudited interim financial statements are mailed or otherwise delivered to Unitholders in accordance with applicable securities legislation within the periods prescribed by such legislation. Our year end of the Trust is December 31.

We are subject to the continuous disclosure obligations under all applicable securities legislation.

Takeover Bids

The Trust Indenture contains provisions to the effect that if a takeover bid is made for the Trust Units and not less than 90% of the Trust Units (other than Trust Units held at the date of the takeover bid by or on behalf of the offeror or associates or affiliates of the offeror) are taken up and paid for by the offeror, the offeror will be entitled to acquire the Trust Units held by Unitholders who did not accept the takeover bid on the terms offered by the offeror.

The Trustee

Valiant Trust Company is our trustee. The Trustee is responsible for, among other things, accepting subscriptions for Trust Units and issuing Trust Units pursuant thereto and providing timely reports to holders of Trust Units. The Trust Indenture provides that the Trustee will exercise its powers and carry out its functions thereunder as Trustee honestly, in good faith and in our best interests and the interests of Unitholders and, in connection therewith, will exercise that degree of care, diligence and skill that a reasonably prudent trustee would exercise in comparable circumstances.

The initial term of the Trustee’s appointment is until the third annual meeting of Unitholders. The Unitholders will, at the third annual meeting of Unitholders, re-appoint, or appoint a successor to the Trustee for an additional three year term, and thereafter, Unitholders will reappoint or appoint a successor to the Trustee at the annual meeting of Unitholders three years following the reappointment or appointment of the successor to the Trust. The Trustee may also be removed by a special resolution of Unitholders. Such resignation or removal becomes effective upon the acceptance or appointment of a successor trustee.

Delegation of Authority, Administration and Trust Governance

The Board of Directors has generally been delegated the significant management decisions relating to us. In particular, the Trustee has delegated to Baytex responsibility for any and all matters relating to the following: (i) an offering; (ii) ensuring compliance with all applicable laws, including in relation to an offering; (iii) all matters relating to the content of any offering documents, the accuracy of the disclosure contained therein, and the certification thereof; (iv) all matters concerning the terms of, and amendment from time to time of our material contracts; (v) all matters concerning any underwriting or agency agreement providing for the sale of Trust Units or rights to Trust Units; (vi) all matters relating to the redemption of Trust Units; (vii) all matters relating to the voting rights on any investments in our assets or any subsequent investments; (viii) all matters relating to the specific powers and authorities as set forth in the Trust Indenture.

Liability of the Trustee

The Trustee, its directors, officers, employees, shareholders and agents are not be liable to any Unitholder or any other person, in tort, contract or otherwise, in connection with any matter pertaining to us or our property, arising from the exercise by the Trustee of any powers, authorities or discretion conferred under the Trust Indenture, including, without limitation, an administration agreement in place between us and Baytex and relying on Baytex thereunder, any action taken or not taken in good faith in reliance on any documents that are, prima facie, properly executed, any depreciation of, or loss to, our property incurred by reason of the sale of any asset, any inaccuracy in any evaluation provided by any appropriately qualified person, any reliance on any such evaluation, any action or failure to act of Baytex, or any other person to whom the Trustee has, with the consent of Baytex, delegated any of its duties thereunder, or any other action or failure to act (including failure to compel in any way any former trustee to redress any breach of trust or any failure by Baytex to perform its duties under or delegated to it under the Trust Indenture or any other contract), including anything done or permitted to be done pursuant to, or any error or omission relating to, the rights, powers, responsibilities and duties conferred upon, granted, allocated and delegated to Baytex thereunder or under the administration agreement, or the act of agreeing to the conferring upon, granting, allocating and delegating any such rights, powers, responsibilities and duties to Baytex in accordance with the terms of the Trust Indenture or under the administration agreement, unless and to the extent such liabilities arise out of the gross negligence, wilful default or fraud of the Trustee or any of its directors, officers, employees, shareholders, or agents.

If the Trustee has retained an appropriate expert or adviser or legal counsel with respect to any matter connected with its duties under the Trust Indenture or any other contract, the Trustee may act or refuse to act based on the advice of such expert, adviser or legal counsel, and notwithstanding any other provision of the Trust Indenture, the Trustee will not be liable for and will be fully protected from any loss or liability occasioned by any action or refusal to act based on the advice of any such expert, adviser or legal counsel. In the exercise of the powers, authorities or discretion conferred upon the Trustee under the Trust Indenture, the Trustee is and will be conclusively deemed to be acting as Trustee of our assets and will not be subject to any personal liability for any debts, liabilities, obligations, claims, demands, judgments, costs, charges or expenses against or with respect to us or our property. In addition, the Trust Indenture contains other customary provisions limiting the liability of the Trustee.

Amendments to the Trust Indenture

The Trust Indenture may be amended or altered from time to time by a special resolution of Unitholders.

The Trustee may, without the approval of any of Unitholders, amend the Trust Indenture for the purpose of:

(a) ensuring our continuing compliance with applicable laws or requirements of any governmental agency or authority of Canada or of any province;

(b) ensuring that we will satisfy the provisions of each of subsections 108(2) and 132(6) of the Tax Act as from time to time amended or replaced;

(c) ensuring that such additional protection is provided for the interests of Unitholders as the Trustee may consider expedient;

(d) removing or curing any conflicts or inconsistencies between the provisions of the Trust Indenture or any supplemental indenture and any other agreement of us or any offering document pursuant to which our securities are issued with respect us, or any applicable law or regulation of any jurisdiction, provided that in the opinion of the Trustee the rights of the Trustee and of Unitholders are not prejudiced thereby; and

(e) curing, correcting or rectifying any ambiguities, defective or inconsistent provisions, errors, mistakes or omissions, provided that in the opinion of the Trustee the rights of the Trustee and of Unitholders are not prejudiced thereby.

Termination of the Trust

The Unitholders may vote to terminate the Trust at any meeting of Unitholders duly called for that purpose, subject to the following: (a) a vote may only be held if requested in writing by the holders of not less than 20% of the outstanding Trust Units; (b) a quorum of 50% of the issued and outstanding Trust Units is present in person or by proxy; and (c) the termination must be approved by special resolution of Unitholders.

Unless the Trust is earlier terminated or extended by vote of Unitholders, the Trustee will commence to wind-up our affairs on December 31, 2099. In the event that we are wound-up, the Trustee will sell and convert into money our property in one transaction or in a series of transactions at public or private sale and do all other acts appropriate to liquidate our property, and will in all respects act in accordance with the directions, if any, of Unitholders in respect of termination authorized pursuant to the special resolution authorizing our termination. After paying, retiring or discharging or making provision for the payment, retirement or discharge of all our known liabilities and obligations and providing for indemnity against any other outstanding liabilities and obligations, the Trustee will distribute the remaining part of the proceeds of the sale of the assets together with any cash forming part of our property among Unitholders in accordance with their pro rata holdings.

Exercise of Voting Rights Attached to Shares of Baytex

The Trust Indenture prohibits the Trustee from voting the shares of Baytex with respect to: (i) the election of directors of Baytex; (ii) the appointment of auditors of Baytex; or (iii) the approval of Baytex’s financial statements, except in accordance with an ordinary resolution adopted at an annual meeting of Unitholders. The Trustee is also prohibited from voting the shares to authorize:

(a) any sale, lease or other disposition of, or any interest in, all or substantially all of the assets of Baytex, except in conjunction with an internal reorganization of the direct or indirect assets of Baytex as a result of which either Baytex or the Trust has the same interest, whether direct or indirect, in the assets as the interest, whether direct or indirect, that it had prior to the reorganization;

(b) any statutory amalgamation of Baytex with any other corporation, except in conjunction with an internal reorganization as referred to in paragraph (a) above;

(c) any statutory arrangement involving Baytex except in conjunction with an internal reorganization as referred to in paragraph (a) above;

(d) any amendment to the articles of Baytex to increase or decrease the minimum or maximum number of directors; or

(e) any material amendment to the articles of Baytex to change the authorized share capital other than the creation of additional classes of Exchangeable Shares or amend the rights, privileges, restrictions and conditions attaching to any class of Baytex’s shares in a manner which may be prejudicial to us, without the approval of Unitholders by special resolution at a meeting of Unitholders called for that purpose.

ADDITIONAL INFORMATION RESPECTING BAYTEX ENERGY LTD.

Management of the Trust

The name, municipality of residence, principal occupation for the prior five years of each of the directors and officers of Baytex are as follows:

Name and Municipality Of Residence	Position with Baytex	Principal Occupation
Raymond T. Chan Calgary, Alberta	President, Chief Executive Officer and Director	President and Chief Executive Officer of Baytex since September 2003; prior thereto, Senior Vice President and Chief Financial Officer of Baytex since October 1998.

John A. Brussa(2) (3) (5) Calgary, Alberta	Director	Partner, Burnet, Duckworth & Palmer LLP (a law firm).

W.A. Blake Cassidy (1) Calgary, Alberta	Director	Retired banker.

Edward Chwyl (2) (3) Victoria, B.C.	Chairman	Independent businessman since May 2002; prior thereto Chairman of the Board of Ventus Energy Ltd. since January 1999; prior thereto Chief Executive Officer of Marathon Oil Canada Ltd. since August 1998; prior thereto President and Chief Executive Officer of Tarragon Oil and Gas Limited.

