Exhibit 99.1

BAYTEX ENERGY TRUST

ANNUAL INFORMATION FORM

2006

March 22, 2007

TABLE OF CONTENTS
	Page
SELECTED TERMS	1
ABBREVIATIONS	2
CONVERSIONS	3
CONVENTIONS	3
SPECIAL NOTE REGARDING FORWARD LOOKING STATEMENTS	3
BAYTEX ENERGY TRUST	5
GENERAL DEVELOPMENT OF OUR BUSINESS	7
RISK FACTORS	9
ADDITIONAL INFORMATION RESPECTING BAYTEX ENERGY TRUST	46
ADDITIONAL INFORMATION RESPECTING BAYTEX ENERGY LTD.	55
AUDIT COMMITTEE INFORMATION	58
BAYTEX SHARE CAPITAL	59
VOTING AND EXCHANGE TRUST AGREEMENT	63
SUPPORT AGREEMENT	64
MARKET FOR SECURITIES	66
RATINGS	68
LEGAL PROCEEDINGS AND REGULATORY ACTIONS	69
INTEREST OF INSIDERS AND OTHERS IN MATERIAL TRANSACTIONS	69
AUDITORS, TRANSFER AGENT AND REGISTRAR	69
INTERESTS OF EXPERTS	69
MATERIAL CONTRACTS	70
INDUSTRY CONDITIONS	70
ADDITIONAL INFORMATION	77

APPENDICES:

APPENDIX AREPORT OF MANAGEMENT AND DIRECTORS ON RESERVES DATA AND OTHER INFORMATION

APPENDIX BREPORT ON RESERVES DATA

APPENDIX CAUDIT COMMITTEE MANDATE

SELECTED TERMS

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

Entities

Baytex, the Corporation or the Company means Baytex 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.

Unitholders means holders of our Trust Units.

Independent Engineering

COGE Handbook means the Canadian Oil and Gas Evaluation Handbook.

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

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

Sproule Report means the report dated March 2, 2007 entitled "Evaluation of the P&NG Reserves of Baytex Energy Trust as of December 31, 2006".

Securities and Other Terms

DRIP Plan means our distribution reinvestment plan.

Convertible Debentures means our 6.50 % convertible unsecured subordinated debentures issued on June 6, 2005.

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.

GAAP means generally accepted accounting principals…

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 Notes issued on September 2, 2003.

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 us and Baytex 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 the Trustee.

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

Trust Unit or 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.

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

ABBREVIATIONS

Oil and Natural Gas Liquids			Natural Gas
bbl	Barrel		Mcf	thousand cubic feet
Mbbl	thousand barrels		MMcf	million cubic feet
MMbbl	million barrels		Bcf	billion cubic feet
NGL	natural gas liquids		Mcf/d	thousand cubic feet per day
Stb	stock tank barrels of oil		MMcf/d	million cubic feet per day
Mstb	thousand stock tank barrels of oil		m3	cubic metres
Bbl/d	barrels per day		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.
ARTC		means Alberta Royalty Tax Credit.
$ Million		means millions of dollars.
$000s		means thousands of dollars.

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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	6.290
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 within the meaning of applicable securities laws, including section 21E of the United States Securities Exchange Act of 1934, as amended, and section 27A of the United states Securities Act of 1933, as amended. 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 not historical facts and 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, contains forward-looking statements pertaining to the following:

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

·   oil and natural gas production levels;

·   our drilling plans for our Heavy Oil, Light Oil and Natural Gas District projects;

·   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 therefrom;

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

·   our ability to grow or sustain production and reserves through prudent management and acquisitions;

·   the emergence of accretive growth opportunities; and

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

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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;

·   fluctuation in foreign exchange or interest rates;

·   stock market volatility and market valuations;

·   geological, technical, drilling and processing problems and other difficulties in producing petroleum reserves;

·   changes in income tax laws or changes in tax laws and incentive programs relating to the oil and gas industry and income trusts; 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 certain estimates and assumptions, that the resources and reserves described can be profitably produced in the future. Readers are cautioned that the foregoing lists of factors are not exhaustive. The forward-looking statements contained in this Annual Information Form and the documents incorporated by reference, including factors discussed under "Management’s Discussion and Analysis of Financial Condition and Results of Operation" herein are expressly qualified by this cautionary statement and are available on SEDAR at www.sedar.com. You should also carefully consider the matters discussed under the heading "Risk Factors" in this Annual Information Form.

Further, any forward-looking statement speaks only as of the date on which such statement is made, and, except as required by applicable securities laws, we undertake no obligation to update any forward-looking statement or statements to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for management to predict all of such factors and to assess in advance the impact of each such factor on our business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward looking statements.

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BAYTEX ENERGY TRUST

General

We are an open-end unincorporated investment trust created under 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 - 5^th 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 us.

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

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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 percent of our Trust Units.

(2)   Baytex had a total of 1,573,153 Exchangeable Shares issued and outstanding as at December 31, 2006, which were exchangeable into 2,376,594 Trust Units.

(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 and other intercorporate notes. In addition to such amounts, prepayments in respect of principal on the Notes and other intercorporate notes may be made from time to time to us before the maturity of such notes.

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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 which will expire at the end of 2007. 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 three-quarters 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 percent 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 percent 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 percent 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.

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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 and 330 Bbl/d of light oil. Production from this acquisition represented approximately 9.6 percent 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 represented a new core area for us and are 100 percent operated with an average working interest of 91 percent. 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.

On June 6, 2005, we issued $100 million principal amount of 6.5% convertible debentures for net proceeds of $95.8 million. The Convertible Debentures pay interest semi-annually and are convertible at the option of the holder at any time into fully paid Trust Units at a conversion price of $14.75 per Trust Unit. The Convertible Debentures mature on December 31, 2010 at which time they are due and payable. The net proceeds from the issue of the Convertible Debentures were used to reduce outstanding bank indebtedness.

On September 30, 2005 we completed the acquisition of certain heavy oil producing properties in the Celtic area in Saskatchewan for a net cash consideration of $69 million. The assets acquired consisted of 3,350 Bbl/d of heavy oil (13º - 15º API) and 0.9 MMcf/d of natural gas. Production from this acquisition represented approximately 10 percent of our existing production. The assets acquired also included approximately 7,500 net acres of undeveloped land. The Celtic properties are situated approximately 30 miles east of Lloydminster and are adjacent to Tangleflags, Baytex's second largest producing area within its heavy oil operations. The expanded Celtic/Tangleflags operating region will improve economies of scale and allow for better control over costs. The acquisition included in excess of 100 opportunities for development drilling and recompletions for additional primary (cold) heavy oil production and natural gas production which added immediate low-cost development inventory. The acquisition also included 1,750 Bbl/d of steam assisted gravity drainage ("SAGD") production. As part of this transaction, Baytex entered into a price-sharing arrangement and a net profits agreement for future SAGD development with the vendor with respect to the assets acquired.

On December 30, 2005 we sold the recently acquired SAGD assets in the Celtic area of Saskatchewan for a net cash consideration of $45.3 million. Production at that time from the SAGD assets was approximately 2,000 Bbl/d of heavy oil.

During 2006 we did not complete any significant acquisitions or dispositions.

Significant Acquisitions

We have not completed any significant acquisitions during our most recently completed financial year for which disclosure is required under Part 8 of National Instrument 51-102.

Trends

Crude oil and natural gas prices are volatile and subject to a number of external factors. Prices are cyclical and fluctuate as a result of shifts in the balance between supply and demand for crude oil and natural gas, world and North American market forces, inventory and storage levels, OPEC policy, weather patterns and other factors. During 2006, the industry had seen very strong crude oil prices, as geopolitical tensions continued to threaten supply. Early 2007 pricing has declined in concert with a broader economic slowdown in the United States and resulting high inventory levels. Natural gas inventories are also currently at high 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.

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The Canadian/U.S. currency exchange rate also influences commodity prices received by Canadian producers as oil and natural gas production is ultimately priced in U.S. dollars. The Canadian dollar generally follows the trend in commodity prices, and the 2006 strengthening of the Canadian dollar somewhat mitigated the economic benefit of higher prices on Canadian oil and gas producers.

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 government action on the tax law applicable to income trusts. On October 31, 2006 the Federal Minister of Finance announced certain proposals pursuant to which, commencing January 1, 2011(subject to any "undue expansion" of the Trust) certain distributions from the Trust which would be have otherwise been taxed as ordinary income generally will be characterised as dividends in addition to being taxed at corporate rates at the trust level. For more details see "Industry Conditions - Proposed Federal Tax Changes".

RISK FACTORS

The following is a summary of material risk factors relating to our business.

We are dependent on Baytex for our revenue

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, 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 may not result in commercially productive reserves

Exploitation and development risks are due to the uncertain results of searching for and producing oil and natural gas using imperfect scientific methods. Our long-term commercial success depends on our ability to find, acquire, develop and commercially produce oil and natural gas reserves. There is no assurance that further commercial quantities of oil and natural gas will be discovered or acquired by us. New wells we drill or participate in may not become productive and we may not recover all or any portion of our investment in wells we drill or participate in. The cost of drilling, completing and operating a well is often uncertain, and cost factors can adversely affect the economics of a project.

Our business involves numerous operating hazards, and we are not fully insured against all of them

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, sour gas releases and spills, blow-outs, craterings and fires, all of which could result in personal injuries, loss of life and damage to our property and others. 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 and, in certain circumstances, we may elect not to obtain insurance to deal with specific risks due to the high premiums associated with such insurance or other reasons. The payment of such uninsured liabilities would reduce the funds available to us. The occurrence of a significant event that we are not fully insured against, or the insolvency of the insurer of such event, could have a material adverse effect on our financial position, results of operations or prospects and will reduce income otherwise distributable to us.

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We are dependent on our operators and other third parties to produce and market our property

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.

We may be exposed to third party credit risk through our contractual arrangements with our current or future joint venture partners, marketers of our petroleum and natural gas production and other parties. In the event such entities fail to meet their contractual obligations to us, such failures could have a material adverse effect on us and our cash flow from operations. In addition, poor credit conditions in the industry and of joint venture partners may impact a joint venture partner's willingness to participate in our ongoing capital program, potentially delaying the program and the results of such program until we find a suitable alternative partner.

Our business depends on volatile oil and gas prices.

Oil and gas prices, market expectations of potential changes in these prices and a variety of political and economic factors significantly affect our ability to fund our capital projects or distributions. Oil and gas prices are extremely volatile and are affected by numerous factors beyond our control, including:

·   the political environment of oil-producing regions, including uncertainty or instability resulting from an escalation or additional outbreak of armed hostilities in the Middle East or other geographic areas or further acts of terrorism in the United States or elsewhere;

·   worldwide demand for oil and gas;

·   the cost of exploring for, producing and delivering oil and gas;

·   the discovery rate of new oil and gas reserves;

·   the rate of decline of existing and new oil and gas reserves;

·   available pipeline and other oil and gas transportation capacity;

·   the ability of oil and gas companies to raise capital;

·   weather conditions in the United States and elsewhere;

·   the ability of the Organization of Petroleum Exporting Countries, commonly called OPEC, to set and maintain production levels and pricing;

·   the level of production in non-OPEC countries;

·   the policies of the various governments regarding exploration and development of their oil and gas reserves; and

·   advances in exploration and development technology.

We may manage the risk associated with changes in commodity prices by entering into oil or natural gas price hedges. If we hedge our commodity price exposure, we will forego the benefits we would otherwise experience if commodity prices were to increase. In addition, commodity hedging activities could expose us to losses. To the extent that we engage in risk management activities related to commodity prices, we will be subject to credit risks associated with counterparties with which we contract.

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Distributions may be affected by capital expenditure

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. In addition, if external sources of capital, including the issuance of additional Trust Units, become limited or unavailable on commercially reasonable terms, our ability to make the necessary capital investments to maintain or expand their oil and natural gas reserves will be impaired.

Distributions may be affected by operating costs and production declines

Higher operating costs for our underlying properties will directly decrease the amount of cash flow received by us and, therefore, may reduce distributions to our Unitholders. Electricity, chemicals, supplies, reclamation and abandonment and labour costs are a few of our operating costs that are susceptible to material fluctuation.

The level of production from our existing properties may decline at rates greater than anticipated due to unforeseen circumstances, many of which are beyond our control. A significant decline in production could result in materially lower revenues and cash flow and, therefore, could reduce the amount available for distributions to Unitholders.

Debt Service

We may not be successful in obtaining additional credit or complying with our debt service charges.

Baytex has credit facilities in the amount of $300 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.

Pursuant to various agreements with Baytex's lenders, we are 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 credit facilities or upon a material borrowing base shortfall or default.

From time to time we may enter into transactions to acquire assets or the shares of other organizations. These transactions may be financed in whole or in part with debt, which may increase our debt levels above industry standards for oil and natural gas companies of similar size. Depending on future exploration and development plans, we may require additional equity and/or debt financing that may not be available or, if available, may not be available on favourable terms. We are not restricted in the amount of indebtedness that we may incur. The level of our indebtedness from time to time, could impair our ability to obtain additional financing on a timely basis to take advantage of business opportunities that may arise.

Reserves figures are only estimates and may require revision

Although we, together with Sproule, have carefully prepared the reserves 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.

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We face competition from competitors with greater resources

Some of our competitors have greater financial and human resources than do we. Their greater capabilities in these areas may enable them to:

·   compete more effectively;

·   better withstand industry downturns; and

·   retain skilled personnel.

We may not be able to satisfy our future environmental and reclamation obligations

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 its 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.

We are affected by federal and provincial laws and regulations, including relating to the environment

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, which may be amended from time to time.