Naveen Dargan(1) (2) Calgary, Alberta	Director	Independent businessman since June 2003; prior thereto Senior Managing Director of Raymond James Ltd. and predecessor companies.

Name and Municipality Of Residence	Position with Baytex	Principal Occupation
Dale O. Shwed(1) (3)(6) Calgary, Alberta	Director	President and Chief Executive Officer of Crew Energy Inc. since September 2003; prior thereto President and Chief Executive Officer of Baytex.

Daniel G. Belot Calgary, Alberta	Vice President, Finance and Chief Financial Officer	Vice President, Finance and Chief Financial Officer of Baytex since September 2003; prior thereto Manager, Investor Relations, Pengrowth Energy Trust from 2001 to 2003; prior thereto, Corporate and Investment Banker with Scotia Capital.

Randal J. Best Calgary, Alberta	Vice President, Corporate Development	Vice President, Corporate Development of Baytex since September 2003; prior thereto Managing Director of Waterous Securities Inc. from 2000 to 2003; prior thereto President and CEO of Enercap Corporation, a private investment company.

Ralph W. Gibson Calgary, Alberta	Vice President, Marketing	Vice President, Marketing of Baytex since September 2001; prior thereto Vice President, Crude Oil of Canpet Energy Group Inc. since November 2000; prior thereto Vice President, Marketing of Ranger Oil Limited.

Anthony W. Marino Calgary, Alberta	Chief Operating Officer	Chief Operating Officer of Baytex since November 2004; prior thereto President and Chief Executive Officer of Dominion Exploration Canada Ltd. from 2002 to 2004; prior thereto Vice President, Engineering of Dominion Exploration & Production Inc. from January 2002 to October 2002; prior thereto Team Leader, Jonah/Pinedale asset area of AEC Oil & Gas (USA) Inc. from 2000 to 2002; prior thereto Division Manager, Engineering/New Ventures of Santa Fe Snyder Corporation.

Shannon M. Gangl Calgary, Alberta	Corporate Secretary	Partner, Burnet, Duckworth & Palmer LLP.

Notes:

(1) Member of our Audit Committee.

(2) Member of our Compensation Committee.

(3) Member of our Reserves Committee.

(4) Baytex’s directors hold office until the next annual general meeting of Unitholders or until each director’s successor is appointed or elected pursuant to the Business Corporations Act (Alberta).

(5) Mr. John Brussa was a director of Imperial Metals Limited, a corporation engaged in both oil and gas and mining operations, in the year prior to that corporation implementing a plan of arrangement under the Company Act (British Columbia) and under the Companies’ Creditors Arrangement Act (Canada) which resulted in the separation of its two businesses and the creation of two public corporations: Imperial Metals Corporation and IEI Energy Inc. (now Rider Resources Ltd.). The plan of arrangement was completed in April 2002.

(6) Mr. Shwed was a director of Echelon Energy Inc., a private company incorporated under the Business Corporations Act (Alberta). In September 1999, a receiver manager was appointed over the assets of Echelon.

As at February 28, 2005, the directors and executive officers of Baytex, as a group, beneficially owned, directly or indirectly, or exercised control or direction over 461,717 Trust Units, or approximately 0.70% of the issued and outstanding Trust Units. In addition, as at February 28, 2005, the directors and executive officers of Baytex, as a group, beneficially owned, directly or indirectly, exercised control or direction over, 605,129 Exchangeable Shares (approximately 33% of the issued and outstanding Exchangeable Shares).

Corporate Cease Trade Orders or Bankruptcies

No director, officer or promoter of Baytex has, within the last 10 years, been a director, officer or promoter of any reporting issuer that, while such person was acting in that capacity, was the subject of a cease trade or similar order or an order that denied the company access to any statutory exemption for a period of more than 30 consecutive days or was declared a bankrupt or made a voluntary assignment in bankruptcy, made a proposal under any legislation relating to bankruptcy or been subject to or instituted any proceedings, arrangement or compromise with creditors or had a receiver, receiver-manager or trustee appointed to hold the assets of that person other than as set forth herein.

Penalties or Sanctions

No director, officer or promoter of Baytex, within the last 10 years, has been subject to any penalties or sanctions imposed by a court or securities regulatory authority relating to trading in securities, promotion or management of a publicly traded issuer or theft or fraud.

Personal Bankruptcies

No director, officer or promoter of Baytex, or a shareholder holding sufficient securities of the Trust to affect materially the control of the Trust, or a personal holding company of any such persons, has, within the last 10 years, become bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency, or being subject to or instituted any proceedings, arrangement or compromise with creditors or had a receiver, receiver manager or trustee appointed to hold the assets of the individual.

Conflicts of Interest

There are potential conflicts of interest to which the directors and officers of Baytex will be subject in connection with the operations of Baytex. In particular, certain of the directors and officers of Baytex are involved in managerial or director positions with other oil and gas companies whose operations may, from time to time, be in direct competition with those of Baytex and the Trust or with entities which may, from time to time, provide financing to, or make equity investments in, competitors of Baytex and the Trust. Conflicts, if any, will be subject to the procedures and remedies available under the Business Corporations Act (Alberta). The Business Corporations Act (Alberta) provides that in the event that a director has an interest in a contract or proposed contract or agreement, the director will disclose his interest in such contract or agreement and will refrain from voting on any matter in respect of such contract or agreement unless otherwise provided in the Business Corporations Act (Alberta).

Personnel

As at December 31, 2004, Baytex employed 102 head office employees and 13 field office employees.

AUDIT COMMITTEE

The Audit Committee of Baytex is composed of the following members:

Name	Independent	Financially Literate	Relevant Education and Experience
Naveen Dargan	Yes	Yes	Master of Business Administration degree and Chartered Business Valuator designation. Independent businessman since June 2003; prior thereto Senior Managing Director of Raymond James Ltd. and predecessor companies.

W.A. Blake Cassidy	Yes	Yes	Retired banker.

Dale O. Shwed

Yes

President and Chief Executive Officer of Crew Energy Inc. since September 2003; prior thereto President and Chief Executive Officer of Baytex.

Although the Audit Committee has not adopted specific policies and procedures for the engagement of non-audit services by our auditors, it does pre-approve all non-audit services to be provided to us and our subsidiaries by the external auditors. The pre-approval for recurring tax and tax-related services is provided on an annual basis and other services are subject to pre-approval as required.

The following table provides information about the fees billed to us and our subsidiaries for professional services rendered by Deloitte & Touche LLP, our external auditors, during fiscal 2004 and 2003:

	Aggregate fees billed
	2004	2003
	($thousands)
Audit fees	109	156
Audit-related fees	146	218
Tax fees	184	101
All other fees	69	73
	508	548

Audit Fees. Audit fees consist of fees for the audit of our annual financial statements or services that are normally provided in connection with statutory and regulatory filings or engagements.

Audit-Related Fees. Audit-related services included audit of certain subsidiaries and financial aspects of us.

Tax Fees. Tax fees included tax planning and various taxation matters.

All Other Fees. Other services provided by our external auditor other than audit, audit-related and tax services.

The text of the Audit Committees’ Mandate and Terms of Reference is attached as Appendix C.

BAYTEX SHARE CAPITAL

Baytex is authorized to issue an unlimited number of common shares and an unlimited number of Exchangeable Shares. As of the date hereof, there are 1,852,744 Exchangeable Shares issued and outstanding. We are the sole holder of the issued and outstanding common shares of Baytex.

The following is a summary of certain provisions of the share capital of Baytex and the related and ancillary rights of holders of Exchangeable Share granted under the Voting and Exchange Trust Agreement and the Support Agreement. For a complete description of the share provisions and these related agreements, reference should be made to the Articles of Baytex and these agreements, copies of which been filed on SEDAR at www.sedar.com.

Common Shares

Each Baytex common share entitles its holder to receive notice of and to attend all meetings of the shareholders of Baytex and to one vote at such meetings. The holders of common shares will be, at the discretion of the Board of Directors and subject to applicable legal restrictions, and subject to certain preferences of holders of Exchangeable Shares, entitled to receive any dividends declared by the Board of Directors on the common shares to the exclusion of the holders of Exchangeable Shares, subject to the proviso that no dividends will be paid on the common shares unless all declared dividends on the outstanding Exchangeable Shares have been paid in full. The holders of common shares are entitled to share equally in any distribution of the assets of Baytex upon the liquidation, dissolution, bankruptcy or winding-up of Baytex or other distribution of its assets among its shareholders for the purpose of winding-up its affairs. Such participation is subject to the rights, privileges, restrictions and conditions attaching to the Exchangeable Shares and any other shares having priority over the common shares. At December 31, 2004, all of the common shares of Baytex are owned by us.

Exchangeable Shares

Each Exchangeable Share has economic rights (including the right to have the Exchange Ratio adjusted to account for distributions paid to Unitholders) and voting attributes (through the benefit of the Special Voting Units granted under Voting and Exchange Trust Agreement to the Trustee) equivalent to those of the Trust Units into which they are exchangeable from time to time. In addition, holders of Exchangeable Shares have the right to receive Trust Units at any time in exchange for their Exchangeable Shares, on the basis of the Exchange Ratio in effect at the time of the exchange. Holders of Exchangeable Shares do not receive cash distributions.

Ranking

The Exchangeable Shares rank rateably with shares of any other series of exchangeable shares of Baytex and prior to any common shares and any other shares ranking junior to the Exchangeable Shares with respect to the payment of dividends, if any, that have been declared and the distribution of assets in the event of the liquidation, dissolution or winding-up of Baytex.

Dividends

Holders of Exchangeable Shares are entitled to receive cash dividends if, as and when declared by the Board of Directors. Baytex anticipates that it may from time to time declare dividends on the Exchangeable Shares up to but not exceeding any cash distributions on the Trust Units into which such Exchangeable Shares are exchangeable. In the event that any such dividends are paid, the Exchange Ratio will be correspondingly reduced to reflect such dividends.

Certain Restrictions

Baytex will not, without obtaining the approval of the holders of the Exchangeable Shares as set forth below under the subheading “Amendment and Approval”:

(a) pay any dividend on the common shares or any other shares ranking junior to the common shares, other than stock dividends payable in common shares or any other shares ranking junior to the Exchangeable Shares;

(b) redeem, purchase or make any capital distribution in respect of the common shares of Baytex or any other shares ranking junior to the Exchangeable Shares;

(c) redeem or purchase any other shares of Baytex ranking equally with the Exchangeable Shares with respect to the payment of dividends or on any liquidation distribution; or

(d) issue any shares, other than Exchangeable Shares or common shares, which rank superior to the Exchangeable Shares with respect to the payment of dividends or on any liquidation distribution.

The above restrictions will not apply if all declared dividends on the outstanding Exchangeable Shares have been paid in full.

Liquidation or Insolvency of Baytex

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

Upon the occurrence of such an event, we and Baytex ExchangeCo each have the overriding right to purchase all but not less than all of the Exchangeable Shares then outstanding (other than Exchangeable Shares held by us or any of our subsidiaries) at a purchase price per Exchangeable Share to be satisfied by the issuance or delivery, as the case may be, of that number of Trust Units equal to the Exchange Ratio at such time and, upon the exercise of this right, the holders will be obligated to sell such Exchangeable Shares to us or Baytex ExchangeCo, as applicable.

Automatic Exchange Right on Liquidation of the Trust

The Voting and Exchange Trust Agreement provides that in the event of a “Trust liquidation event”, as described below, we or Baytex ExchangeCo will be deemed to have purchased all outstanding Exchangeable Shares and each holder of Exchangeable Shares will be deemed to have sold their Exchangeable Shares immediately prior to the Trust liquidation event at a purchase price per Exchangeable Share to be satisfied by the issuance or delivery, as the case may be, of that number of Trust Units equal to the Exchange Ratio of the Exchangeable Shares at that time. For this purpose, a “Trust liquidation event” means:

• any determination by us to institute voluntary liquidation, dissolution or winding-up proceedings or to effect any other distribution of our assets among Unitholders for the purpose of winding up our affairs; or

• the earlier of, us receiving notice of and us otherwise becoming aware of, any threatened or instituted claim, suit, petition or other proceedings with respect to the involuntary liquidation, dissolution or winding up of us or to effect any other distribution of our assets among Unitholders for the purpose of winding up our affairs in each case where we have failed to contest 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 retraction call right of the Trust and Baytex ExchangeCo described below, a holder of Exchangeable Shares will be entitled at any time to require Baytex to redeem any or all of the Exchangeable Shares held by such holder for a retraction price per Exchangeable Share equal to the value of that number of Trust Units equal to the Exchange Ratio as at the retraction date , to be satisfied by the delivery of such number of Trust Units.

Holders of the Exchangeable Shares may request redemption by presenting to Baytex or the transfer agent for the Exchangeable Shares a certificate or certificates representing the number of Exchangeable Shares the holder desires to have redeemed, together with a duly executed retraction request and such other documents as may be reasonably required to effect the redemption of the Exchangeable Shares. The redemption will become effective on the retraction date, which will be three business days after the date on which Baytex or the transfer agent receives the retraction notice.

When a holder requests Baytex to redeem the Exchangeable Shares, we and Baytex ExchangeCo will have a overriding right to purchase on the retraction date all of the Exchangeable Shares that the holder has requested Baytex to redeem at a purchase price per Exchangeable Share equal to the retraction price, to be satisfied by the delivery of that number of Trust Units equal to the Exchange Ratio at such time. At the time of such a request by a holder of Exchangeable Shares, Baytex will immediately notify us and Baytex ExchangeCo. We or Baytex ExchangeCo must then advise Baytex within two business days as to whether our purchase right will be exercised.

A holder may revoke his or her retraction request at any time prior to the close of business on the last business day immediately preceding the retraction date. Otherwise, the Exchangeable Shares that the holder has requested Baytex to redeem will be purchased by the Trust or Baytex ExchangeCo or redeemed by Baytex, as the case may be, in each case at a purchase price per Exchangeable Share equal to the retraction price.

In addition, a holder of Exchangeable Shares may elect to instruct the Trustee to exercise a right (Optional Exchange Right) to require us or Baytex ExchangeCo to acquire such holder’s Exchangeable Shares in circumstances where neither we nor Baytex ExchangeCo have exercised the overriding purchase right. See “Voting and Exchange Trust Agreement - Optional Exchange Right”. If, as a result of solvency provisions of applicable law, Baytex is not permitted to redeem all Exchangeable Shares tendered by a retracting holder, Baytex will redeem only those Exchangeable Shares tendered by the holder as would not be contrary to such provisions of applicable law. The holder of any Exchangeable Shares not redeemed by Baytex will be deemed to have required us to purchase such unretracted Exchangeable Shares in exchange for 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 law and the call rights of the Trust and Baytex ExchangeCo, Baytex:

(a) will, on September 2, 2013, subject to extension of such date by the Board of Directors, redeem all but not less than all of the then outstanding Exchangeable Shares for a redemption price per Exchangeable Share equal to the value of that number of Trust Units equal to the Exchange Ratio as at the last business day prior to that redemption date (the “redemption price”), to be satisfied by the delivery of such number of Trust Units;

(b) may, on September 2, 2005, redeem all but not less than all outstanding Exchangeable Shares for thre redemption price per Exchangeable Share at the last business day prior to the redemption date, to be satisfied by the delivery of Trust Units;

(c) may, on any date that is within the first 90 days of any calendar year, redeem up that number of Exchangeable Shares equal to 40% of the Exchangeable Shares which were outstanding on September 2, 2003 for the redemption price per Exchangeable Share at the last business day prior to that redemption date, to be satisfied by the delivery of Trust Units; and

(d) may, at any time when the aggregate number of issued and outstanding Exchangeable Shares is less than 1 million (other than Exchangeable Shares held by us and our subsidiaries and as such shares may be adjusted from time to time), redeem all but not less than all of the then outstanding Exchangeable Shares for the redemption price per Exchangeable Share (unless contested in good faith by the Trust).

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

The Trust and Baytex ExchangeCo have the right, notwithstanding a proposed redemption of the Exchangeable Shares by Baytex on the applicable redemption date, to purchase on any redemption date all but not less than all of the Exchangeable Shares then outstanding (other than Exchangeable Shares held by us and our subsidiaries) in exchange for the redemption price per Exchangeable Share and, upon the exercise of this right, the holders of all of the then outstanding Exchangeable Shares will be obliged to sell all such shares to us Baytex ExchangeCo, as applicable.

Voting Rights

Except as required by applicable law, the holders of the Exchangeable Shares are not entitled as such to receive notice of or attend any meeting of the shareholders of Baytex or to vote at any such meeting. Holders of Exchangeable Shares have the notice and voting rights respecting our meetings that are provided in the Voting and 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 changed only with the approval of the holders thereof. Any such approval or any other approval or consent to be given by the holders of the Exchangeable Shares will be sufficiently given if given in accordance with applicable law and subject to a minimum requirement that such approval or consent be evidenced by a resolution passed by not less than two-thirds of the votes cast thereon (other than shares beneficially owned by us, or any of our subsidiaries and other affiliates) at a meeting of the holders of the Exchangeable Shares duly called and held at which holders of at least 10% of the then outstanding Exchangeable Shares are present in person or represented by proxy. In the event that no such quorum is present at such meeting within one-half hour after the time appointed therefor, then the meeting will be adjourned to such place and time (not less than ten days later) as may be determined at the original meeting and the holders of Exchangeable Shares present in person or represented by proxy at the adjourned meeting will constitute a quorum thereat and may transact the business for which the meeting was originally called. At the adjourned meeting, a resolution passed by the affirmative vote of not less than two-thirds of the votes cast thereon (other than shares beneficially owned by us or any of our subsidiaries and other affiliates) will constitute the approval or consent of the holders of the Exchangeable Shares.

Actions by Us Under the Support Agreement and the Voting and Exchange Trust Agreement

Under the Exchangeable Share provisions, Baytex has agreed to take all such actions and do all such things as are necessary or advisable to perform and comply with its obligations under, and to ensure the performance and compliance by us and Baytex ExchangeCo with our respective obligations under, the Support Agreement and the Voting and Exchange Trust Agreement.