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 natural gases". Our exploration and production facilities and other operations and activities emit a small amount of greenhouse natural gases which may subject us to legislation regulating emissions of greenhouse natural gases. The Government of Canada has put forward a Climate Change Plan for Canada which suggests further legislation will set greenhouse natural gases emission reduction requirements for various industrial activities, including oil and natural gas exploration and production. 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 produced by our operations and facilities. The direct or indirect costs of these regulations may adversely affect our business. 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.

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We may have delays in cash receipts

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.

Our reserves may become depleted

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 could affect our ability to service our debt

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 several years, resulting in the receipt by us of fewer Canadian dollars for our production which may affect future distributions. 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. From time to time we may enter into agreements to fix the exchange rate of Canadian to United States dollars in order to offset the risk of revenue losses if the Canadian dollar increases in value compared to the United States dollar; however, if the Canadian dollar declines in value compared to the United States dollar, we will not benefit from the fluctuating exchange rate.

An increase in interest rates could result in a significant increase in the amount we pay to service debt, resulting in a decrease in distributions to Unitholders, as well as impact the market price of the Trust Units.

We are affected by political events

The marketability and price of oil and natural gas that may be acquired or discovered by us is and will continue to be affected by political events throughout the world that cause disruptions in the supply of oil. Conflicts, or conversely peaceful developments, arising in the Middle East, and other areas of the world, have a significant impact on the price of oil and natural gas. Any particular event could result in a material decline in prices and therefore result in a reduction of our net production revenue.

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In addition, our oil and natural gas properties, wells and facilities could be subject to a terrorist attack. If any of our properties, wells or facilities are the subject of terrorist attack it could have a material adverse effect on our financial condition. We do not have insurance to protect against the risk from terrorism.

Drilling equipment availability and access may be restricted

Oil and natural gas exploration and development activities are dependent on the availability of drilling and related equipment (typically leased from third parties) in the particular areas where such activities will be conducted. Demand for such limited equipment or access restrictions may affect the availability of such equipment to us and may delay exploration and development activities. To the extent we are not the operator of our oil and gas properties, we will be dependent on such operators for the timing of activities related to such properties and will be largely unable to direct or control the activities of the operators.

We are affected by seasonality

The level of activity in the Canadian oil and natural gas industry is influenced by seasonal weather patterns. Wet weather and spring thaw may make the ground unstable. Consequently, municipalities and provincial transportation departments enforce road bans that restrict the movement of rigs and other heavy equipment, thereby reducing activity levels. Also, certain oil and natural gas producing areas are located in areas that are inaccessible other than during the winter months because the ground surrounding the sites in these areas consists of swampy terrain. Seasonal factors and unexpected weather patterns may lead to declines in exploration and production activity and corresponding declines in the demand for crude oil and natural gas.

Project delays may delay expected revenues from operations

We manage a variety of small and large projects in the conduct of our business. Project delays may delay expected revenues from operations. Significant project cost over-runs could make a project uneconomic. Our ability to execute projects and market oil and natural gas will depend upon numerous factors beyond our control, including:

·   the availability of processing capacity;

·   the availability and proximity of pipeline capacity;

·   the availability of storage capacity;

·   the supply of and demand for oil and natural gas;

·   the availability of alternative fuel sources;

·   the effects of inclement weather;

·   the availability of drilling and related equipment;

·   unexpected cost increases;

·   accidental events;

·   currency fluctuations;

·   changes in regulations;

·   the availability and productivity of skilled labour; and

·   the regulation of the oil and natural gas industry by various levels of government and governmental agencies.

Because of these factors, we may be unable to execute projects on time, on budget or at all, and may not be able to effectively market the oil and natural gas that we produce.

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We may not realize anticipated benefits of acquisitions and dispositions

We make acquisitions and dispositions of businesses and assets in the ordinary course of our business. Achieving the benefits of acquisitions depends in part on successfully consolidating functions and integrating operations and procedures in a timely and efficient manner as well as our ability to realize the anticipated growth opportunities and synergies from combining the acquired businesses and operations with those of our operation. The integration of acquired business may require substantial management effort, time and resources and may divert management's focus from other strategic opportunities and operational matters. Management continually assesses the value and contribution of services provided and assets required to provide such services. In this regard, non-core assets are periodically disposed of, so that we can focus our efforts and resources more efficiently. Depending on the state of the market for such non-core assets, certain of our non-core assets, if disposed of, could be expected to realize less than their carrying value on our financial statements.

Acquisitions of resource issuers and resource assets will be based in large part upon engineering and economic assessments made by independent engineers. These assessments will include a series of assumptions regarding such factors as recoverability and marketability of oil and natural gas, future prices of oil and natural gas and operating costs, future capital expenditures and royalties and other government levies, which will be imposed over the producing life of the reserves. Many of these factors are subject to change and are beyond our control. In particular, the prices of and markets for resource products may change from those anticipated at the time of making such assessment. In addition, all such assessments involve a measure of geologic and engineering uncertainty, which could result in lower production and reserves than anticipated. Initial assessments of acquisitions may be based upon reports by a firm of independent engineers other than the firm that we use for our year-end reserve evaluations. Because each of these firms may have different evaluation methods and approaches, these initial assessments may differ significantly from the assessments of the firm we use. Any such instance may offset the return on and value of the Trust Units. Although title reviews may be conducted prior to the purchase of oil and natural gas producing properties or the commencement of drilling wells, such reviews do not guarantee or certify that an unforeseen defect in the chain of title will not arise to defeat our claim which could result in a reduction of the revenue received by us.

We may expand our operations

The operations and expertise of our management are currently focused on conventional oil and natural gas production and development in the Western Canadian Sedimentary Basin. In the future, we may acquire oil and natural gas properties outside this geographic area. In addition, the Trust Indenture does not limit our activities to oil and natural gas production and development, and we could acquire other energy related assets, such as oil and natural gas processing plants or pipelines. Expansion of our activities into new areas may present new additional risks or alternatively, significantly increase the exposure to one or more of the present risk factors which may result in our future operational and financial conditions being adversely affected.

We may issue additional Trust Units

In the normal course of making capital investments to maintain and expand our oil and natural gas reserves additional Trust Units are issued from treasury which may result in a decline in production per Trust Unit and reserves per Trust Unit. Additionally, from time to time we issue Trust Units from treasury in order to reduce debt and maintain a more optimal capital structure. To the extent that external sources of capital, including the issuance of additional Trust Units become limited or unavailable, our ability to make the necessary capital investments to maintain or expand our oil and natural gas reserves will be impaired. To the extent that we are required to use cash flow to finance capital expenditures or property acquisitions or to pay debt service charges or to reduce debt, the level of income available for distributions will be reduced.

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Our net asset value will vary from time to time

Our net asset value from time to time will vary dependent upon a number of factors beyond the control of management, including oil and natural gas prices. The trading prices of the Trust Units from time to time is also determined by a number of factors which are beyond the control of management and such trading prices may be greater than our net asset value.

Our prior distributions may not be reflective of future distributions

Our historical distributions 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.

We allocate all of our income

Pursuant to the provisions of the Trust Indenture all income earned by Baytex in a fiscal year, not previously distributed in that fiscal year, must be distributed to Unitholders of record on December 31. This excess income, if any, will be allocated to Unitholders of record at December 31 but the right to receive this income, if the amount is not determined and declared payable at December 31, will trade with the Trust Units until determined and declared payable in accordance with the rules of the Toronto Stock Exchange. To the extent that a Unitholder trades Trust Units in this period they will be allocated such income but will dispose of their right to receive such distribution.

Our status as a mutual fund trust may be changed or affected

On October 31, 2006, the Minister of Finance announced a proposal to tax trusts such as us. See "Industry Conditions - Proposed Federal Tax Changes".

Income tax laws, or other laws or government incentive programs relating to the oil and gas industry, such as the treatment of mutual fund trusts and resource taxation, may in the future be changed or interpreted in a manner that adversely affects us and our Unitholders. Tax authorities having jurisdiction over us or the Unitholders may disagree with how we calculate our income for tax purposes or could change administrative practises to our detriment or the detriment of our Unitholders.

In particular, generally speaking, the Income Tax Act (Canada) provides that a trust will permanently lose its "mutual fund trust" status (which is essential to the income trust structure) if it is established or maintained primarily for the benefit of non-residents of Canada (which is generally interpreted to mean that the majority of unitholders must not be non-residents of Canada), unless at all times after February 21, 1990, "all or substantially all" of the Trust's property consisted of property other than taxable Canadian property (the "TCP Exception"). We are currently able to take advantage of the TCP Exception.

On March 23, 2004 the Canadian federal government announced proposed changes to the Income Tax Act (Canada) which would have effectively eliminated, over a period of time, the TCP Exception currently relied on by us to maintain our mutual fund trust status, and, if implemented, would require us to comply with the requirement that it "not be maintained primarily for the benefit of non-residents". In response to submissions from and discussions with stakeholders, the Canadian federal government suspended the implementation of those proposed amendments. The Canadian Minister of Finance indicated in the February 23, 2005 federal budget that further consultations would be pursued with stakeholders on taxation issues related to income trusts and other flow-through entities. On September 8, 2005, the Canadian Department of Finance released a discussion paper on these matters and invited interested parties to make submissions to the Department of Finance. On November 23, 2005, the former Canadian Minister of Finance issued a news release announcing that no change would be made to the tax treatment of income trusts in Canada and calling an end to the consultation process initiated in September 2005.

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Notwithstanding the above, there is no assurance that the TCP Exception will continue to be available to the Trust or that the Canadian federal government will not introduce new changes or proposals to tax regulations directed at non-resident ownership which, depending upon our level of non-resident ownership, could result in us losing our mutual fund trust status or could otherwise detrimentally affect us and the market price of the Trust Units. We intend to continue to take the necessary measures in order to ensure that we continue to qualify as a mutual fund trust under the Income Tax Act (Canada). There would be material adverse consequences if we lost our status as a mutual fund trust under Canadian tax laws.

We may not be able to take steps necessary to ensure that we maintain our mutual fund trust status. Even if we are successful in taking such measures, these measures could be adverse to certain holders of Trust Units, particularly "non-residents" of Canada (as defined in the Income Tax Act (Canada)). There can be no assurance that such circumstances would not detrimentally affect the market price of the Trust Units.

Additionally, legislation may be implemented to limit the investment in income funds and royalty trusts by certain investors or to change the manner in which these entities are taxed. Tax authorities having jurisdiction over us or our Unitholders may disagree with how we calculate our income for tax purposes or could change administrative practices to our detriment or the detriment of our Unitholders.

There can be no assurance that the treatment of mutual fund trusts will not be changed in a manner adversely affecting Unitholders. If we cease to qualify as a "mutual fund trust" under the Income Tax Act (Canada), the Trust Units will cease to be qualified investments for registered retirement savings plans, registered education savings plans, deferred profit sharing plans and registered retirement income funds.

Income tax laws, or other laws or government incentive programs relating to the oil and gas industry, such as the treatment of mutual fund trusts and resource taxation, may in the future be changed or interpreted in a manner that adversely affects us and our Unitholders. Tax authorities having jurisdiction over us or the Unitholders may disagree with how we calculate our income for tax purposes or could change administrative practises to the detriment of us or the detriment of our Unitholders.

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

· We would be taxed on certain types of income distributed to Unitholders, including income generated by the royalties held by us. 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.

· We would cease to be eligible for the capital gains refund mechanism available under Canadian tax laws if it ceased to be a mutual fund trust.

· Trust Units held by Unitholders that are not residents of Canada would become taxable Canadian property. These non-resident holders would be subject to Canadian income tax on any gains realized on a disposition of Trust Units held by them.

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· Trust Units would not constitute qualified investments for registered retirement savings plans ("RRSPs"), registered retirement income funds ("RRIFs"), registered education savings plans ("RESTPs") or deferred profit sharing plans ("DPSPs"). If, at the end of any month, one of these exempt plans holds Trust Units that are not qualified investments, the plan must pay a tax equal to one percent of the fair market value of the Trust Units at the time the Trust Units were acquired by the exempt plan. An RRSP or RRIF holding non-qualified Trust Units would be subject to taxation on income attributable to the Trust Units. If an RESP holds non-qualified Trust Units, it may have its registration revoked by the Canada Customs and Revenue Agency.

In addition, we may take certain measures in the future to the extent we believe necessary to ensure that we maintain our status as a mutual fund trust. These measures could be adverse to certain holders of Trust Units, particularly "non-residents" of Canada as defined in the Income Tax Act (Canada). See "AdditionalInformation Respecting Baytex Energy Trust - Trust Indenture -Non-resident Unitholders".

We have non-resident ownership restrictions of our 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 Income Tax Act (Canada). The Trust Indenture provides that if at any time we or Baytex becomes aware that the beneficial owners of 49 percent 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.

Our expenses and other deductions may be challenged by taxing authorities

Generally, oil and gas income trusts including the 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.

Our revenues are affected by changes in regulations

Governments may regulate or intervene with respect to price, taxes, royalties and the exportation of oil and natural gas. Such regulations may be changed from time to time in response to economic or political conditions. At this time the Alberta Government is in the process of examining the royalty and tax regime applicable to oil, natural gas and oil sands, see "Industry Conditions - Provincial Royalties and Incentives". The implementation of new regulations or the modification of existing regulations affecting the oil and natural gas industry could reduce demand for natural gas and crude oil and increase our costs, any of which may have a material adverse effect on our intended business, financial condition and results of operations. In order to conduct oil and natural gas operations, we will require licenses from various governmental authorities. There can be no assurance that we will be able to obtain all of the licenses and permits that may be required to conduct operations that we may wish to undertake.

Our Trust Units are not shares

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.

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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.

We are not a legally recognized entity within the relevant definitions of the Bankruptcy and Insolvency Act (Canada), the Companies' Creditors Arrangement Act (Canada) and in some cases, the Winding-Up and Restructuring Act (Canada). As a result, in the event a restructuring of the Trust were necessary, the Trust would not be able to access the remedies available thereunder.