Non-Resident and Tax-Exempt Holders

The obligation of us, Baytex or Baytex ExchangeCo to deliver Trust Units to a non-resident holder in respect of the exchange of such holder’s Exchangeable Shares may be satisfied by delivering such Trust Units to the transfer agent who will sell such Trust Units on the stock exchange on which they are listed and deliver the proceeds of sale to the non-resident holder.

VOTING AND EXCHANGE TRUST AGREEMENT

The following is a summary of certain provisions of the Voting and Exchange Trust Agreement. For a complete description of the terms of the Voting and Exchange Agreement, reference should be made to this agreement, a copy of which has been filed on SEDAR at www.sedar.com.

Voting Rights

In accordance with the Voting and Exchange Trust Agreement, we have issued one (1) Special Voting Right to Valiant Trust Company, the Voting and Exchange Trust Agreement Trustee, for the benefit of the holders (other than us and Baytex ExchangeCo) of the Exchangeable Shares. The Special Voting Right carries a number of votes, exercisable at any meeting at which Unitholders are entitled to vote, equal to one vote for each Exchangeable Share outstanding. With respect to any written consent sought from Unitholders, each vote attached to the Special Voting Right will be exercisable in the same manner as set forth above.

Each holder of an Exchangeable Share on the record date for any meeting at which Unitholders are entitled to vote will be entitled to instruct the Voting and Exchange Trust Agreement Trustee to exercise that number of votes attached to the Special Voting Right which relate to the Exchangeable Shares held by such holder. The Voting and Exchange Trust Agreement Trustee will exercise each vote attached to the Special Voting Right only as directed by the relevant holder and, in the absence of instructions from a holder as to voting, will not exercise such votes.

The Trustee appointed under the Voting and Exchange Trust Agreement is required to send to the holders of the Exchangeable Shares a notice of each meeting at which Unitholders are entitled to vote, together with the related meeting materials and a statement as to the manner in which the holder may instruct the Voting and Exchange Trust Agreement Trustee to exercise the votes attaching to the Special Voting Right, at the same time as we send such notice and materials to Unitholders. The Voting and Exchange Trust Agreement Trustee is also required to send to the holders copies of all information statements, interim and annual financial statements, reports and other materials sent by us to Unitholders at the same time as such materials are sent to Unitholders. To the extent such materials are provided to the Voting and Exchange Trust Agreement Trustee by us, the Voting and Exchange Trust Agreement Trustee will also send to the holders all materials sent by third parties to Unitholders, including dissident proxy circulars and tender and exchange offer circulars, as soon as possible after such materials are first sent to Unitholders.

All rights of a holder of Exchangeable Shares to exercise votes attached to the Special Voting Right will cease upon the exchange of all such holder’s Exchangeable Shares for Trust Units. With the exception of administrative changes for the purpose of adding covenants for the protection of the holders of the Exchangeable Shares, making necessary amendments or curing ambiguities or clerical errors (in each case provided that the Board of Directors ExchangeCo and Baytex are of the opinion that such amendments are not prejudicial to the interests of the holders of the Exchangeable Shares), the Voting and Exchange Trust Agreement may not be amended without the approval of the holders of the Exchangeable Shares.

Optional Exchange Right

Upon the occurrence and during the continuance of:

(a) an Insolvency Event (as defined in the Exchangeable Share provisions); or

(b) circumstances in which we or Baytex ExchangeCo may exercise a Call Right (as defined in the Exchangeable Share provisions), but elect not to exercise such Call Right,

a holder of Exchangeable Shares will have the right (Optional Exchange Right) to instruct the Trustee to exercise the Optional Exchange Right with respect to any or all of the Exchangeable Shares held by such holder, thereby requiring us or Baytex ExchangeCo to purchase such Exchangeable Shares from the holder. Immediately upon the occurrence of (i) an Insolvency Event, (ii) any event which will, with the passage of time or the giving of notice, become an Insolvency Event, or (iii) the election by us and Baytex ExchangeCo not to exercise a Call Right which is then exercisable by us and Baytex ExchangeCo, Baytex, the Trust or Baytex ExchangeCo will give notice thereof to the Trustee. As soon as practicable thereafter, the Trustee will then notify each affected holder of Exchangeable Shares (who has not already provided instructions respecting the exercise of the Optional Exchange Right) of such event or potential event and will advise such holder of its rights with respect to the Optional Exchange Right.

The purchase price payable by us or Baytex ExchangeCo for each Exchangeable Share to be purchased under the Optional Exchange Right will be satisfied by the issuance of that number of Trust Units equal to the Exchange Ratio as at the last business day prior to the day of closing of the purchase and sale of such Exchangeable Share under the Exchange Right.

If, as a result of solvency provisions of applicable law, Baytex is unable to redeem all of a holder’s Exchangeable Shares which such holder is entitled to have redeemed in accordance with the Exchangeable Share provisions, the holder will be deemed to have exercised the optional exchange right with respect to the unredeemed Exchangeable Shares and we or Baytex ExchangeCo will be required to purchase such shares from the holder in the manner set forth above.

SUPPORT AGREEMENT

The following is a summary of certain provisions of the Support Agreement, a copy of which has been filed on SEDAR at www.sedar.com.

Under the Support Agreement, we have agreed that:

(a) we will take all actions and do all things necessary to ensure that Baytex is able to pay to the holders of the Exchangeable Shares the amounts required under the Exchangeable Share provisions in the event of a liquidation, dissolution or winding-up of Baytex, the retraction price in the event of the giving of a retraction request by a holder of Exchangeable Shares or in the event of a redemption of Exchangeable Shares by Baytex; and

(b) we will not vote or otherwise take any action or omit to take any action causing the liquidation, dissolution or winding-up of Baytex.

The Support Agreement also provides that we will not issue or distribute to the holders of all or substantially all of the outstanding Trust Units:

(a) additional Trust Units or securities convertible into Trust Units;

(b) rights, options or warrants for the purchase of Trust Units; or

(c) units or securities of the Trust other than Trust Units, evidences of indebtedness of the Trust or other assets of the Trust;

unless the same or an equivalent distribution is made to holders of Exchangeable Shares, an equivalent change is made to the Exchangeable Shares, such issuance or distribution is made in connection with a distribution reinvestment plan instituted for holders of Trust Units or a unitholder rights protection plan approved for holders of Trust Units by the Board of Directors or the approval of holders of Exchangeable Shares has been obtained.

In addition, we may not subdivide, reduce, consolidate, reclassify or otherwise change the terms of the Trust Units unless an equivalent change is made to the Exchangeable Shares or the approval of the holders of Exchangeable Shares has been obtained.

In the event of any proposed take-over bid, issuer bid or similar transaction affecting the Trust Units, we have agreed to use reasonable efforts to take all actions necessary or desirable to enable holders of Exchangeable Shares to participate in such transaction to the same extent and on an economically equivalent basis as Unitholders.

The Support Agreement also provides that, as long as any outstanding Exchangeable Shares are owned by any person or entity other than us or any of our subsidiaries or affiliates, we will, unless approval to do otherwise is obtained from the holders of Exchangeable Shares, remain the direct or indirect beneficial owner collectively of more than 50% of all of the issued and outstanding voting securities of Baytex, provided that we will not be in violation of this obligation if a party acquires all or substantially all of our assets.

With the exception of administrative changes for the purpose of adding covenants for the protection of the holders of the Exchangeable Shares, making certain necessary amendments or curing ambiguities or clerical errors (in each case provided that the Board of Directors and the Trustee are of the opinion that such amendments are not prejudicial to the interests of the holders of the Exchangeable Shares), the Support Agreement may not be amended without the approval of the holders of the Exchangeable Shares.

Under the Support Agreement, we have also agreed to not exercise any voting rights attached to the Exchangeable Shares owned by us or any of our respective subsidiaries and other affiliates on any matter considered at meetings of holders of Exchangeable Shares (including any approval sought from such holders in respect of matters arising under the Support Agreement).

We have also agreed to make such filings and seek such regulatory consents and approvals as are necessary so that the Trust Units issuable upon the exchange of Exchangeable Shares will be issued in compliance with applicable securities laws in Canada and may be traded freely on the Toronto Stock Exchange or such other exchange on which the Trust Units may be listed, quoted or posted for trading from time to time.

MARKET FOR SECURITIES

The Trust Units are listed for trading on the Toronto Stock Exchange under the symbol “BTE.UN”. The following table sets forth the high and low closing trading prices and the aggregate volume of trading of the Trust Units as reported by the Toronto Stock Exchange for the periods indicated. the Trust Units commenced trading on the Toronto Stock Exchange on September 8, 2003.

	Price Range		Volume Traded
	High	Low	Volume Traded
	($)	($)
2003
September	10.85	9.19	9,992,166
October	10.65	9.49	13,469,910
November	10.64	9.98	7,380,404
December	10.89	9.97	10,131,182

2004
January	11.45	10.60	8,866,915
February	10.82	9.78	11,503,106
March	11.32	10.25	14,408,162
April	12.32	11.00	7,312,078
May	12.60	11.51	10,079,917
June	12.32	11.29	4,590,663
July	12.65	11.95	3,819,217
August	12.90	11.90	4,912,537
September	13.13	11.65	4,964,218
October	14.00	12.79	9,654,989
November	13.70	12.60	7,049,582
December	13.42	12.61	6,091,424

	Price Range		Volume Traded
	High	Low	Volume Traded
	($)	($)
2005
January	13.26	12.42	6,261,488
February .	15.07	13.25	11,885,861

LEGAL PROCEEDINGS

There are no outstanding legal proceedings involving claims for damages, exclusive of interest and costs, in excess of ten percent (10%) of our current assets, to which we are party or of which any of our properties are subject, nor are there any such proceedings known to be contemplated.

INTEREST OF INSIDERS AND OTHERS IN MATERIAL TRANSACTIONS

There were no material interests, direct or indirect, of directors and senior officers of the Trust, nominees for director, any Unitholder who beneficially owns more than 10% of the Trust Units or any known associate or affiliate of such persons in any transaction since the beginning of the Trust’s last completed financial year or in any proposed transaction which has materially affected or would materially affect the Trust.

AUDITORS, TRANSFER AGENT AND REGISTRAR

Our Independant Registered Chartered Accountants are Deloitte & Touche LLP, Calgary, Alberta.

Valiant Trust Company, at its principal office in Calgary, Alberta and through its co-agent, Equity Transfer Services Inc., at its principal office in Toronto, Ontario is the transfer agent and registrar for the Trust Units.

INTERESTS OF EXPERTS

There is no person or company whose profession or business gives authority to a statement made by such person or company and who is named as having prepared or certified a statement, report or valuation described or included in a filing, or referred to in a filing, made under National Instrument 51-102 by us during, or related to, our most recently completed financial year other than Sproule, our independent engineering evaluator. None of the principals of Sproule had any registered or beneficial interests, direct or indirect, in any of our securities or other property or of our associates or affiliates either at the time they prepared the statement, report or valuation prepared by it, at any time thereafter or to be received by them. The auditors of the Trust are Deloitte & Touche, LLP, Independent Registered Chartered Accountants, Calgary, Alberta.

In addition, none of the aforementioned persons or companies, nor any director, officer or employee of any of the aforementioned persons or companies, is or is expected to be elected, appointed or employed as a director, officer or employee of Baytex or of any associate or affiliate of Baytex, except for John Brussa, a director of Baytex and Shannon Gangl, the Corporate Secretary of Baytex, are partners at Burnet, Duckworth & Palmer LLP, which law firm renders legal services to us.

INDUSTRY CONDITIONS

General

The oil and natural gas industry is subject to extensive controls and regulations governing its operations (including land tenure, exploration, development, production, refining, transportation and marketing) imposed by legislation enacted by various levels of government and with respect to pricing and taxation of oil and natural gas by agreements among the governments of Canada, Alberta, British Columbia and Saskatchewan, all of which should be carefully considered by investors in the oil and gas industry. It is not expected that any of these controls or regulations will affect our operations in a manner materially different than they would affect other oil and gas companies of similar size. All current legislation is a matter of public record and we are unable to predict what additional legislation or amendments may be enacted. Outlined below are some of the principal aspects of legislation, regulations and agreements governing the oil and gas industry.

Pricing and Marketing Oil and Natural Gas

The producers of oil are entitled to negotiate sales contracts directly with oil purchasers, with the result that the market determines the price of oil. Such price depends in part on oil quality, prices of competing energy, distance to market, the value of refined products and the supply/demand balance. Oil exporters are also entitled to enter into export contracts with terms not exceeding one year in the case of light crude oil and two years in the case of heavy crude oil, provided that an order approving such export has been obtained from 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 licence from the NEB and the issuance of such licence requires the approval of the Governor in Council.

The price of natural gas is determined by negotiation between buyers and sellers. Natural gas exported from Canada is subject to regulation by the NEB and the Government of Canada. Exporters are free to negotiate prices with purchasers, provided that the export contracts must continue to meet certain other criteria prescribed by the NEB and the Government of Canada. Natural gas exports for a term of less than 2 years or for a term of 2 to 20 years (in quantities of not more than 30,000 m³/day) must be made pursuant to an NEB order. Any natural gas export to be made pursuant to a contract of longer duration (to a maximum of 25 years) or a larger quantity requires an exporter to obtain an export licence from the NEB and the issuance of such licence requires the approval of the Governor in Council.

The governments of Alberta, British Columbia and Saskatchewan also regulate the volume of natural gas which may be removed from those provinces for consumption elsewhere based on such factors as reserve ability, transportation arrangements and market considerations.

From time to time pipeline capacity limits the ability to produce and market crude oil and natural gas production although pipeline expansions are ongoing.

The North American Free Trade Agreement

The North 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 the material energy terms that are contained in the Canada United States Free Trade Agreement. Canada continues to remain free to determine whether exports of energy resources to the United States or Mexico will be allowed, provided that any export restrictions do not: (i) reduce the proportion of energy resources exported relative to domestic use (based upon the proportion prevailing in the most recent 36 month period); (ii) impose an export price higher than the domestic price; or (iii) disrupt normal channels of supply. All three countries are prohibited from imposing minimum export or import price requirements.

NAFTA contemplates the reduction of Mexican restrictive trade practices in the energy sector and prohibits discriminatory border restrictions and export taxes. The agreement also contemplates clearer disciplines on regulators to ensure fair implementation of any regulatory changes and to minimize disruption of contractual arrangements, which is important for Canadian natural gas exports.

Provincial Royalties and Incentives

In addition to federal regulation, each province has legislation and regulations which govern land tenure, royalties, production rates, environmental protection and other matters. The royalty regime is a significant factor in the profitability of crude oil, natural gas liquids, sulphur and natural gas production. Royalties payable on production from lands other than Crown lands are determined by negotiations between the mineral owner and the lessee, although production from such lands is subject to certain provincial taxes and royalties. Crown royalties are determined by governmental regulation and are generally calculated as a percentage of the value of the gross production. The rate of royalties payable generally depends in part on prescribed reference prices, well productivity, geographical location, field discovery date and the type or quality of the petroleum product produced.

From time to time the governments of the western Canadian provinces create incentive programs for exploration and development. Such programs often provide for royalty rate reductions, royalty holidays and tax credits, and are generally introduced when commodity prices are low. The programs are designed to encourage exploration and development activity by improving earnings and cash flow within the industry.

In the Province of Alberta, a producer of oil or natural gas is entitled to a credit against the royalties payable to the Crown by virtue of the Alberta royalty tax credit (“ARTC”) program. The ARTC rate is based on a price sensitive formula and the ARTC rate varies between 75% at prices at and below $100 per m³and 25% at prices at and above $210 per m³. The ARTC rate is applied to a maximum of $2,000,000 of Alberta Crown royalties payable for each producer or associated group of producers. Crown royalties on production from producing properties acquired from a corporation already claiming maximum entitlement to ARTC will 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 quarterly period.

Crude oil and natural gas royalty programs for specific wells and royalty reductions reduce the amount of Crown royalties paid by our operating entities to the provincial governments. In general, the ARTC program provides a rebate on Alberta Crown royalties paid in respect of eligible producing properties.

Land Tenure

Crude oil and natural gas located in the western provinces is owned predominantly by the respective provincial governments. Provincial governments grant rights to explore for and produce oil and natural gas pursuant to leases, licences and permits for varying terms generally from two to five years and on conditions set forth in provincial legislation including requirements to perform specific work or make payments. Oil and natural gas located in such provinces can also be privately owned and rights to explore for and produce such oil and natural gas are granted by lease on such terms and conditions as may be negotiated.

Environmental Regulation

The oil and natural gas industry is currently subject to environmental regulations pursuant to a variety of provincial and federal legislation. Such legislation provides for restrictions and prohibitions on the release or emission of various substances produced in association with certain oil and gas industry operations. In addition, such legislation requires that well and facility sites be abandoned and reclaimed to the satisfaction of provincial authorities. Compliance with such legislation can require significant expenditures and a breach of such requirements may result in suspension or revocation of necessary licenses and authorizations, civil liability for pollution damage and the imposition of material fines and penalties.

Environmental legislation in the Province of Alberta has been consolidated into the Alberta Environmental Protection and Enhancement Act (the “APEA”), which came into force on September 1, 1993. The APEA imposes stricter environmental standards, requires more stringent compliance, reporting and monitoring obligations and significantly increases penalties. We are committed to meeting its responsibilities to protect the environment wherever it operates and anticipates making increased expenditures of both a capital and an expense nature as a result of the increasingly stringent laws relating to the protection of the environment and will be taking such steps as required to ensure compliance with the APEA and similar legislation in other jurisdictions in which it operates. We believe that we are in material compliance with applicable environmental laws and regulations. We also believe that it is reasonably likely that the trend towards stricter standards in environmental legislation and regulation will continue.

In December 2002, the Government of Canada ratified the Kyoto Protocol and it became legally binding on February 16, 2005. This protocol calls for Canada to reduce its green house gas emissions to 6% below 1990 levels during the period between 2008 and 2012. See also “Risk Factors – Kyoto Protocol”.

RISK FACTORS

The following is a summary of certain risk factors relating to our business. The following information is a summary only of certain risk factors and is qualified in its entirety by reference to, and must be read in conjunction with, the detailed information appearing elsewhere in this Annual Information Form.