Our Trust Units have a limited 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 (as defined in the Trust Indenture) 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".

Trust Units will have no value when we can no longer economically produce and, as a result, cash distributions do not represent a "yield" in the traditional sense and are not comparable to bonds or other fixed yield securities, where investors are entitled to a full return of the principal amount of debt on maturity in addition to a return on investment through interest payments. Consequently, distributions represent a blend of return of Unitholders initial investment and a return on Unitholders initial investment.

Our Unitholders may not have 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 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.

Our permitted investments may be risky

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.

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Our directors and officers may have conflicts

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 Baytex 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.

Accounting policies may impact our financial statements

Canadian GAAP requires management to apply certain accounting policies and make certain estimates and assumptions which affect reported amounts in our consolidated financial statements. The accounting policies may result in non-cash charges to net income and write-downs of net assets in the financial statements. Such non-cash charges and write-downs may be viewed unfavourably by the market and result in an inability to borrow funds and/or may result in a decline in the Trust Unit price.

Under GAAP, the net amounts at which petroleum and natural gas costs on a property or project basis are carried are subject to a cost-recovery test, which is based in part upon estimated future net cash flows from reserves. If net capitalized costs exceed the estimated recoverable amounts, we will have to charge the amounts of the excess to earnings. A decline in the net value of oil and natural gas properties could cause capitalized costs to exceed the cost ceiling, resulting in a charge against earnings. The net value of oil and natural gas properties are highly dependent upon the prices of oil and natural gas.

GAAP requires that goodwill balances be assessed at least annually for impairment and that any permanent impairment be charged to net income. A permanent reduction in reserves, decline in commodity prices, and/or reduction in the Trust Unit price may indicate a goodwill impairment. As at December 31, 2006 we had $37.7 million of goodwill recorded on our balance sheet. An impairment would result in a write-down of the goodwill value and a non-cash charge against net income. The calculation of impairment value is subject to management estimates and assumptions.

Emerging GAAP surrounding hedge accounting may result in non-cash charges against net income as a result of changes in the fair market value of hedging instruments. A decrease in the fair market value of the hedging instruments as the result of fluctuations in commodity prices and foreign exchange rates may result in a write-down of net assets and a non-cash charge against net income. Such write-downs and non-cash charges may be temporary in nature if the fair market value subsequently increases.

Risks Particular to United States and Other Non-Resident Unitholders

In addition to the risk factors set forth above, the following risk factors are particular to Unitholders who are not residents of Canada.

United States and other non-resident Unitholders may be subject to additional taxation.

The Income Tax Act (Canada) and the tax treaties between Canada and other countries may impose additional withholding or other taxes on the cash distributions or other property paid by us to Unitholders who are not residents of Canada, and these taxes may change from time to time. For instance, since January 1, 2005, a 15 percentwithholding tax is applied to return of capital portion of distributions made to non-resident unitholders.

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The ability of United States and other non-resident Unitholders investors to enforce civil remedies may be limited.

We are a trust organized under the laws of Alberta, Canada, and our principal place of business is in Canada. All of the directors and officers of Baytex are residents of Canada and most of the experts who provide services to us (such as its auditors and some of its independent reserve engineers) are residents of Canada, and all or a substantial portion of their assets and our assets are located within Canada. As a result, it may be difficult for investors in the United States or other non-Canadian jurisdictions (a "Foreign Jurisdiction")to effect service of process within such Foreign Jurisdiction upon such directors, officers and representatives of experts who are not residents of the Foreign Jurisdiction or to enforce against them judgments of courts of the applicable Foreign Jurisdiction based upon civil liability under the securities laws of such Foreign Jurisdiction, including United States federal securities laws or the securities laws of any state within the United States. In particular, there is doubt as to the enforceability in Canada against us or any of our directors, officers or representatives of experts who are not residents of the United States, in original actions or in actions for enforcement of judgments of United States courts of liabilities based solely upon the United States federal securities laws or the securities laws of any state within the United States.

NEW YORK STOCK EXCHANGE

As a Canadian issuer listed on the New York Stock Exchange (the "NYSE"), we are not required to comply with most of the NYSE rules and listing standards and instead may comply with domestic requirements. As a foreign private issuer, we are only required to comply with three of the NYSE Rules: 1) have an audit committee that satisfies the requirements of the United States Securities Exchange Act of 1934; 2) the Chief Executive Officer must promptly notify the NYSE in writing after an executive officer becomes aware of any material non-compliance with the applicable NYSE Rules; and 3) provide a brief description of any significant differences between our corporate governance practices and those followed by U.S. companies listed under the NYSE. We have reviewed the NYSE listing standards and confirm that our corporate governance practices do not differ significantly from such standards.

DESCRIPTION OF OUR BUSINESS AND OPERATIONS

Overview

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;

· 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).

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Our principal undertaking is to issue Trust Units and other securities and to acquire and hold net profits interests, 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.

Pursuant to various agreements with Baytex's lenders, we are 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.

Our current distribution policy targets the use of between 30 percent and 40 percent of our available cash for capital expenditures to fund both exploration and development expenditures and minor property acquisitions, but excludes 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 governing the subordinated debt 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 percent 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.

Baytex Energy Ltd.

Baytex Energy Ltd. is amalgamated under the Business Corporations Act (Alberta) and is actively engaged in the business of oil and natural gas exploitation, development, acquisition and production in Canada. We are the sole common shareholder of Baytex. The Exchangeable Shares are owned by the public.

The head office of Baytex is located at Suite 2200, 205 - 5^th Avenue S.W., Calgary, Alberta, T2P 2V7 and its registered office is located at Suite 1400, 350 - 7^th Avenue S.W., Calgary, Alberta T2P 3N9.

NPI

We are a party to the NPI 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 percent of the gross proceeds from the sale of production attributable to such property interests for such month exceed ninety-nine (99 percent) 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.

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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.

The Notes are unsecured, payable on demand and bear interest from the date of issue at an interest rate equal to 12 percent 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 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 five days after demand.

From time to time we advance funds to our controlled entities which are evidenced by promissory notes. The terms of the notes are set at the time of issue. All of these advances are subordinate to all senior indebtedness to our senior lenders.

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, 2006. The effective date of the Statement is December 31, 2006 and the preparation date of the Statement by Sproule is March 2, 2007. 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") are 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. Constant and forecast prices were provided by Sproule as at December 31, 2006. 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. See also "Definitions and Other Notes" below.

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".

23

We are a taxable entity under the Income Tax Act (Canada) and are taxable only on income that is not distributed or distributable to our Unitholders. As we distribute all of our taxable income to our Unitholders and meet the requirements of the Income Tax Act (Canada) applicable to us, all future net revenue information contained in this Annual Information Form is presented on a before tax basis and after tax information is not included. Based on proposed changes announced by the federal government this may change. See "Industry Conditions - Proposed Federal Tax Changes".

Reserves Data (Constant Prices and Costs)

SUMMARY OF OIL AND GAS RESERVES

AND NET PRESENT VALUES OF FUTURE NET REVENUE

AS OF DECEMBER 31, 2006

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	3,303.0	3,006.9	22,395.9	19,366.3	78.0	65.5	2,240.0	1,903.5	40,944.6	35,198.6
Developed Non-Producing	470.6	389.9	23,959.9	20,784.6	12.0	10.1	593.2	506.8	27,020.5	23,372.6
Undeveloped	1,504.9	1,289.1	30,103.0	27,060.6	17.5	12.9	629.9	481.6	35,148.2	30,978.3
TOTAL PROVED	5,278.5	4,685.9	76,458.8	67,211.5	107.5	88.6	3,463.2	2,892.0	103,113.3	89,549.4
PROBABLE
Developed Producing	1,499.7	1,374.1	8,534.6	7,408.9	26.4	22.4	609.3	517.4	15,036.7	13,036.2
Developed Non-Producing	103.6	87.4	7,127.0	6,227.6	4.5	3.9	101.9	84.7	8,084.2	7,042.0
Undeveloped	529.8	452.8	17,596.8	15,261.4	8.4	6.6	302.6	233.0	19,833.5	17,039.4
TOTAL PROBABLE	2133.2	1,914.3	33,258.5	28,898.0	39.3	32.8	1,013.8	835.0	42,954.5	37,117.6
TOTAL PROVED PLUS PROBABLE	7,411.7	6,600.2	109,717.2	96,109.5	146.8	121.4	4,477.0	3,727.0	146,067.8	126,667.1

	NET PRESENT VALUES OF FUTURE NET REVENUE BEFORE INCOME TAXES DISCOUNTED AT
RESERVES CATEGORY	0% ($ Million)	5% ($ Million)	10% ($ Million)	15% ($ Million)	20% ($ Million)
PROVED
Developed Producing	834.4	760.8	685.3	625.5	577.9
Developed Non-Producing	527.3	378.3	286.1	225.3	183.0
Undeveloped	489.1	349.8	255.6	189.5	141.7
TOTAL PROVED	1,850.7	1,488.9	1,227.1	1,040.3	902.7
PROBABLE
Developed Producing	325.8	239.9	189.6	156.6	133.2
Developed Non-Producing	172.2	107.9	73.1	52.4	39.2
Undeveloped	360.5	227.5	152.7	107.9	79.5
TOTAL PROBABLE	858.6	575.3	415.4	316.9	251.9
TOTAL PROVED PLUS PROBABLE	2,709.3	2,064.2	1,642.5	1,357.2	1,154.6

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TOTAL FUTURE NET REVENUE

(UNDISCOUNTED)

AS OF DECEMBER 31, 2006

CONSTANT PRICES AND COSTS

RESERVES CATEGORY	REVENUE ($ Million)	ROYALTIES ($ Million)	OPERATING COSTS ($ Million)	DEVELOPMENT COSTS ($ Million)	WELL ABANDONMENT COSTS ($ Million)	FUTURE NET REVENUE BEFORE INCOME TAXES ($ Million)
PROVED
Developed Producing	1,573.9	228.1	452.3	1.5	57.6	834.4
Developed Non-Producing	979.7	137.0	271.3	44.1	-	527.3
Undeveloped	1,248.5	153.0	269.2	337.3	-	489.1
TOTAL PROVED	3,802.1	518.0	992.8	382.9	57.6	1,850.7
PROBABLE
Developed Producing	580.1	78.5	175.8	-	-	325.8
Developed Non-Producing	297.7	40.3	83.8	1.4	-	172.2
Undeveloped	693.0	95.4	171.3	65.7	-	360.5
TOTAL PROBABLE	1,570.8	214.2	431.0	67.1	-	858.6
TOTAL PROVED PLUS PROBABLE	5,372.8	732.2	1,423.7	450.0	57.6	2,709.3

FUTURE NET REVENUE

BY PRODUCTION GROUP

AS OF DECEMBER 31, 2006

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 (including solution gas and other by-products)	120.9
	Heavy Oil (including solution gas and other by-products)	908.6
	Natural Gas (including by-products and solution gas from oil wells)	197.6
Proved Plus Probable Reserves	Light and Medium Crude Oil (including solution gas and other by-products)	156.9
	Heavy Oil (including solution gas and other by-products)	1,222.3
	Natural Gas (including by-products and solution gas from oil wells)	263.4

25

Reserves Data (Forecast Prices and Costs)

SUMMARY OF OIL AND GAS RESERVES

AND NET PRESENT VALUES OF FUTURE NET REVENUE

AS OF DECEMBER 31, 2006

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	3,223.1	2,931.7	21,999.9	18,982.7	79.0	66.3	2,239.5	1,903.1	40,622.9	34,860.7
Developed Non-Producing	469.7	389.1	23,723.3	20,597.4	12.0	10.1	592.8	506.2	26,784.5	23,180.4
Undeveloped	1,492.7	1,277.2	30,085.7	27,208.2	17.4	12.9	629.9	481.8	35,119.5	31,109.6
TOTAL PROVED	5,185.6	4,597.9	75,809.0	66,788.3	108.4	89.2	3,462.2	2,891.0	102,526.9	89,150.7
PROBABLE
Developed Producing	1,415.1	1,292.6	8,312.3	7,209.9	26.7	22.7	609.5	517.5	14,781.4	12,796.9
Developed Non-Producing	103.9	87.8	7,025.4	6,140.4	4.5	3.9	101.6	84.4	7,983.8	6,954.8
Undeveloped	524.6	447.6	17,591.8	15,313.3	8.4	6.6	302.6	233.0	19,827.5	17,088.8
TOTAL PROBABLE	2,043.6	1,827.9	32,929.5	28,663.7	39.6	33.1	1,013.7	835.0	42,592.7	36,840.4
TOTAL PROVED PLUS PROBABLE	7,229.2	6,425.9	108,738.4	95,451.9	148.1	122.3	4,475.9	3,726.0	145,119.6	125,991.1

	NET PRESENT VALUES OF FUTURE NET REVENUE BEFORE INCOME TAXES DISCOUNTED AT
RESERVES CATEGORY	0% ($ Million)	5% ($ Million)	10% ($ Million)	15% ($ Million)	20% ($ Million)
PROVED
Developed Producing	856.9	833.4	757.8	694.0	642.6
Developed Non-Producing	481.6	347.2	264.7	210.6	173.0
Undeveloped	404.7	286.7	207.8	152.9	113.4
TOTAL PROVED	1,743.2	1,467.3	1,230.3	1,057.5	929.0
PROBABLE
Developed Producing	349.3	251.5	197.6	163.3	139.5
Developed Non-Producing	164.6	100.3	67.1	47.9	35.8
Undeveloped	321.3	202.6	136.3	96.7	71.7
TOTAL PROBABLE	835.1	554.4	401.0	307.9	247.0
TOTAL PROVED PLUS PROBABLE	2,578.3	2,021.7	1,631.3	1,365.4	1,176.0

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TOTAL FUTURE NET REVENUE

(UNDISCOUNTED)

AS OF DECEMBER 31, 2006

FORECAST PRICES AND COSTS

RESERVES CATEGORY	REVENUE ($ Million)	ROYALTIES ($ Million)	OPERATING COSTS ($ Million)	DEVELOPMENT COSTS ($ Million)	WELL ABANDONMENT COSTS ($ Million)	FUTURE NET REVENUE BEFORE INCOME TAXES ($ Million)
PROVED
Developed Producing	1,756.0	262.5	504.2	1.5	130.9	856.9
Developed Non-Producing	992.0	138.5	322.5	49.4	-	481.6
Undeveloped	1,243.8	155.1	317.0	367.0	-	404.7
TOTAL PROVED	3,991.8	556.2	1,143.6	417.9	130.9	1,743.2
PROBABLE
Developed Producing	659.5	90.8	219.4	-	-	349.3
Developed Non-Producing	314.5	42.2	105.9	1.8	-	164.6
Undeveloped	724.4	97.7	226.2	79.2	-	321.3
TOTAL PROBABLE	1,698.4	230.8	551.5	81.0	-	835.1
TOTAL PROVED PLUS PROBABLE	5,690.1	786.9	1,695.1	498.9	130.9	2,578.3

FUTURE NET REVENUE

BY PRODUCTION GROUP

AS OF DECEMBER 31, 2006

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 (including solution gas and other by-products)	121.9
	Heavy Oil (including solution gas and other by-products)	829.2
	Natural Gas (including by-products and solution gas from oil wells)	279.2
Proved Plus Probable Reserves	Light and Medium Crude Oil (including solution gas and other by-products)	157.7
	Heavy Oil (including solution gas and other by-products)	1,107.0
	Natural Gas (including by-products and solution gas from oil wells)	366.6

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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

(c)   in relation to properties, the total area of properties in which we have an interest.

2.    "Net" means:

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

(c)   specified economic conditions (see the discussion of "Economic Assumptions" below).

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.

Other criteria that must also be met for the categorization of reserves are provided in the COGE Handbook.

"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.

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     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.

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.

Additional clarification of certain levels associated with reserve estimates and the effect of aggregation is provided in the COGE Handbook.

4.   "Exploratory well" means a well that is not a development well, a service well or a stratigraphic test well.

29

5.    "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.

6.    "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.

7.    "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;

(c)   dry hole contributions and bottom hole contributions;

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

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

8.    "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.

30

9.   "Future net revenue" means the estimated net amount to be received with respect to the development and production of reserves; estimated using either (i) constant prices and costs or (ii) forecast prices and costs. This net amount is computed by deducting from estimated future revenues the estimated amounts of future royalty obligations, costs related to the development and production of reserves, well abandonment costs. Future incomes taxes have not been deducted from future net revenues, nor have general and administrative expenses or financing costs.

10.   Numbers may not add due to rounding.

11.   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.

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

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

 Pricing Assumptions

         The following sets forth the benchmark reference prices, as at December 31, 2006, 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 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).

31

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, 2006, inflation and exchange rates utilized in the Sproule Report were as follows:

SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS

AS OF DECEMBER 31, 2006

FORECAST PRICES AND COSTS

	OIL
Year	WTI Cushing Oklahoma ($US/Bbl)	Edmonton Par Price 40o API ($Cdn/Bbl)	Hardisty Heavy 12o API ($Cdn/Bbl)	NATURAL GAS AECO Gas Price ($Cdn/Mmbtu)	INFLATION RATES(1) %/Year	EXCHANGE RATE(2) ($US/$Cdn)
Historical
2002	26.09	40.12	27.58	4.04	2.7	0.637
2003	31.14	43.23	27.39	6.66	2.5	0.716
2004	41.42	52.91	30.40	6.87	1.3	0.770
2005	56.46	69.29	34.35	8.58	1.6	0.826
2006	66.09	73.31	43.32	7.16	2.0	0.882
Forecast
2007	65.73	74.10	42.98	7.72	5.0	0.870
2008	68.82	77.62	45.02	8.59	4.0	0.870
2009	62.42	70.25	40.74	7.74	3.0	0.870
2010	58.37	65.56	38.03	7.55	2.0	0.870
2011	55.20	61.90	35.90	7.72	2.0	0.870
Thereafter.	Various escalation Rates

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, 2006, 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:

32

SUMMARY OF PRICING ASSUMPTIONS ⁽¹⁾

AS OF DECEMBER 31, 2006

CONSTANT PRICES AND COSTS

	OIL
Year	WTI Cushing Oklahoma ($US/Bbl)	Edmonton Par Price 40 API ($Cdn/Bbl)	Hardisty Heavy 12 API ($Cdn/Bbl)	NATURAL GAS AECO Gas Price ($Cdn/Mmbtu)	EXCHANGE RATE(2) ($US/$Cdn)
December 31, 2006	61.05	67.59	43.32(3)	6.13	0.858

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.

(3)   $43.32 for 2007, and $40.05 for subsequent years.

Weighted average prices realized by us for the year ended December 31, 2006, were $7.13/Mcf for natural gas, $53.84/bbl for light crude oil and NGLs, and $43.57/bbl for heavy oil. The heavy oil price includes the effect of our long term sales contract.

33

Reconciliations of Changes in Reserves and Future Net Revenue

RECONCILIATION OF TRUST NET RESERVES

BY PRINCIPAL PRODUCT TYPE

FORECAST PRICES AND COSTS

	Light and Medium Crude Oil			Heavy Oil
	Proved	Probable	Proved + Probable	Proved	Probable	Proved + Probable
	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)
December 31, 2005	4,817	2,101	6,918	62,205	22,451	84,656
Extensions	-	-	-	1,531	771	2,302
Discoveries	21	10	31	78	22	100
Improved Recovery	-	-	-	-	-	-
Technical Revisions	298	(321)	(23)	9,664	5,645	15,309
Acquisitions	111	47	157.2	-	-	-
Dispositions	-	-	-	-	-	-
Economic Factors	34	(9)	26	(139)	(225)	(364)
Production	(682)	-	(682)	(6,551)	-	(6,551)
December 31, 2006	4,598	1,828	6,426	66,788	28,664	95,452

	Natural Gas Liquids			Natural Gas including solution gas
	Proved	Probable	Proved + Probable	Proved	Probable	Proved + Probable
	(Mbbl)	(Mbbl)	(Mbbl)	(MMcf)	(MMcf)	(MMcf)
December 31, 2005	3,083	1,022	4,105	103,320	42,551	145,871
Extensions	94	24	118	3,728	38	3,842
Discoveries	60	21	81	1,967	1,130	3,106
Improved Recovery	-	-	-	-	-	-
Technical Revisions	213	(171)	42	(1,611)	(9,735)	(11,182)
Acquisitions	-	-	-	22	10	33
Dispositions				-	-	-
Economic Factors	(94)	(61)	(155)	(1,586)	(1,159)	(2,745)
Production	(465)	-	(465)	(16,600)	-	(16,600)
December 31, 2006	2,891	835	3,726	89,241	33,083	122,324

	Oil Equivalent
	Proved	Probable	Proved + Probable
	(Mboe)	(Mboe)	(Mboe)
December 31, 2005	87,325	32,666	119,991
Extensions	2,247	813	3,060
Discoveries	487	242	729
Improved Recovery	-	-	-
Technical Revisions	9,906	3,559	13,464
Acquisitions	114	48	163
Dispositions	-	-	-
Economic Factors	(463)	(488)	(951)
Production	(10,465)	-	(10,465)
December 31, 2006	89,151	36,840	125,991

34

RECONCILIATION OF TRUST GROSS RESERVES

BY PRINCIPAL PRODUCT TYPE

FORECAST PRICES AND COSTS

	Light and Medium Crude Oil			Heavy Oil
	Proved	Probable	Proved + Probable	Proved	Probable	Proved + Probable
	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)
December 31, 2005	5,472	2,342	7,814	71,266	26,286	97,552
Extensions	-	-	-	1,828	887	2,715
Discoveries	25	12	37	90	25	116
Improved Recovery	-	-	-	-	-	-
Technical Revisions	312	(351)	(39)	9,890	5,649	15,540
Acquisitions	121	51	172	-	-	-
Dispositions	-	-	-	-	-	-
Economic Factors	36	(10)	26	518	82	600
Production	(780)	-	(780)	(7,784)	-	(7,784)
December 31, 2006	5,186	2,044	7,229	75,809	32,929	108,738
	Natural Gas Liquids			Natural Gas including solution gas
	Proved	Probable	Proved + Probable	Proved	Probable	Proved + Probable
	(Mbbl)	(Mbbl)	(Mbbl)	(MMcf)	(MMcf)	(MMcf)
December 31, 2005	3,635	1,254	4,889	125,537	50,862	176,399
Extensions	138	29	167	4,817	90	4,906
Discoveries	76	26	102	2,458	1,449	3,907
Improved Recovery	-	-	-	-	-	-
Technical Revisions	308	(226)	82	(2,425)	(11,535)	(13,960)
Acquisitions	-	-	-	32	15	47
Dispositions	-	-	-	-	-	-
Economic Factors	(112)	(69)	(181)	(1,779)	(1,244)	(3,024)
Production	(583)	-	(583)	(20,219)	-	(20,219)
December 31, 2006	3,462	1,014	4,476	108,421	39,636	148,056

	Oil Equivalent
	Proved	Probable	Proved + Probable
	(Mboe)	(Mboe)	(Mboe)
December 31, 2005	101,296	38,359	139,655
Extensions	2,769	931	3,700
Discoveries	601	305	906
Improved Recovery	-	-	-
Technical Revisions	10,106	3,150	13,256
Acquisitions	127	53	180
Dispositions	-	-	-
Economic Factors	146	(206)	(60)
Production	(12,517)	-	(12,517)
December 31, 2006	102,527	42,593	145,120

35

RECONCILIATION OF CHANGES IN

NET PRESENT VALUES OF FUTURE NET REVENUE

DISCOUNTED AT 10% PER YEAR

NET PROVED RESERVES

CONSTANT PRICES AND COSTS

PERIOD AND FACTOR	2006 ($ Million)
Estimated Future Net Revenue at Beginning of Year	1,506.7
Sales and Transfers of Oil and Gas Produced, Net of Production Costs and Royalties(1)	(329.7)
Net Change in Prices, Production Costs and Royalties Related to Future Production(2)	(182.2)
Changes in Previously Estimated Development Costs Incurred During the Period(2)	(6.2)
Changes in Estimated Future Development Costs(2)	(136.9)
Extensions and Improved Recovery(2)	167.0
Discoveries	4.6
Acquisitions of Reserves(2)	2.8
Dispositions of Reserves(2)	0.0
Net Change Resulting from Revisions in Quantity Estimates (Technical Revisions)	(10.6)
Accretion of Discount(3)	139.8
Miscellaneous Changes	71.8
Estimated Future Net Revenue at End of Year	1,227.1

Note:

(1)   Undiscounted before income tax.

(2)   Discounted before income tax.

(3)   Ten percent (10%) of beginning of year net present value, before income tax.

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 six 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.

36

Significant Factors or Uncertainties

We have a significant amount of proved non-producing and proved undeveloped reserves assigned to the Seal, Celtic and Tangleflags heavy oil properties in Saskatchewan, the Ardmore and Cold Lake heavy oil properties in Alberta and to the Stoddart, British Columbia and Turin and Leahurst, Alberta light oil and gas properties. As well we have a significant amount of probable non-producing and probable undeveloped reserves assigned to these same properties. At the current prices, these development activities are economic. However, should oil and natural gas 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)
2007	72.6	76.1	72.6
2008	86.0	85.6	82.0
2009	101.9	102.8	93.5
2010	62.0	72.4	55.2
2011	28.9	41.1	25.4
Total Undiscounted (all years)	417.9	498.9	382.9
Total Discounted at 10%/year	249.9	315.6	253.9

We expect to fund the development costs of our reserves through a combination of internally generated cash flow, debt and equity financings. We withhold approximately 30 - 50 percent 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.

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, 2006. Unless otherwise specified, gross and net acres and well count information are as at December 31, 2006. Well counts indicate gross wells, except where otherwise indicated. Production information represents average working interest production, for the year ended December 31, 2006, except where otherwise indicated.

Baytex’s crude oil and natural gas operations are organized into two operating districts: the Heavy Oil District and the Light Oil and Natural Gas District. Each district has an extensive portfolio of operated properties and development prospects with considerable upside potential. Within these districts, Baytex has established a total of nine geographically-organized teams with a full complement of technical professionals (engineers, geoscientists and landmen) within each team. This comprehensive technical approach results in thorough identification and evaluation of exploration, development and acquisition investment opportunities, and cost-efficient execution of those opportunities.

37

Heavy Oil District

The Heavy Oil District accounts for approximately sixty percent of current production, three-quarters of oil-equivalent reserves and over half of Baytex’s cash flow from operations.  Baytex's heavy oil operations consist predominantly of cold primary production, without the assistance of steam injection.  In some cases, Baytex's heavy oil reservoirs containing lower-than-average viscosity crudes are waterflooded, occasionally with hot water.  Baytex's heavy oil fields often have multiple productive zones, some of which can be commingled within the same producing wellbore.  Production is generated from vertical, slant and horizontal wells using progressive cavity pumps capable of handling 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 crude with gravities ranging from 11º to 18º API.  Once produced, the oil is trucked or pipelined to markets in both Canada and the United States.  Heavy crude is usually blended with a light-hydrocarbon diluent (such as condensate) prior to being introduced into a sales pipeline. The blended crude oil is then sold by Baytex and may be upgraded into lighter grades of crude or refined into petroleum products such as fuel oil, lubricants and asphalt by the crude purchasers. All production rates reported are for heavy crude only, before the addition of diluent.