Dependence on Baytex

We are an open-ended, limited purpose trust which is entirely dependent upon the operations and assets of Baytex through our ownership of the common shares, the Notes and the NPI. Accordingly, the cash distributions to Unitholders will be dependent upon the ability of Baytex to meet its interest and principal repayment obligations under the Notes, to declare and pay dividends on the common shares, and to pay the NPI. Baytex’s income will be received from the production of oil and natural gas from Baytex’s existing resource properties and will be susceptible to the risks and uncertainties associated with the oil and natural gas industry generally. If the oil and natural gas reserves associated with Baytex’s resource properties are not supplemented through additional development or the acquisition of additional oil and natural gas properties, the ability of Baytex to meet its obligations to us may be adversely affected.

Exploitation and Development

Exploitation and development risks are due to the uncertain results of searching for and producing oil and natural gas using imperfect scientific methods. These risks are mitigated by using highly skilled staff, focusing exploitation efforts in areas in which we have existing knowledge and expertise or access to such expertise, using up-to-date technology to enhance methods, and controlling costs to maximize returns. Advanced oil and natural gas related technologies such as three-dimensional seismography, reservoir simulation studies and horizontal drilling have been used by us and will be used by us to improve our ability to find, develop and produce oil and natural gas.

Operations

Our operations are subject to all of the risks normally incident to the operation and development of oil and natural gas properties and the drilling of oil and natural gas wells, including encountering unexpected formations or pressures, blow-outs, craterings and fires, all of which could result in personal injuries, loss of life and damage to our property and others. We have both safety and environmental policies in place to protect our operators and employees, as well as to meet the regulatory requirements in those areas where we operate. In addition, we have liability insurance policies in place, in such amounts as we consider adequate, however, we are not be fully insured against all of these risks, nor are all such risks insurable.

Continuing production from a property, and, to some extent the marketing of production therefrom, are largely dependent upon the ability of the operator of the property. To the extent the operator fails to perform these functions properly, revenue may be reduced. Payments from production generally flow through the operator and there is a risk of delay and additional expense in receiving such revenues if the operator becomes insolvent. Although satisfactory title reviews are generally conducted in accordance with industry standards, such reviews do not guarantee or certify that a defect in the chain of title may not arise to defeat the claim of Baytex to certain properties. A reduction of the income from the NPI could result in such circumstances.

Oil and Natural Gas Prices

The price of oil and natural gas will fluctuate and price and demand are factors beyond our control. Such fluctuations will have a positive or negative effect on the revenue to be received by it. Such fluctuations will also have an effect on the acquisition costs of any future oil and natural gas properties that Baytex may acquire. As well, cash distributions from us will be highly sensitive to the prevailing price of crude oil and natural gas.

Marketing

The marketability and price of oil and natural gas that may be acquired or discovered by us will be affected by numerous factors beyond its control. These factors include demand for oil and natural gas, market fluctuations, the proximity and capacity of oil and natural gas pipelines and processing equipment and government regulations, including regulations relating to environmental protection, royalties, allowable production, pricing, importing and exporting of oil and natural gas.

Capital Investment

The timing and amount of capital expenditures will directly affect the amount of income for distribution to Unitholders. Distributions may be reduced, or even eliminated, at times when significant capital or other expenditures are made.

Debt Service

Baytex has credit facilities in the amount of $250 million. Variations in interest rates and scheduled principal repayments could result in significant changes in the amount required to be applied to debt service before payment of any amounts to us. Although it is believed that the bank line of credit is sufficient, there can be no assurance that the amount will be adequate for the financial obligations of Baytex or that additional funds can be obtained.

The lenders have been provided with security over substantially all of the assets of Baytex. If Baytex becomes unable to pay its debt service charges or otherwise commits an event of default such as bankruptcy, the lenders may foreclose on or sell the properties free from or together with the NPI.

Reserves

Although we, together with Sproule, have carefully prepared the reserve figures included herein and believe that the methods of estimating reserves have been verified by operating experience, such figures are estimates and no assurance can be given that the indicated levels of reserves will be produced. Probable reserves estimated for properties may require revision based on the actual development strategies employed to prove such reserves. Declines in our reserves which are not offset by the acquisition or development of additional reserves may reduce the underlying value of Trust Units to Unitholders. Trust Units will have no value once all of the oil and natural gas reserves of Baytex have been produced. As a result, holders of Trust Units will have to obtain the return of capital invested out of cash flow derived from their investment in such Trust Units.

Competition

The industry is highly competitive in the acquisition of exploration prospects and the development of new sources of production and the sale of oil and natural gas.

Environmental Concerns

The oil and natural gas industry is subject to environmental regulation pursuant to local, provincial and federal legislation. A breach of such legislation may result in the imposition of fines or issuance of clean-up orders in respect of Baytex or the properties. Such legislation may be changed to impose higher standards and potentially more costly obligations on Baytex. Baytex provides for the necessary amounts in its annual capital budget for the purpose of funding its currently estimated future environmental and reclamation obligations based on its current knowledge. There can be no assurance that the Trust will be able to satisfy its actual future environmental and reclamation obligations.

Delay in Cash Distributions

In addition to the usual delays in payment by purchasers of oil and natural gas to the operators of the properties, and by the operator to Baytex, payments between any of such parties may also be delayed by restrictions imposed by lenders, delays in the sale or delivery of products, delays in the connection of wells to a gathering system, blowouts or other accidents, recovery by the operator of expenses incurred in the operation of the properties, or the establishment by the operator of reserves for such expenses.

Depletion of Reserves

We have certain unique attributes that differentiate us from other oil and gas industry participants. Distributions of distributable income in respect of properties, absent commodity price increases or cost effective acquisition and development activities will decline over time in a manner consistent with declining production from typical oil, natural gas and natural gas liquids reserves. Baytex will not be reinvesting cash flow in the same manner as other industry participants. Accordingly, absent capital injections, Baytex’s initial production levels and reserves will decline.

Baytex’s future oil and natural gas reserves and production, and therefore its cash flows, will be highly dependent on Baytex’s success in exploiting its reserve base and acquiring additional reserves. Without reserve additions through acquisition or development activities, Baytex’s reserves and production will decline over time as reserves are exploited.

To the extent that external sources of capital, including the issuance of additional Trust Units, become limited or unavailable, Baytex’s ability to make the necessary capital investments to maintain or expand its oil and natural gas reserves will be impaired. To the extent that Baytex is required to use cash flow to finance capital expenditures or property acquisitions, the level of distributable income will be reduced.

There can be no assurance that Baytex will be successful in developing or acquiring additional reserves on terms that meet our investment objectives.

Variations in Interest Rates and Foreign Exchange Rates

Variations in interest rates could result in a significant change in the amount we pay to service debt, potentially impacting distributions to Unitholders.

In addition, the exchange rate for the Canadian dollar versus the U.S. dollar has increased significantly over the last 24 months, resulting in the receipt by us of fewer Canadian dollars for our production which may affect future distributions. We have initiated certain hedges to mitigate these risks. The increase in the exchange rate for the Canadian dollar and future Canadian/United States exchange rates may impact future distributions and the future value of our reserves as determined by independent evaluators.

Distributions

Our historical distribution may not be reflective of future distribution payments, which will be subject to review by the Board of Directors taking into account our prevailing financial circumstances at the relevant time. The actual amount distributed, if any, is dependent on the commodity price environment and is at the discretion of the Board of Directors.

Distributable cash available for distribution is not an earnings measure recognized by generally accepted accounting principles and is not necessarily comparable to the measurement of distributable cash available for distribution in other similar trust entities.

Mutual Fund Trust Status

It is intended that we will continue to qualify as a mutual fund trust for the purposes of the Income Tax Act (Canada) (the “Tax Act”). We may not, however, always be able to satisfy any future requirement for the maintenance of mutual fund trust status. Should our status as a mutual fund trust be lost or successfully challenged by a relevant tax authority, certain adverse consequences may arise for us and Unitholders. Some of the significant consequences of losing mutual fund trust status are as follows:

• Where at the end of any month a registered retirement savings plan (“RRSP”), registered retirement income fund (“RRIF”), registered education savings plan (“RESP”) or deferred profit sharing plan (“DPSP”) (collectively, “Exempt Plans”) holds Trust Units that are not qualified investments, the Exempt Plan must, in respect of that month, pay a tax under Part XI. 1 of the Tax Act equal to 1 percent of the fair market value of the Trust Units at the time such Trust Units were acquired by the Exempt Plan. An RRSP or RRIF holding Trust Units that are not qualified investments would become taxable on income attributable to the Trust Units while they are not qualified investments (including the entire amount of any capital gain arising on a disposition of the non-qualified investment). RESPs which hold Trust Units that are not qualified investments may have their registration revoked by the Canada Customs and Revenue Agency.

• Trust Units would become foreign property for Exempt Plans upon the Trust ceasing to be a mutual fund trust.

• The Trust would be taxed on certain types of income distributed to Unitholders, including income generated by the royalty held by the Trust. Payment of this tax may have adverse consequences for some Unitholders, particularly Unitholders that are not residents of Canada and residents of Canada that are otherwise exempt from Canadian income tax.

• The Trust would cease to be eligible for the capital gains refund mechanism available under Canadian tax laws.

• Trust Units would become taxable Canadian property. As a result, non-resident Unitholders would be subject to Canadian income tax on any gains realized on a disposition of Trust Units held by them.

In addition, we may take certain measures in the future to the extent we believe such measures are necessary to ensure we maintain our status as a mutual fund trust. These measures could be adverse to certain holders of Trust Units.