In 2006, production in the Heavy Oil District averaged approximately 21,300 Bbl/d of heavy oil and 8.8 MMcf/d of natural gas (22,800 Boe/d).  Baytex drilled 88 gross (84.2 net) wells in the Heavy Oil District resulting in 79 (75.2 net) oil wells, four (4.0 net) gas wells, three (3.0 net) stratigraphic test wells, and two (2.0 net) dry and abandoned wells, for a success rate of 98 percent (98 percent net).

The Heavy Oil District possesses a large inventory of development projects within the west-central Saskatchewan, Cold Lake/Ardmore, and Peace River areas.  Baytex's ability to generate relatively low-cost replacement production through conventional cold production methods is key to maintaining the Trust's overall production rate.  Because of Baytex's large inventory of heavy oil investment projects, the Trust is able to select between a wide range of investments to maintain heavy oil production rates.

38

Baytex will continue to build value through internal heavy oil property development and selective acquisitions.  Future heavy oil development will focus both on the Peace River Oil Sands area and Baytex’s area of historical emphasis around Lloydminster in southwest Saskatchewan and southeast Alberta.  Our net undeveloped lands in the Heavy Oil District totalled approximately 294,492 acres at year-end 2006.

Ardmore, Alberta: Acquired in 2002 at a production rate of 2,200 Bbl/d, this property has since been extensively developed in the Sparky, McLaren and Colony formations.  Average production during 2006 was approximately 3,100 Bbl/d of oil and 500 Mcf/d of natural gas (3,200 Boe/d).  Eleven successful oil wells and no dry holes were drilled in the area during 2006. Baytex anticipates drilling two wells in this area in 2007. In addition, new production techniques, such as cold horizontal well production and cyclic steam injection are being evaluated for the large hydrocarbon resource in this area. Due to extensive Baytex infrastructure in this area, operating expenses in 2006 remained relatively low at approximately $6 per boe. Net undeveloped lands were 41,800 acres at year-end 2006.

Carruthers, Saskatchewan:  The Carruthers property was acquired by Baytex in 1997.  This property consists of separate "North" and "South" oil pools in the Cummings formation. During 2006, average production was approximately 2,400 Bbl/d of heavy oil and 900 Mcf/d of natural gas (2,500 Boe/d). Although no new wells were drilled in this area in 2006, a significant hot waterflood expansion (up-grading battery treating capacity, conversion of six wells to injection and re-starting 11 producing wells) was completed. Net undeveloped lands were 9,700 acres at year-end 2006.

Celtic, Saskatchewan: This producing property was acquired in October 2005, in a transaction which included approximately 2,000 Bbl/d of Steam Assisted Gravity Drainage (SAGD) production.  The SAGD production was divested at the end of 2005, leaving Baytex with purchased cold heavy oil production of 1,600 Bbl/d and 0.9 MMcf/d. As a result of Baytex’s well re-completion and drilling activities, cold production increased to an average of 3,800 Bbl/d of heavy oil and 1.9 MMcf/d of natural gas (4,100 Boe/d) during 2006. (This production number includes Baytex production in the area held prior to the Celtic acquisition). Celtic is a key asset for Baytex because, like the adjacent Tangleflags property, it contains a large resource base within multiple prospective horizons. As a result, the Celtic property provides a multi-year inventory of drilling locations and re-completion opportunities.  Also like Tangleflags, the heavy oil at Celtic is relatively highly gas-saturated and the existing infrastructure allows for efficient capture and marketing of co-produced solution gas. In 2007 Baytex expects to drill 20 new wells and re-complete up to 60 existing wells. Net undeveloped lands were 8,700 acres at year-end 2006.

Cold Lake, Alberta:  Located on Cold Lake First Nations lands, this heavy oil property was acquired by Baytex in 2001.  Production is primarily from the Colony formation. Average oil production during 2006 was approximately 600 Bbl/d, during which time Baytex drilled four oil wells.  In 2006, Baytex acquired additional mineral rights to capture deeper producing horizons on 7,680 acres of land on which it already held shallow leases. These new rights are anticipated to ultimately generate up to 15 new drilling locations, and three new wells are planned for 2007.  Net undeveloped lands were 15,300 acres at year-end 2006.

Marsden/Epping/Macklin/Silverdale, Saskatchewan:  This area of Saskatchewan is characterized by low access costs and generally higher quality crude oil that ranges up to 18 API.  Initial per well production rates are typically 40 to 70 Bbl/d.  Primary recovery factors can be as high as 30 percent of the original oil in-place because of the relatively high oil gravity and the existence of strong water drive in many of the oil pools in this area.  Average oil production in this area during 2006 was approximately 4,200 Bbl/d and 950 Mcf/d (4,400 Boe/d).  Eleven oil wells were drilled in 2006. During 2007, nine new wells are planned for this area, as well as an expansion of the solution gas sales facility at Macklin.  Net undeveloped lands were 19,300 acres at year-end 2006.

Seal, Alberta: Seal is a highly prospective property located in the Peace River Oil Sands area of northern Alberta.  Baytex holds a 100 percent working interest in over 100 sections of long-term oil sands leases.  In certain parts of this land base, heavy oil can be produced through primary methods using horizontal wells at initial rates of approximately 150 Bbl/d per well without employing more capital-intensive methods such as steam injection. During 2006, Baytex drilled three new stratigraphic test wells to identify extensions to our current development area located on the western block of these land holdings.  In this area, Baytex also drilled two new horizontal producing wells, bringing the total number of producing wells to eight. The average production rate during 2006 was 550 Bbl/d of heavy oil. Baytex plans to drill four additional stratigraphic test wells and up to 18 horizontal producing wells at Seal during 2007. Baytex is also core-testing and conducting numerical reservoir simulation of both waterflood and cyclic steam recovery methods for Seal. Both of these processes have the potential to greatly increase ultimate recovery factor beyond what is achievable with primary recovery. We anticipate conducting a steam injection field test by 2008 or earlier. Operators of adjoining lands are also pursuing aggressive development programs that will contribute to vital infrastructure and allow enhanced marketing solutions for the region.  As the region continues to develop, the Seal property will take an increasingly more prominent role in the Trust's production profile.  Net undeveloped lands in this area were 66,200 acres at year-end 2006.

Tangleflags, Saskatchewan:  Baytex 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. Accordingly, this property supplies long-term development potential through a considerable number of uphole re-completion opportunities. In 2006, 24 wells were either re-started or re-completed. Average production during 2006 was approximately 2,200 Bbl/d of heavy oil and 1.0 MMcf/d of natural gas (2,300 Boe/d).  In 2007, Baytex plans to drill two new wells and re-complete about 30 existing wells in Tangleflags.  Net undeveloped lands were 8,300 acres at year-end 2006.

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Light Oil and Natural Gas District

Although Baytex is best known as a "heavy oil" energy trust, we also possess a growing array of light oil and natural gas properties that generate nearly half of our cash flow.  In addition to Baytex’s historical light oil and natural gas properties in northern and southeastern Alberta, the geographic scope of our light oil and gas operations has expanded to southwest Alberta and northeast British Columbia, providing exposure to some of the most prospective areas in Western Canada.

The Light Oil and Natural Gas District produces light and medium gravity crude oil, natural gas and natural gas liquids from various fields in Alberta and British Columbia. During 2006, production from this district averaged 47 MMcf/d of natural gas sales and 3,700 Bbl/d of light oil and NGLs for annual average oil equivalent production of 11,500 Boe/d.  In 2006, the Light Oil and Natural Gas District drilled 40 (33.4 net) wells resulting in 17 (14.1 net) gas wells, 19 (16.1 net) oil wells, and four (3.2 net) dry wells for a success rate of 90 percent (90 percent net).  Our net undeveloped lands in this business unit were approximately 323,643 acres at year-end 2006. 

Bon Accord, Alberta:  This multi-zone property was acquired by Baytex in 1997.  Production, which is from the Belly River, Viking and Mannville formations, averaged approximately 4.3 MMcf/d of sales gas and 300 Bbl/d of light oil (1,000 Boe/d) during 2006.  Natural gas is processed at two Company-operated plants and oil is treated at three Company-operated batteries.  During 2006, Baytex drilled three gas wells and two oil wells in this area. At year-end 2006, Baytex had 21,400 net undeveloped acres in this area.

Darwin/Nina, 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 2006 averaged approximately 3.5 MMcf/d (600 Boe/d).  During 2006, Baytex drilled three gas wells in this area. Baytex plans to install an amine facility at Darwin during 2007 to remove carbon dioxide from sales gas and improve operating capability and product netback for the area.  At year-end 2006, Baytex had 44,700 net undeveloped acres in this area.

Leahurst, Alberta:  Production averaged approximately 3.7 MMcf/d (600 Boe/d) sales gas in 2006 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.  During 2006, Baytex drilled one gas well and one abandoned well in this area. During 2006, Baytex plans to drill up to six wells in this area. At year-end 2006, Baytex had 15,600 net undeveloped acres in this area.

Richdale/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.  During 2006, production averaged approximately 7.7 MMcf/d of gas (1,300 Boe/d).  This area has advantages of year-round access and multi-zone potential in the Second White Specks, Viking and Mannville formations.  Most of the gas production from this area is processed at two Company-operated gas plants.  During 2006, Baytex drilled four gas wells in this area and plans to drill four to seven additional wells during 2007.  At year-end 2006, Baytex had 41,800 net undeveloped acres in this area.

40

Red Earth/Goodfish, Alberta:  This primarily winter-access, multi-zone property was acquired by Baytex in 1997. 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 from this area during 2006 averaged approximately 5.3 MMcf/d sales gas and 700 Bbl/d of hydrocarbon liquids (1,600 Boe/d).  During 2006, Baytex drilled two gas wells and one abandoned well in this area.  At year-end 2006, Baytex had 33,900 net undeveloped acres in this area.

Turin, Alberta:  This multi-zone, year-round access property was acquired in 2004 with the acquisition of a private company.  Production during 2006 averaged approximately 700 Bbl/d of oil and NGLs and 1.8 MMcf/d sales gas (1,000 Boe/d).  Production is from the Second White Specks, Milk River, Bow Island, Mannville, Sawtooth and Livingstone formations. Oil production is treated at three Company-operated batteries and gas is processed at two outside-operated gas plants.  During 2006, Baytex drilled two gas wells and five oil wells in this area. Baytex plans to drill three to six wells in the Turin area during 2007.  At year-end 2006, Baytex had 14,600 net undeveloped acres in this area.

Stoddart, British Columbia:  The Stoddart asset acquisition was completed in December 2004.  Oil and liquids rich gas production from this largely year-round-access area comes from the Doig, Halfway, Baldonnel, Coplin and Bluesky formations.  Oil is treated at two Company-operated batteries and natural gas is compressed at four Company-operated sites and sent for further processing at the outside-operated West Stoddart and Taylor Younger plants.  Production from this area during 2006 averaged approximately 12.5 MMcf/d sales gas and 1,900 Bbl/d of oil and NGLs (4,000 Boe/d).  Baytex drilled nine wells in 2006 resulting in two gas wells, six oil wells and one abandoned well. Baytex plans to drill up to eight wells and re-complete several wells in 2007.  At year-end 2006, Baytex had 31,400 net undeveloped acres in this area.

Average Production

The following table indicates our average daily production from our principal areas for the year ended December 31, 2006.

	Light Oil and NGL	Heavy Oil	Gas
	(Bbl/d)	(Bbl/d)	(Mcf/d)
Ardmore	-	3,095	548
Carruthers	-	2,387	850
Celtic	-	3,849	1,916
Cold Lake	-	623	-
Lashburn	-	178	148
Marsden	-	1,344	-
Neilburg	-	512	116
Poundmaker	-	507	1,082
Seal	-	547	-
Silverdale / Epping / Macklin	-	2,891	953
Tangleflags	-	2,181	977
Remaining heavy oil properties	-	3,207	2,258
Bon Accord	301	-	4,316
Darwin/Nina	-	-	3,531
Goodfish	-	-	5,222
Hamburg/Chinchaga	37	-	2,835
Leahurst	15	-	3,733
Red Earth	667	-	39
Richdale / Sedalia	20	-	7,716
Stoddart	1,864	-	12,509
Tangent	-	-	756
Turin	655	-	1,802
Viking	-	-	1,650
Remaining light oil / natural gas properties	176	-	2,437
Total	3,735	21,321	55,394

41

Costs Incurred

The following table summarizes the costs incurred related to our activities for the year ended December 31, 2006:

	Costs Incurred
	$ Million
Property acquisition costs:
Proved properties (1)	0.7
Unproved properties	11.1
Development Costs (2)	110.1
Exploration Costs (3)	11.2
Total	133.1

Notes:

(1)  Acquisitions are net of disposition of properties.

     (2)  Development and facilities expenditures.

 (3)  Cost of geological and geophysical capital expenditures and drilling costs for 2006 exploration wells drilled.

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, 2006.

	Oil Wells				Natural Gas Wells
	Producing		Non-Producing		Producing		Non-Producing
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Alberta	445	335.6	349	294.2	494	385.3	290	227.5
British Columbia	49	48.2	31	30.2	30	26.4	13	9.7
Saskatchewan	1,070	981.4	694	664.6	50	46.8	50	46.8
Total	1,564	1,365.2	1,074	989.0	574	458.5	353	284.0

Properties with no Attributable Reserves

The following table sets out our undeveloped land holdings as at December 31, 2006.

	Undeveloped Acres
	Gross	Net
Alberta	605,425	438,585
British Columbia	76,223	55,913
Saskatchewan	138,948	123,637
Total	820,596	618,135

We expect that rights to explore, develop and exploit approximately 51,835 net acres of our undeveloped land holdings may expire on or before December 31, 2007. There are no material drilling commitments associated with the land holdings expiring by December 31, 2007.

Forward Contracts

For details of our material commitment to sell natural gas and crude oil which were outstanding at December 31, 2006, see Notes 15 and 16 to our Consolidated Financial Statements on page 58 and 59 of our 2006 Annual Report which are incorporated herein by reference.

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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 5 % for the year 2007, 4% for the year 2008, 3% for the year 2009 and 2% thereafter	Abandonment and Reclamation Costs escalated at 5 % for the year 2007, 4% for the year 2008, 3% for the year 2009 and 2% thereafter
	Undiscounted ($ Million)	Discounted at 10% ($ Million)
Total as at December 31, 2006	236.4	28.1
Anticipated to be paid in 2007	1.7	1.7
Anticipated to be paid in 2008	1.0	0.9
Anticipated to be paid in 2009	0.8	0.7

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. Expenditures related to 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 2,065 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, 2006. 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 liability associated with the wells not assigned reserves by Sproule, pipelines and facility reclamation costs, net of salvage, which was estimated to be $147.3 million ($17.5 million discounted at 10 percent), 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 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. See "Industry Conditions - Proposed Federal Tax Changes".

43

Capital Expenditures

The following table summarizes capital expenditures related to our activities for the year ended December 31, 2006:

Expenditure	($000s)
Land	11,118
Seismic	2,202
Drilling and completion	97,273
Equipment	19,240
Other	2,548
Total exploration and development	132,381
Property acquisitions	1,530
Property dispositions	(828)
Net capital expenditures	133,083

Exploration and Development Activities

Approximately seven percent of our annual exploration and development budget is spent on exploration activities.

The following table sets forth the gross and net exploratory and development wells in which we participated during the year ended December 31, 2006.

	Exploratory Wells		Development Wells
	Gross	Net	Gross	Net
Oil	5	4.5	93	86.8
Natural Gas	-	-	21	18.1
Evaluation	2	2.0	1	1.0
Dry	2	1.2	4	4.0
Total	9	7.7	119	109.9

Production Estimates

The following table sets out the volume of our production estimated for the year ending December 31, 2007 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)
2007	2,200	21,400	55,000	1,625	34,400

No individual property accounts for 20 percent or more of the estimated production disclosed.

44

Production History

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
	2006				2005
	Dec. 31	Sept. 30	Jun. 30	Mar. 31	Dec. 31	Sept. 30	Jun. 30	Mar. 31
Average Daily Production
Light Oil and NGL (Bbl/d)	3,643	3,594	3,619	4,089	4,022	4,063	3,404	3,876
Heavy Oil (Bbl/d)	22,416	21,325	20,413	21,134	24,051	20,061	19,653	21,279
Gas (Mmcf/d)	51.4	54.9	54.7	60.6	58.9	63.9	59.3	59.5
Combined (Boe/d)	34,631	34,074	33,154	35,319	37,895	34,780	32,937	35,068
Average Price Received
Light Oil and NGL ($/Bbl)	48.62	57.94	57.83	51.33	55.48	59.24	53.06	46.69
Heavy Oil ($/Bbl)	41.15	48.28	47.10	37.87	37.75	39.64	30.22	27.38
Gas ($/Mcf)	7.03	6.35	6.68	8.36	10.69	8.39	7.08	6.69
Combined ($/Boe)	42.19	46.57	46.35	42.94	46.48	42.92	36.26	33.10
Royalties Paid
Light Oil and NGL ($/Bbl)	7.15	8.13	8.72	7.40	9.04	8.53	8.51	6.39
Heavy Oil ($/Bbl)	4.99	8.80	8.20	3.55	4.43	6.83	3.87	3.48
Gas ($/Mcf)	1.23	0.89	1.17	1.58	2.60	1.17	1.09	1.43
Combined ($/Boe)	5.81	7.80	7.94	5.69	7.81	7.09	5.15	5.25
Production Costs
Light Oil and NGL ($/Bbl)	12.25	12.44	11.79	8.50	6.28	10.40	9.12	10.53
Heavy Oil ($/Bbl)	9.47	9.26	8.63	9.52	11.00	9.49	8.88	8.59
Gas ($/Mcf)	1.31	1.36	1.16	1.20	1.22	1.05	1.02	1.02
Combined ($/Boe)	9.36	9.30	8.51	8.74	9.55	8.61	8.07	8.11
Transportation
Light Oil and NGL ($/Bbl)	0.99	1.15	1.21	1.23	0.94	0.84	1.55	1.38
Heavy Oil ($/Bbl)	2.64	2.61	2.74	2.40	2.19	2.28	2.48	2.20
Gas ($/Mcf)	0.12	0.12	0.13	0.13	0.14	0.14	0.14	0.14
Combined ($/Boe)	2.00	1.95	2.04	1.79	1.71	1.67	1.89	1.73
Netback Received
Light Oil and NGL ($/Bbl)	28.23	36.22	36.11	34.20	39.22	39.47	33.88	28.39
Heavy Oil ($/Bbl)	24.05	27.61	27.53	22.40	20.13	21.04	14.99	13.11
Gas ($/Mcf)	4.37	3.98	4.22	5.45	6.73	6.03	4.83	4.10
Combined ($/Boe)	25.02	27.52	27.85	26.72	27.41	25.55	21.15	18.01

Note:

(1)Our NGL volumes are not material, and have been grouped with light oil for reporting purposes.

Marketing Arrangements

Natural Gas

We continue to maintain a risk-mitigating strategy and cultivate a diverse natural gas sales portfolio, which encompasses a variety of pricing mechanisms and term commitments. Our marketing objectives also include protecting or securing minimum prices for up to 50 percent of net production for terms not exceeding two years. Our hedging methodology generally includes employing collars, floors or fixed price contracts. In order to control and manage credit risk and ensure competitive bids, we engage a number of reputable counterparties for our natural gas transactions. Our natural gas portfolio includes sales to industrial consumers, distribution companies and traditional aggregators.

For 2007, Baytex has entered into several physical forward sales contracts. These agreements have locked in seasonal natural gas prices over the year at prices above the current forward strip.

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Oil and Liquids

Benchmark WTI prices began the year around US$60.00 per bbl, climbed to an all-time high of US$77.03 per bbl in August, and ended the year over US$61 per bbl. The average WTI price for 2006 was US$66.22 per bbl, an increase of 17 percent from US$56.56 in 2005.

Baytex's light oil and natural gas liquids prices averaged $53.84 per bbl in 2006 identical to the $53.84 in 2005. Our heavy oil prices averaged $43.57 per bbl in 2006, compared to $37.38 in 2005.

In October 2002, Baytex signed a five-year crude oil supply agreement with Frontier Oil and Refining Company ("Frontier") of Houston, Texas. This contract will expire at the end of 2007. The agreement calls for Baytex to deliver 20,000 Bbl/d of Lloyd Blend ("LLB") quality crude at Hardisty, Alberta through the Express Pipeline to Guernsey, Wyoming. The blended crude is comprised of approximately 16,000 barrels of Baytex production and 4,000 Bbl/d of diluent. Prices are fixed at 71 percent of WTI or a 29 percent LLB differential which represents the long-term average differential since 1986. This contract significantly reduces the volatility of Baytex's cash flow from its heavy oil operations.

Going forward, Baytex has entered into a series of costless collar contracts which will provide significant downside protection on the oil price while still allowing Baytex to participate in upside price potential. WTI costless collars have been put in place for 2007 on 8,000 bbls/d, at a weighted average price from US$56.88 to US$82.48 per bbl.

Environmental Policies

We have an active program to monitor and comply with all environmental laws, rules and regulations applicable to our operations. Our policies require that all employees and contractors must report all breaches or potential breaches of environmental laws, rules and regulations to our senior management and all applicable governmental authorities. Any material breaches of environmental law, rules and regulations must be reported to the Board of Directors.

ADDITIONAL INFORMATION RESPECTING BAYTEX ENERGY TRUST

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 us or Baytex. Corporate law does not govern us and the rights of Unitholders. 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. The rights of Unitholders are specifically set forth in the Trust Indenture. In addition, trusts are not defined as recognized entities within the definitions of legislation such as the Bankruptcy and Insolvency Act (Canada) and the Companies' Creditors Arrangement Act (Canada). As a result, in the event of an insolvency or restructuring, a Unitholder's position as such may be quite different than that of a shareholder of a corporation.

The price per Trust Unit is a function of our anticipated distributable income and the ability of the Board of Directors to effect long term growth in our value. The market price of the Trust Units will be sensitive to a variety of market conditions including, but not limited to, interest rates, commodity prices and our ability to acquire additional assets. Changes in market conditions may adversely affect the trading price of the Trust Units.

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A return on an investment in the Trust is not comparable to the return on an investment in a fixed income security. The recovery of an initial investment in us is at risk, and the anticipated return on such investment is based on many performance assumptions. Although we intend to make distributions of our available cash to holders of Trust Units, these cash distributions may be reduced or suspended. The actual amount distributed will depend on numerous factors including: the financial performance of Baytex, debt obligations, working capital requirements and future capital requirements. In addition, the market value of the Trust Units may decline if our cash distributions decline in the future, and that market value decline may be material.

It is important for an investor to consider the particular risk factors that may affect the industry in which it is investing, and therefore the stability of the distributions that it receives. See "Risk Factors".

The after tax return from an investment in Trust Units to Unitholders subject to Canadian income tax can be made up of both a return on capital and a return of capital. That composition may change over time, thus affecting an investor's after tax return. Returns on capital are generally taxed as ordinary income in the hands of a Unitholder. Returns of capital are generally tax deferred (and reduce the Unitholder's cost base in the Trust Unit for tax purposes).

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 Energy Ltd. - Share Capital" below.

Convertible Debentures

On June 6, 2005, we issued $100 million principal amount of 6.5% convertible unsecured subordinated debentures for net proceeds of $95.8 million. The Convertible Debentures pay interest semi-annually and are convertible at the option of the holder at any time into fully paid Trust Units at a conversion price of $14.75 per Trust Unit. The Convertible Debentures mature on December 31, 2010 at which time they are due and payable. The Convertible Debentures are redeemable by us at a price of $1,050 per 7.50 percent Convertible Debenture after February 1, 2007 and on or before February 1, 2008 and at a price of $1.025 per 7.50 percent Convertible Debenture after February 1, 2008 and before maturity on June 30, 2009, in each case, plus accrued and unpaid interest thereon, if any. For a complete description of the Convertible Debentures, reference should be made to the indenture creating the Convertible Debentures, a copy of which has been filed on SEDAR at www.sedar.com.

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Trust Indenture

The Trust Indenture, among other things, provides for the calling of meetings of Unitholders, the conduct of business thereof, notice provisions, the appointment and removal of the Trustee and the form of Trust Unit certificates. The Trust Indenture may be amended from time to time. Substantive amendments to the Trust Indenture, including early termination of the Trust and the sale or transfer of our property as an entirety or substantially as an entirety requires approval by special resolution of the Unitholders. Any approval or consent of Unitholders in relation to any matter required by any regulatory body will require a majority of, or such other level of approval of Unitholders as may be stipulated by such regulatory authority, including as to the exclusion of interested or other Unitholders in the calculation of such level of approval.

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

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.

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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 percent to 40 percent of cash available for distribution for capital expenditures. Depending upon commodity prices, 30 percent to 40 percent of the cash available for distribution could fund up to all of our capital expenditures, including both exploration and development expenditures and minor property acquisitions, but excluding major acquisitions.

Pursuant to various agreements with Baytex's lenders, we are 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.

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 governing the subordinated debt 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 percent 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.

Pursuant to the provisions of the Trust Indenture all income earned by us in a fiscal year, not previously distributed in that fiscal year, must be distributed to Unitholders of record on December 31. This excess income, if any, will be allocated to Unitholders of record at December 31 but the right to receive this income, if the amount if not determined and declared payable at December 31, will trade with the Trust Units until determined and declared payable in accordance with the rules of the Toronto Stock Exchange. To the extent that a Unitholder trades Trust Units in this period they will be allocated such income but will dispose of their right to receive such distribution.

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The following is a summary of the distributions paid or declared by us from inception in September of 2003 to March 15, 2007.

For the Month Ended	Distribution	Payment Date
September to December 2003	$0.15 per Unit	15th of the following month
January to December 2004	$0.15 per Unit	15th of the following month
January to December 2005	$0.15 per Unit	15th of the following month
January 31, 2006	$0.18 per Unit	February 15, 2006
February 28, 2006	$0.18 per Unit	March 15, 2006
March 31, 2006	$0.18 per Unit	April 17, 2006
April 30, 2006	$0.18 per Unit	May 15, 2006
May 31, 2006	$0.18per Unit	June 15, 2006
June 30, 2006	$0.18 per Unit	July 15, 2006
July 31, 2006	$0.18 per Unit	August 15, 2006
August 31, 2006	$0.18 per Unit	September 15, 2006
September 30, 2006	$0.18 per Unit	October 16, 2006
October 31, 2006	$0.18 per Unit	November 15, 2006
November 30, 2006	$0.18 per Unit	December 15, 2006
December 31, 2006	$0.18 per Unit	January 15, 2007
January 31, 2007	$0.18 per Unit	February 15, 2007
February 28, 2007	$0.18 per Unit	March 15, 2007

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 percent 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.

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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 percent 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 49 percent 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, 2007, approximately 42 percent 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.

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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 percent 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 five percent 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. The 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 percent 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.

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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 Income Tax Act (Canada) 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.

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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 percent of the outstanding Trust Units; (b) a quorum of 50 percent 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.