Non-resident Ownership of Trust Units

In order for us to maintain our status as a mutual fund trust under the Tax Act, we must not be established or maintained primarily for the benefit of non-residents of Canada (“non-residents”) within the meaning of the Tax Act. The Trust Indenture provides that if at any time we or Baytex becomes aware that the beneficial owners of 50% or more of the Trust Units then outstanding are or may be non-residents or that such a situation is imminent, we, by or through Baytex on our behalf, will take such action as may be necessary to carry out the foregoing intention.

Income Tax Matters

Generally, oil and gas income trusts including this income trust involve significant amounts of inter-company debt, royalties or similar instruments, generating substantial interest expense or other deductions which serve to reduce taxable income and income tax payable. There can be no assurance that the taxation authorities will not seek to challenge the amount of interest expense and other deductions. If such a challenge were to succeed against us, it could materially adversely affect the amount of distributions available to us. We believe that the interest expense inherent in our structure is supportable and reasonable in light of the terms of the Notes.

Nature of Trust Units

The Trust Units do not represent a traditional investment in the oil and natural gas sector and should not be viewed by investors as shares in Baytex. The Trust Units represent a fractional interest in the Trust. As holders of Trust Units, Unitholders will not have the statutory rights normally associated with ownership of shares of a corporation including, for example, the right to bring “oppression” or “derivative” actions. Our primary assets will be the Notes, common shares, the NPI and other investments in securities. The price per Trust Unit is a function of anticipated distributable income, the properties acquired by Baytex, and Baytex’s ability to effect long-term growth in the value of the Trust. The market price of the Trust Units will be sensitive to a variety of market conditions including, but not limited to, interest rates and our ability to acquire oil and natural gas properties. Changes in market conditions may adversely affect the trading price of the Trust Units.

The Trust Units are not “deposits” within the meaning of the Canada Deposit Insurance Corporation Act (Canada) and are not insured under the provisions of that Act or any other legislation. Furthermore, we are not a trust company and, accordingly, is not registered under any trust and loan company legislation as it does not carry on or intend to carry on the business of a trust company.

Redemption Right

It is anticipated that the redemption right will not be the primary mechanism for Unitholders to liquidate their investments. Notes or Redemption Notes which may be distributed in specie to Unitholders in connection with a redemption will not be listed on any stock exchange and no established market is expected to develop for such Notes or Redemption Notes. Cash redemptions are subject to limitations. See “Additional Information Respecting Baytex Energy Trust - - Redemption Right”.

Unitholder Limited Liability

The Trust Indenture provides that no Unitholder will be subject to any liability in connection with the Trust or its affairs or obligations and, in the event that a court determines that Unitholders are subject to any such liabilities, the liabilities will be enforceable only against, and will be satisfied only out of, the Unitholder’s share of our assets.

The Trust Indenture provides that all written instruments signed by us or on our behalf must contain a provision to the effect that such obligation will not be binding upon Unitholders personally. Personal liability may also arise in respect of claims against the Trust that do not arise under contracts, including claims in tort, claims for taxes and possibly certain other statutory liabilities. The possibility of any personal liability of this nature arising is considered unlikely.

Our operations will be conducted, upon the advice of counsel, in such a way and in such jurisdictions as to avoid as far as possible any material risk of liability on Unitholders for claims against us.

In addition, on July 1, 2004 the Income Trusts Liability Act (Alberta) came into force, creating a statutory limitation on the liability of unitholders of Alberta income trusts such as ust. The legislation provides that a unitholder will not be, as a beneficiary, liable for any act, default, obligation or liability of the trustee that arises after July 1, 2004.

Permitted Investments

An investment in the Trust should be made with the understanding that the value of any of our investments may fluctuate in accordance with changes in the financial condition of the issuers of the investment vehicle, the value of similar securities, and other factors. For example, the prices of Canadian government securities, bankers’ acceptances and commercial paper react to economic developments and changes in interest rates. Commercial paper is also subject to issuer credit risk. Investments in energy-related income trusts, companies and partnerships will be subject to the general risks of investing in equity securities. These include the risk that the financial condition of issuers may become impaired, or that the energy sector may suffer a market downturn. Securities markets in general are affected by a variety of factors, including governmental, environmental, and regulatory policies, inflation and interest rates, economic cycles, and global, regional and national events. The value of Trust Units could be affected by adverse changes in the market values of such investments.

Regulatory Matters

Baytex’s operations are subject to a variety of federal and provincial laws and regulations, including laws and regulations relating to the protection of the environment.

Kyoto Protocol

Canada is a signatory to the United Nations Framework Convention on Climate Change and has ratified the Kyoto Protocol established thereunder to set legally binding targets to reduce nationwide emissions of carbon dioxide, methane, nitrous oxide and other so-called “greenhouse gases”. Our exploration and production facilities and other operations and activities emit greenhouse gases that may subject us to legislation regulating emissions of greenhouse gases. The Government of Canada has put forward a Climate Change Plan for Canada which suggests further legislation will set greenhouse gases emission reduction requirements for various industrial activities, including oil and gas exploration and production. While the protocol became legally binding on February 16, 2005, details of any specific requirements have not been released. However, the Canadian Association of Petroleum Producers has secured specific non-binding limitations from the Government of Canada on reductions required by the oil and gas industry and the cost thereof. On the basis of these limitations, the impact of the Kyoto Protocol on our operations is currently not expected to be material.

Future federal legislation together with provincial emission reduction requirements, such as those proposed in Alberta’s Bill 37 Climate Change and Emissions Management may require the reduction of emissions or emissions intensity of our operations and facilities beyond what was agreed to by the Canadian Association of Petroleum Producers. The direct or indirect costs of these regulations may adversely affect our business.

Conflicts of Interest

The directors and officers of Baytex are engaged in and will continue to engage in other activities in the oil and natural gas industry and, as a result of these and other activities, the directors and officers of the Corporation may become subject to conflicts of interest. The Business Corporations Act (Alberta) provides that in the event that a director has an interest in a contract or proposed contract or agreement, the director will disclose his interest in such contract or agreement and will refrain from voting on any matter in respect of such contract or agreement unless otherwise provided under the Business Corporations Act (Alberta). To the extent that conflicts of interest arise, such conflicts will be resolved in accordance with the provisions of the Business Corporations Act (Alberta).

As at the date hereof, we are not aware of any existing or potential material conflicts of interest between the Trust and Baytex and a director or officer of Baytex.

ADDITIONAL INFORMATION

Additional information including remuneration of directors and officers of Baytex, principal holders of the Trust Units, Exchangeable Share and rights to purchase Trust Units, will be contained in our Information Circular which relates to the Annual and Special Meeting of Unitholders to be held on May 11, 2005, and additional financial information is provided in our consolidated financial statements and management discussion and analysis of financial results for the year ended December 31, 2004 which are attached hereto as Appendix D and which have been filed on SEDAR at www.sedar.com.

The Trust will provide to any person, upon request to the Chief Financial Officer of the Corporation:

1. when the securities of the Trust are in the course of a distribution pursuant to a preliminary short form prospectus or a short form prospectus:

(a) one copy of the Annual Information Form of the Trust, together with one copy of any document, or the pertinent pages of any document, incorporated by reference in the Annual Information Form;

(b) one copy of the comparative financial statements of the Trust for its most recently completed fiscal period for which financial statements have been filed, together with the accompanying report of the auditor and one copy of the most recent interim financial statements of the Trust that have been filed, if any, for any period after the end of its most recently completed financial year;

(c) one copy of the Information Circular of the Trust in respect of its most recent annual and special meeting of Unitholders; and

(d) one copy of any other documents that are incorporated by reference into the preliminary short form prospectus or the short form prospectus and which are not required to be provided under items (a) to (c) above; or

2. at any other time, one copy of any documents referred to in items (1)(a), (b) and (c) above, provided that the Trust may require the payment of a reasonable charge if the request is made by a person who is not a security holder of the Trust.

For additional copies of this Annual Information Form and the materials listed in the preceding paragraphs, please contact:

Baytex Energy Trust
2200, 205 – 5^th Avenue S.W.

Calgary, Alberta T2P 2V7

Phone: (403) 269-4282

Fax: (403) 205-3845

www.baytex.ab.ca

APPENDIX A

REPORT OF MANAGEMENT AND DIRECTORS ON RESERVES DATA AND OTHER INFORMATION

Management of Baytex, on behalf of the Trust, are responsible for the preparation and disclosure of information with respect to the oil and gas activities of Baytex in accordance with securities regulatory requirements. This information includes reserves data, which consist of the following:

(a) (i) proved and proved plus probable oil and gas reserves estimated as at December 31, 2004 using forecast prices and costs; and

(ii) the related estimated future net revenue; and

(b) (i) proved and proved plus probable oil and gas reserves estimated as at December 31, 2004 using constant prices and costs; and

(ii) the related estimated future net revenue.

An independent qualified reserves evaluator has evaluated the Trust’s reserves data. The report of the independent qualified reserves evaluator is presented below.