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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.
John A. Brussa (2) (3) (4) (6) Calgary, Alberta	Director	Partner, Burnet, Duckworth & Palmer LLP (a law firm).
W.A. Blake Cassidy (1)(8) Calgary, Alberta	Director	Retired businessman; prior thereto held various senior positions with Canadian Imperial Bank of Commerce.
Edward Chwyl (2) (3) (4) Victoria, B.C.	Chairman of the Board of Directors	Independent businessman since May 2002; prior thereto Chairman of the Board of Ventus Energy Ltd. (a public oil and gas company).
Naveen Dargan (1) (2) (4) Calgary, Alberta	Director	Independent businessman since June 2003; prior thereto Senior Managing Director of Raymond James Ltd. (an investment banking firm) and predecessor companies.
R.E.T. (Rusty) Goepel (1) Vancouver, B.C.	Director	Senior Vice President of Raymond James Ltd. and predecessor companies.
Dale O. Shwed (3) (7) Calgary, Alberta	Director	President and Chief Executive Officer of Crew Energy Inc. (a public oil and gas company) since September 2003; prior thereto President and Chief Executive Officer of Baytex.
W. Derek Aylesworth Calgary, Alberta	Chief Financial Officer	Chief Financial Officer of Baytex since November 2005; prior thereto Commercial Manager, Ecuador Region, EnCana Corporation (a public oil and gas company) from 2003; prior thereto, Division Vice President, International New Ventures Exploration, EnCana Corporation from 2001.
Randal J. Best Calgary, Alberta	Senior Vice President, Corporate Development	Senior Vice President, Corporate Development of Baytex since December 2006; prior thereto Vice President, Corporate Development of Baytex since September 2003; prior thereto Managing Director of Waterous Securities from 2000.
Stephen Brownridge Calgary, Alberta	Vice President, Heavy Oil	Vice President, Heavy Oil of Baytex since December 2006; prior thereto Manager, Heavy Oil since September 2003; prior thereto various positions within Baytex since 1997.

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 October 2002 (a wholly owned subsidiary of Dominion Resources Inc., a publicly traded U.S. energy company); prior thereto Vice President, Engineering of Dominion Exploration & Production Inc. from January 2002.
Brett J. McDonald Calgary, Alberta	Vice President, Land	Vice President, Land of Baytex since December 2006; prior thereto General Manager of Land of Baytex since September 2003; prior thereto Senior Landman with Baytex since January 2000.
R. Shaun Paterson Calgary, Alberta	Vice President, Marketing	Vice President, Marketing of Baytex since December 2006; prior thereto Vice President, Domestic Crude Oil Marketing for EnCana Corporation (a public oil & gas company) from 2002.
Mark F. Smith Calgary, Alberta	Vice President, Conventional Oil & Gas	Vice President, Conventional Oil & Gas of Baytex since November 2006; prior thereto Vice President, Development North Business Unit of Burlington Resources Canada since September 2004; prior General Manager Deep Basin Business Unit of Burlington Resources Canada (a public oil & gas company) since January 2002.
Shannon M. Gangl Calgary, Alberta	Corporate Secretary	Partner, Burnet, Duckworth & Palmer LLP (a law firm).

 Notes:

(1)   Member of our Audit Committee.

(2)   Member of our Compensation Committee.

(3)   Member of our Reserves Committee.

(4)   Member of our Governance Committee

(5)   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).

(6)   Mr. 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.

(7)   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.

(8)   Mr. Cassidy is not seeking re-appointment to our board of directors at our next annual meeting of unitholders.

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As at February 28, 2007, the directors and executive officers of Baytex, as a group, beneficially owned, directly or indirectly, or exercised control or direction over 650,659 Trust Units, or approximately 0.86 percent of the issued and outstanding Trust Units. In addition, as at February 28, 2006, the directors and executive officers of Baytex, as a group, beneficially owned, directly or indirectly, exercise control or direction over 455,129 Exchangeable Shares or approximately 28.9 percent of the issued and outstanding Exchangeable Shares. No Convertible Debentures were owned by this same group.

Corporate Cease Trade Orders or Bankruptcies

Except as set forth above, in the ten years preceding the date of this Annual Information Form, none of the directors or executive officers of Baytex are or have been a director or executive officer of any other company that, while acting in such capacity:

(a)   was the subject of a cease trade or similar order or an order that denied the relevant company access to any exemption under securities legislation for a period of more than 30 consecutive days;

(b)   was subject to an event that resulted, after the director or executive officer ceased to be a director or executive officer, in the company being the subject of a cease trade or similar order or an order that denied the relevant company access to any exemption under securities legislation for a period of more than 30 consecutive days; or

(c)   within a year of that person ceasing to act as director or executive officer, became bankrupt, made a proposal under any legislation relating to bankruptcy and insolvency or was subject to or instituted any proceedings, arrangement or compromise with creditors or had a receiver, receiver manager or trustee appointed to hold its assets.

Penalties or Sanctions

No director or officer of Baytex has been subject to any penalties or sanctions under securities legislation or by a securities regulatory authority or has entered into a settlement agreement with a securities regulatory authority or any other penalties or sanctions imposed by a court or regulatory body that would likely be considered important to a reasonable investor in making an investment decision.

Personal Bankruptcies

No director or officer of Baytex has in the ten years preceding the date of this Annual Information Form become bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency, or been subject to or instituted any proceedings, arrangement or compromise with creditors or had a receiver, receiver manager or trustee appointed to hold their assets.

Conflicts

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, 2006, Baytex employed 124 head office employees and 25field office employees.

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                                                                          AUDIT COMMITTEE INFORMATION

Audit Committee Mandate and Terms of Reference

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

Composition of the Audit Committee

The members of our Audit Committee are Mr. Naveen Dargan, Mr. W.A. Blake Cassidy and Mr. R.E.T. (Rusty) Goepel, each of whom is independent and financially literate. We have adopted the definition of "independence" as set out in Section 1.4 of Multilateral Instrument 52-110 Audit Committees. The relevant education and experience of each Audit Committee member is outlined below:

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 businessman; prior thereto held various senior positions with Canadian Imperial Bank of Commerce.
R.E.T. (Rusty) Goepel	Yes	Yes	Senior Vice President, Raymond James Ltd. and predecessor companies.

Pre-Approval of Policies and Procedures

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.

External Auditor Service Fees

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 2006 and 2005:

	Aggregate fees billed
	2006	2005
	($000s)
Audit fees	549	350
Audit-related fees	-	-
Tax fees	4	42
All other fees	187	44
	740	436

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. In addition to the fees for annual audits of financial statements and review of quarterly results, services in this category for fiscal 2006 and 2005 also include the reviews of comment letters from Canadian and U.S. regulatory agencies. The 2006 fees include $286 for audit work performed in relation to the requirements of Section 404 of the Sarbanes-Oxley Act of 2002 relating to internal control over financial reporting while the 2005 fees also include review of prospectuses related to an acquisition and equity and debt issuances.

Audit-Related Fees. Audit-related fees consist of fees for assurance and related services that are reasonably related to the performance of the audit or review of the Trust's financial statements and are not reported as Audit Fees. During fiscal 2006 and 2005, there were no payments in this category.

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

All Other Fees. During fiscal 2006 and 2005, the services provided in this category consist only of advisory services associated with property taxes. The increase in 2006 reflects a full review of the Trust's property holdings.

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BAYTEX SHARE CAPITAL

Baytex is authorized to issue an unlimited number of common shares and an unlimited number of Exchangeable Shares. As of February 28, 2007, there were 1,572,153 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 holders 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, 2006, 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.

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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.

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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 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 any date that is within the first 90 days of any calendar year, redeem up that number of Exchangeable Shares equal to 40 percent 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

(c)   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).

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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 percent 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.

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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.

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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:

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

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

(e)   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.

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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 percent 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.

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MARKET FOR SECURITIES

The Trust Units and the Convertible Debentures are listed and traded on the Toronto Stock Exchange. The trading symbol for the Trust Units is BTE.UN, and for the Convertible Debentures is BTE.DB.The Exchangeable Shares Units are not listed on any stock exchange.

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
	High ($)		Low ($)		Volume Traded
2003		10.89		9.19		40,973,662
2004		14.00		9.78		93,252,808
2005		18.78		12.42		87,481,272
2006
January		20.69		17.35		9,144,637
February		20.29		16.81		6,959,795
March		20.90		18.60		8,325,081
April		21.58		19.72		7,545,699
May		24.14		21.06		7,132,966
June		25.39		21.66		7,699,911
July		25.25		23.10		5,294,628
August		28.66		24.71		7,378,882
September		27.32		21.50		11,269,514
October		25.82		19.35		11,762,794
November		23.20		18.95		14,365,793
December		23.22		21.40		5,772,540
2007
January		22.28		19.29		8,957,643
February		21.38		19.66		6,476,432

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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 New York Stock Exchange for the periods indicated. The Trust Units commenced trading on the New York Stock Exchange on March 27, 2006.

	Price Range
	High ($US)	Low ($US)	Volume Traded
2006
March	17.90	17.51	735,900
April	19.10	17.08	2,547,200
May	21.91	19.00	2,292,200
June	22.97	19.47	1,987,800
July	22.31	20.45	915,600
August	25.87	21.80	1,924,700
September	24.67	19.26	2,512,400
October	22.84	17.17	2,157,100
November	20.28	16.63	4,909,500
December	20.29	18.59	1,513,800
2007
January………………………………………	18.43	16.32	1,615,800
February …………………………………….	18.48	16.64	1,218,500

The following table sets forth the high and low closing trading prices and the aggregate volume of trading of the Convertible Debentures as reported by the Toronto Stock Exchange for the periods indicated. The Convertible Debentures commenced trading on the Toronto Stock Exchange on June 6, 2005.

	Price Range
	High ($)	Low ($)	Volume Traded
2005	127.00	99.50	766,975
2006
January	139.35	117.35	135,685
February	137.35	114.83	62,890
March	140.00	126.00	67,550
April	145.13	132.35	41,350
May	163.00	142.01	57,415
June	170.27	146.83	44,890
July	169.00	157.58	14,520
August	190.88	168.08	57,025
September	183.43	145.00	16,960
October	172.00	140.00	34,050
November	155.43	128.45	12,473
December	156.58	146.00	5,890
2007
January	146.00	131.02	4,510
February	140.00	130.02	3,430

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RATINGS

DBRS has assigned a stability rating of STA-6 (high) to the Trust. The stability rating is based on a rating scale developed by DBRS that provides an indication of both the stability and sustainability of an income fund's distributions per unit. Stability rating categories range from STA-1 to STA-7, with STA-1 being the highest and STA-7 being the lowest possible rating. DBRS further separates the ratings into high, middle and low to indicate relative standing within a rating category. Ratings take into consideration the seven main factors of: (1) operating and industry characteristics; (2) asset quality; (3) financial flexibility; (4) diversification; (5) size and market position; (6) sponsorship/governance; and (7) growth. In addition, consideration is given to specific structural or contractual elements that may eliminate or mitigate risks or other potentially negative factors. DBRS has assigned stability ratings to 15 of the largest oil and gas income trusts in Canada, including the Trust, ranging from STA-5 (high) to STA-6 (middle). Specifically, income funds rated as STA-6 are considered by DBRS to have very weak distribution per unit stability and sustainability. An income fund rated as STA-6 is subject to many of the same cyclical, seasonal, commodity price and economic factors as the higher STA-5 rating category, but the lack of diversification is generally more pronounced. In addition such income funds will tend to be "weak" or "moderate" in the majority of the key factors considered when determining a stability rating.

On November 1, 2006 DBRS placed the stability ratings of select Canadian income trusts "Under Review with Developing Implications" following the Federal Minister of Finance’s announcement to make significant changes to the way in which Canadian income trusts will be taxed in the future. For income trusts that plan to reduce the level of their distributions to unitholders to reflect the additional tax burden, the reduction would be viewed as a one time event and DBRS’s analytical focus would then be on the stability and sustainability of distributions following the adjustments. Under this scenario, the stability ratings would likely be confirmed; however, the proposed legislation could encourage certain trusts to develop alternative capitalisation or operating strategies. Until DBRS is able to discuss these issues with those trusts implementing alternative capitalisation or operating strategies, their ratings would remain under review. Baytex’s stability rating would also be subject to this latest "Under Review with Developing Implications" rating adjustment.

On March 8, 2007 DBRS removed the Trust from its "Under Review with Developing Implications" rating, and reconfirmed the stability rating of STA- 6 (high).

Baytex has been assigned a senior implied rating of B1 and an issuer rating of B3, each with a stable outlook by Moody's. Moody's credit ratings are on a long-term debt rating scale that ranges from Aaa to C, which represents the range from highest to lowest quality of such securities rated. According to the Moody's rating system, securities rated ''B'' are considered speculative and are subject to high credit risk. Moody's appends numerical modifiers 1, 2 and 3 to each generic rating classification from Aa through Caa. The modifier 1 indicates that the security ranks in the higher end of its generic rating category; the modifier 2 indicates a mid-range ranking; and the modifier 3 indicates a ranking in the lower end of its generic rating category.

The Trust has been assigned a long-term corporate credit rating of B+/Stable by S&P. S&P's credit ratings are on a long-term debt rating scale that ranges from AAA to D, which represents the range from highest to lowest quality of such securities rated. According to the S&P rating system, debt rated ''BBB'' is regarded as having an adequate capacity to pay interest and repay principal. Whereas it normally exhibits adequate protection parameters, adverse economic conditions or changing circumstances are more likely to lead to a weakened capacity of the obligor to meet its financial commitments on the obligation. The ratings from AA to CCC may be modified by the addition of a plus (+) or a minus (-) sign to show relative standing within the major rating categories. In addition, S&P may add a rating outlook of "positive", "negative" or "stable" which assesses the potential direction of a long-term credit rating over the intermediate term (typically six months to two years).