The Reserves Committee of the Board of Directors of the Baytex, on behalf of the Trust, has

(a) reviewed Baytex’s procedures for providing information to the independent qualified reserves evaluator;

(b) met with the independent qualified reserves evaluator to determine whether any restrictions affected the ability of the independent qualified reserves evaluator to report without reservation; and

The Reserves Committee of the Board of Directors of the Baytex, on behalf of the Trust, has reviewed Baytex’s procedures for assembling and reporting other information associated with oil and gas activities and has reviewed that information with management. The Board of Directors has, on the recommendation of the Audit Committee, approved

(a) the content and filing with securities regulatory authorities of the reserves data and other oil and gas information;

(b) the filing of the report of the independent qualified reserves evaluator on the reserves data; and

Because the reserves data are based on judgments regarding future events, actual results will vary and the variations may be material.

(signed) “Raymond T. Chan”		(signed) “Daniel G. Belot”
Raymond T. Chan		Daniel G. Belot
President and Chief Executive Officer		Vice President, Finance and Chief Financial Officer

(signed) “Dale O. Shwed”“		(signed) “John A. Brussa”
Dale O. Shwed		John A. Brussa
Director		Director

February 28, 2005

APPENDIX B

REPORT ON RESERVES DATA

To the Board of Directors of Baytex Energy Ltd. (“Baytex”), on behalf of Baytex Energy Trust (the “Trust”):

1. We have evaluated the reserves data of the Trust as at December 31, 2004. The reserves data consist of the following:

(a) (i) proved and proved plus probable oil and gas reserves estimated as at December 31, 2004 using forecast prices and costs; and

(ii) the related estimated future net revenue; and

(b) (i) proved oil and gas and proved plus probable reserves estimated as at December 31, 2004 using constant prices and costs; and

(ii) the related estimated future net revenue.

2. The reserves data are the responsibility of Baytex’s management. Our responsibility is to express an opinion on the reserves data based on our evaluation.

We carried out our evaluation in accordance with standards set out in the Canadian Oil and Gas Evaluation Handbook (the “COGE Handbook”) prepared jointly by the Society of Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum Society).

3. Those standards require that we plan and perform an evaluation to obtain reasonable assurance as to whether the reserves data are free of material misstatement. An evaluation also includes assessing whether the reserves data are in accordance with principles and definitions presented in the COGE Handbook.

4. The following table sets forth the estimated future net revenue (before deduction of income taxes) attributed to proved plus probable reserves, estimated using forecast prices and costs and calculated using a discount rate of 10 percent, included in the reserves data of the Trust evaluated by us for the year ended December 31, 2004, and identifies the respective portions thereof that we have audited, evaluated and reviewed and reported on to Baytex’s Board of Directors:

Independent Qualified
Reserves Evaluator or
Auditor

Description and
Preparation Date
of [Audit/
Evaluation/
Review]
Report

Location of
Reserves
(County or
Foreign
Geographic
Area)

Net Present Value of Future Net Revenue
(before income taxes, 10% discount rate)

($Million)

Audited

Evaluated

Reviewed

Total

Sproule Associates Limited

February 28, 2005

Canada

—

1,019.3

—

1,019.3

5. In our opinion, the reserves data respectively evaluated by us have, in all material respects, been determined and are in accordance with the COGE Handbook. We express no opinion on the reserves data that we reviewed but did not audit or evaluate.

6. We have no responsibility to update our reports referred to in paragraph 4 for events and circumstances occurring after their respective preparation dates.

7. Because the reserves data are based on judgements regarding future events, actual results will vary and the variations may be material.

(signed) “Sproule Associates Limited”

Calgary, Alberta

February 28, 2005

APPENDIX C

BAYTEX ENERGY LTD.
AUDIT COMMITTEE
MANDATE AND TERMS OF REFERENCE

ROLE AND OBJECTIVE

The Audit Committee (the “Committee”) is a committee of the board of directors (the “Board”) of Baytex Energy Ltd. (“Baytex”) to which the Board has delegated its responsibility for oversight of the nature and scope of the annual audit, management’s reporting on internal accounting standards and practices, financial information and accounting systems and procedures, financial reporting and statements and recommending, for board of director approval, the audited financial statements and other mandatory disclosure releases containing financial information. The objectives of the Committee are as follows:

1. To assist directors meet their responsibilities (especially for accountability) in respect of the preparation and disclosure of the financial statements of Baytex Energy Trust (the “Trust”) and related matters;

2. To provide better communication between directors and external auditors;

3. To enhance the external auditor’s independence;

4. To increase the credibility and objectivity of financial reports; and

5. To strengthen the role of the outside directors by facilitating in depth discussions between directors on the Committee, management and external auditors.

MEMBERSHIP OF COMMITTEE

6. The Committee shall be comprised of at least three (3) directors of Baytex, none of whom are members of management of Baytex and all of whom are “independent” (as such term is used in Multilateral Instrument 52-110 — Audit Committees (“MI 52-110”).

7. The Board of Directors shall have the power to appoint the Committee Chairman, who shall be an unrelated director.

8. All of the members of the Committee shall be “financially literate”. The Board has adopted the definition for “financial literacy” used in MI 52-110.

MEETINGS

9. At all meetings of the Committee every question shall be decided by a majority of the votes cast. In case of an equality of votes, the Chairman of the meeting shall be entitled to a second or casting vote.

10. A quorum for meetings of the Committee shall be a majority of its members, and the rules for calling, holding, conducting and adjourning meetings of the Committee shall be the same as those governing the Board.

11. Meetings of the Committee should be scheduled to take place at least four times per year. Minutes of all meetings of the Committee shall be taken. The Chief Financial Officer shall attend meetings of the Committee, unless otherwise excused from all or part of any such meeting by the Chairman.

12. The Committee shall forthwith report the results of meetings and reviews undertaken and any associated recommendations to the board.

13. The Committee shall meet with the external auditor at least once per year (in connection with the preparation of the year- end financial statements) and at such other times as the external auditor and the audit Committee consider appropriate.

MANDATE AND RESPONSIBILITIES OF COMMITTEE

14. It is the responsibility of the Committee to oversee the work of the external auditors, including resolution of disagreements between management and the external auditors regarding financial reporting.

15. It is the responsibility of the Committee to satisfy itself on behalf of the board with respect to the Trust’s Internal Control Systems:

• identifying, monitoring and mitigating business risks; and

• ensuring compliance with legal, ethical and regulatory requirements.

16. It is a primary responsibility of the Committee to review the annual financial statements of the Trust prior to their submission to the board of directors for approval. The process should include but not be limited to:

• reviewing changes in accounting principles, or in their application, which may have a material impact on the current or future years’ financial statements;

• reviewing significant accruals, reserves or other estimates such as the ceiling test calculation;

• reviewing accounting treatment of unusual or non-recurring transactions;

• ascertaining compliance with covenants under loan agreements;

• reviewing disclosure requirements for commitments and contingencies;

• reviewing adjustments raised by the external auditors, whether or not included in the financial statements;

• reviewing unresolved differences between management and the external auditors; and

• obtain explanations of significant variances with comparative reporting periods.

17. The Committee is to review the financial statements, prospectuses, management discussion and analysis (MD&A), annual information forms (AIF) and all public disclosure containing audited or unaudited financial information before release and prior to board approval. The Committee must be satisfied that adequate procedures are in place for the review of the Trust’s disclosure of all other financial information and shall periodically access the accuracy of those procedures.

18. With respect to the appointment of external auditors by the board, the Committee shall:

• recommend to the board the appointment of the external auditors;

• recommend to the board the terms of engagement of the external auditor, including the compensation of the auditors and a confirmation that the external auditors shall report directly to the Committee;

• when there is to be a change in auditors, review the issues related to the change and the information to be included in the required notice to securities regulators of such change;

• review and approve any non-audit services to be provided by the external auditors’ firm and consider the impact on the independence of the auditors; and

• determine through inquiry if there are any related party transactions and ensure the nature and extent of such transactions are properly disclosed.

19. Review with external auditors (and internal auditor if one is appointed by the Trust) their assessment of the internal controls of the Trust, their written reports containing recommendations for improvement, and management’s response and follow-up to any identified weaknesses. The Committee shall also review annually with the external auditors their plan for their audit and, upon completion of the audit, their reports upon the financial statements of the Trust and its subsidiaries.

20. The Committee must pre-approve all non-audit services to be provided to the Trust or its subsidiaries by the external auditors. The Committee may delegate to one or more members the authority to pre-approve non-audit services, provided that the member report to the Committee at the next scheduled meeting such pre-approval and the member comply with such other procedures as may be established by the Committee from time to time.

21. The Committee shall review risk management policies and procedures of the Trust (i.e. hedging, litigation and insurance).

22. The Committee shall establish a procedure for:

• the receipt, retention and treatment of complaints received by the Trust regarding accounting, internal accounting controls or auditing matters; and

• the confidential, anonymous submission by employees of the Trust of concerns regarding questionable accounting or auditing matters.

23. The Committee shall review and approve the Trust’s hiring policies regarding employees and former employees of the present and former external auditors of the Trust.

24. The Committee shall have the authority to investigate any financial activity of the Trust. All employees of the Trust are to cooperate as requested by the Committee.

25. The Committee may retain persons having special expertise and/or obtain independent professional advice to assist in filling their responsibilities at the expense of the Trust without any further approval of the board.

Positive
Negative
Uncertain
Constraining
Legalese
Litigious
Readability	7th grade Avg

Baytex Energy (BTE) 40-F2004 FY Annual report (Canada)

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