The stability and credit ratings accorded to Baytex and the Trust by DBRS, Moody's and S&P are not recommendations to purchase, hold or sell any securities of the Trust inasmuch as such ratings do not comment as to market price or suitability for a particular investor. There is no assurance that any rating will remain in effect for any given period of time or that any rating will not be revised or withdrawn entirely by a rating agency in the future if in its judgment circumstances so warrant.

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LEGAL PROCEEDINGS AND REGULATORY ACTIONS

There are no legal proceedings which the Trust or Baytex or any subsidiary of the Trust or Baytex is or was a party of or which any of their property is or was subject to, which are material to the Trust or Baytex and the Trust and Baytex is not aware of any such proceedings that are contemplated or pending.In addition, neither the Trust or Baytex was subject to: (i) any penalties or sanctions imposed against it by a court relating to securities legislation or by a securities regulatory authority, or (ii) any other penalties or sanctions imposed by a court or regulatory body against it, or has entered into any settlement agreement with a court relating to securities legislation or with a securities regulatory authority.

INTEREST OF INSIDERS AND OTHERS IN MATERIAL TRANSACTIONS

There were no material interests, direct or indirect, of directors and executive officers of Baytex, any holder of Trust Units or Exchangeable Shares who beneficially owns more than 10 percent of the outstanding Trust Units or Exchangeable Shares, or any known associate or affiliate of such persons, in any transactions since our inception or since the beginning of the Trust's last completed financial year which has materially affected, or would materially affect us.

AUDITORS, TRANSFER AGENT AND REGISTRAR

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

Valiant Trust Company, at its principal office in Calgary, Alberta and through its co-agent, BNY Trust Company of Canada, at its principal office in Toronto, Ontario is the transfer agent and registrar for the Trust Units and the Convertible Debentures.

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 designated professionals of Sproule have 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.

Deloitte & Touche LLP, is our auditor and is independent within the meaning of the Rules of Professional Conduct of the Institute of Chartered Accountants of 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.

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MATERIAL CONTRACTS

Except for contracts entered into in the ordinary course of business, the only material contracts entered into by us within the most recently completed financial year, or before the most recently completed financial year but are still material and are still in effect, are the following:

(a)the Trust Indenture;

(b)the indenture creating the Note and the promissory note evidencing the Notes issued thereunder;

(d)the indenture creating the Convertible Debentures; and

(e)our trust unit incentive plan.

Copies of each of these documents have been filed on SEDAR at www.sedar.com.

INDUSTRY CONDITIONS

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 natural 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 natural 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 natural gas industry.

Pricing and Marketing - Oil

In Canada, producers of oil are entitled to negotiate sales contracts directly with oil purchasers, with the result that the market determines the price of oil. Oil prices are primarily based on worldwide supply and demand. The specific price depends in part on oil quality, prices of competing fuels, distance to market, the value of refined products, the supply/demand balance and other contractual terms. Oil exporters are also entitled to enter into export contracts with terms not exceeding one year in the case of light crude oil, and not exceeding two years in the case of heavy crude oil, provided that an order approving any such export has been obtained from the National Energy Board of Canada ("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 a licence requires the approval of the Governor in Council.

Pricing and Marketing - Natural Gas

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 and other terms 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 two years or for a term of between two to 20 years (in quantities of not more than 30,000 m³/d) 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 license from the NEB and the issuance of such license requires the approval of Governor in Council.

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

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Pipeline Capacity

Although pipeline expansions are ongoing, the lack of firm pipeline capacity continues to affect the oil and natural gas industry and limit the ability to produce and to market natural gas production. The pro-rationing of capacity on the inter-provincial pipeline systems also continues to affect the ability to export oil and natural gas.

The North American Free Trade Agreement

On January 1, 1994, the North American Free Trade Agreement ("NAFTA") among the governments of Canada, the U.S. and Mexico became effective. The NAFTA carries forward most of the material energy terms contained in the Canada-U.S. Free Trade Agreement. In the context of energy resources, Canada continues to remain free to determine whether exports to the U.S. 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 subject to an exception with respect to certain voluntary measures which only restrict the volume of exports, and (iii) disrupt normal channels of supply. All three countries are prohibited from imposing minimum or maximum export or import price requirements, provided, in the case of export-price requirements, prohibition in any circumstances in which any other form of quantitative restriction is prohibited, and in the case of import-price requirements, such requirements do not apply with respect to enforcement of countervailing and anti-dumping orders and undertakings.

NAFTA contemplates the reduction of Mexican restrictive trade practices in the energy sector by 2010 and prohibits discriminatory border restrictions and export taxes. NAFTA also contemplates clearer disciplines on regulators to ensure fair implementation of any regulatory changes and to minimize disruption of contractual arrangements and avoid undue interference with pricing, marketing and distribution arrangements, which is important for Canadian natural gas exports.

Provincial Royalties and Incentives

General

In addition to federal regulation, each province has legislation and regulations that govern land tenure, royalties, production rates, environmental protection and other matters. The royalty regime is a significant factor in the profitability of oil, natural gas, natural gas liquids and sulphur 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 also subject to certain provincial taxes and royalties. Our operations which are not Crown lands and are subject to the provisions of specific agreements are also usually subject to royalties negotiated between the mineral owner and the lessee. These royalties are not eligible for incentive programs sponsored by various governments as discussed below. Crown royalties are determined by governmental regulation and are generally calculated as a percentage of the value of the gross production, and the rate of royalties payable generally depends in part on prescribed reference prices, well productivity, geographical location, field discovery date, method of recovery and the type or quality of the petroleum product produced. Other royalties and royalty-like interests are from time to time carved out of the working interest owner's interest through non-public transactions. These are often referred to as overriding royalties, gross overriding royalties, net profits interests or net carried interests.

From time to time the governments of Canada and the western Canadian provinces have established 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. Royalty holidays and reductions would reduce the amount of Crown royalties paid by oil and gas producers to the provincial governments and would increase the net income and funds from operations of such producers. However, the trend in recent years has been for provincial governments to eliminate, amend or allow such incentive programs to expire without renewal, and consequently few such incentive programs are currently operative.

The Canadian federal corporate income tax rate levied on taxable income is 22.1% effective January 1, 2007 for active business income including resource income. With the elimination of the corporate surtax effective January 1, 2008 and other rate reductions introduced in the 2006 Federal Budget, the federal corporate income tax rate will decrease to 19% in three steps: 20.5% on January 1, 2008, 20% on January 1, 2009 and 19% on January 1, 2010.

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Alberta

In Alberta, companies are granted the right to explore, produce and develop petroleum and natural gas resources in exchange for royalties, bonus bid payments and rents.  Currently, the amount of royalties that are payable is influenced by the oil production, density of the oil, and the vintage of the oil.  Originally, the vintage classified oil in "new oil" and "old oil" depending on when the oil pools were discovered.  If discovered prior to March 31, 1974 it is considered "old oil", if discovered after March 31, 1974 and before September 1, 1992, it is considered "new oil".  The Alberta government introduced in 1992 a Third Tier Royalty with a base rate of 10 percent and a rate cap of 25 percent for oil pools discovered after September 1, 1992.  The new oil royalty reserved to the Crown has a base rate of 10 percent and a rate cap of 30 percent.  The old oil royalty reserved to the Crown has a base rate of 10 percent and a rate cap of 35 percent. 

The royalty reserved to the Crown in respect of natural gas production, subject to various incentives, is between 15 percent and 30 percent, in the case of new natural gas, and between 15 percent and 35 percent, in the case of old natural gas, depending upon a prescribed or corporate average reference price.  Natural gas produced from qualifying intervals in eligible natural gas wells spudded or deepened to a depth below 2,500 metres is also subject to a royalty exemption, the amount of which depends on the depth of the well. 

Oil sands projects are subject to a specific regulation made effective July 1, 1997 and expiring June 30, 2007, which, among other things, determines the Crown's share of crude and processed oil sands products.

Regulations made pursuant to the Mines and Minerals Act (Alberta) provided various incentives for exploring and developing oil reserves in Alberta.  However, the Alberta Government announced in August of 2006 that four royalty programs were to be amended, a new program was to be introduced and the Alberta Royalty Tax Credit Program ("ARTC") was to be eliminated, effective January 1, 2007.  The programs affected by this announcement are: (i) Deep Gas Royalty Holiday; (ii) Low Productivity Well Royalty Reduction; (iii) Reactivated Well Royalty Exemption; and (iv) Horizontal Re-Entry Royalty Reduction.  The program being introduced is the Innovative Energy Technologies Program (the "IETP") which is intended to promote the producers' investment in research, technology and innovation for the purposes of improving environmental performance while creating commercial value.  The IETP provides royalty reductions which are presumed to reduce financial risk.  Alberta Energy will be the one to decide which projects qualify and the level of support that will be provided.  The deadline for the IETP's third round of applications is May 31, 2007.

On February 16, 2007, the Alberta Government announced that a review of the province's royalty and tax regime (including income tax and freehold mineral rights tax) pertaining to oil, natural gas and oil sands will be conducted by a panel of experts, with the assistance of individual Albertans and key stakeholders.  The purpose of this process is to ensure that Albertans are receiving a fair share from energy development through royalties, taxes and fees.  The issues to be reviewed during this examination process are:  (i) undertaking a comparison of Alberta's royalty system to other oil and gas producing jurisdictions, taking into account investment economics and industry returns and risks in Alberta; (ii) whether Alberta's royalty system is sufficiently sensitive to market conditions; (iii) whether the current revenue minus cost system for oil sands royalties is optimal; (iv) which programs built into the existing royalty system should be retained or strengthened, and which should be adapted or eliminated; (v) how the tax treatment of the oil and gas sector compares to other sectors and jurisdictions; (vi) the economic and fiscal impacts of any possible changes to the royalty and corporate tax structures; and (vii) how existing resource development should be treated if changes are to be made to the fiscal regime.  The review panel is to produce a final report that will be presented to the Minister of Finance by August 31, 2007.

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British Columbia

Producers of oil and natural gas in British Columbia are required to pay annual rental payments in respect of Crown leases and royalties and freehold production taxes in respect of oil and natural gas produced from Crown and freehold lands.  The amount payable as a royalty in respect of oil depends on the type of oil, the value of the oil, the quantity of oil produced in a month and the vintage of the oil.  Generally, the vintage of oil is based on the determination of whether the oil is produced from a pool discovered before October 31, 1975 (old oil) between October 31, 1975 and June 1, 1998 (new oil) or after June 1, 1998 (third-tier oil).  The royalty rates are calculated in three stages which take into account the vintage of the oil, if the oil produced has already been sold and any royalty exempt value applicable (exempt wells).  Oil produced from newly discovered pools may be exempt from the payment of a royalty for the first 36 months of production or 11,450m³ produced, whichever comes first; and the royalties for third-tier oil are the lowest reflecting the higher costs of exploration and extraction that the producers would incur.  The royalty payable on natural gas is determined by a sliding scale based on a reference price, which is the greater of the price obtained by the producer, and a prescribed minimum price.  However, when the reference price is below the select price, the royalty rate is fixed.  As an incentive for the production and marketing of natural gas, which may have been flared, natural gas produced in association with oil has a lower royalty then the royalty payable on non-conservation natural gas. 

On May 30, 2003, the Ministry of Energy and Mines for the Province of British Columbia announced an Oil and Gas Development Strategy for the Heartlands ("Strategy").  The Strategy is a comprehensive program to address road infrastructure, targeted royalties, and regulatory reduction and British Columbia service sector opportunities.  In addition, the Strategy will result in economic and employment opportunities for communities in British Columbia's heartlands. 

Some of the financial incentives in the Strategy include:

·              Royalty credits of up to $30 million annually towards the construction, upgrading and maintenance of road infrastructure in support of resource exploration and development.  Funding will be contingent upon an equal contribution from industry. 

·              Changes to provincial royalties: new royalty rates for low productivity natural gas to enhance marginally economic resources plays, royalty credits for deep gas exploration to locate new sources of natural gas, and royalty credits for summer drilling to expand the drilling season. 

On February 27, 2007 the Government of British Columbia unveiled the Energy Plan outlining the Province's strategy towards the environment and which includes targeting for zero net greenhouse gas emissions, promoting new investments in innovation, and becoming the world's leader in sustainable environmental management. With regards to the oil and natural gas industry the objective is to achieve clean energy through conservation and energy efficient practices, whilst competitiveness is advocated in order to attract investment for the development of the oil and natural gas sector. Among the changes to be implemented are: (i) a new Net Profit Royalty Program; (ii) the creation of a Petroleum Registry; (iii) the establishing of an infrastructure royalty program (combining roads and pipelines); (iv) the elimination of routine flaring at producing wells; (v) the creation of policies and measures for the reduction of emissions; (vi) the development of unconventional resources such as tight gas and coalbed gas; and (vii) the Oil and Gas Technology Transfer Incentive Program that encourages the research, development and use of innovative technologies to increase recoveries from existing reserves and promotes responsible development of new oil and natural gas reserves.

Saskatchewan

In Saskatchewan, the amount payable as a royalty in respect of oil depends on the vintage of the oil, the type of  oil, the quantity of oil produced in a month, and the value of the oil. For Crown royalty and freehold production tax purposes, crude oil is considered "heavy oil", "southwest designated oil" or "non-heavy oil other than southwest designated oil". The conventional royalty and production tax classifications ("fourth tier oil" introduced October 1, 2002, "third tier oil", "new oil" or "old oil") of oil production are applicable to each of the three crude oil types. The Crown royalty and freehold production tax structure for crude oil is price sensitive and varies between the base royalty rates of five percent for all "fourth tier oil" to 20 percent for "old oil". Marginal royalty rates are 30 percent for all "fourth tier oil" to 45 percent for "old oil".

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The amount payable as a royalty in respect of natural gas is determined by a sliding scale based on a reference price which is the greater of the amount obtained by the producer and a prescribed minimum price, the quantity produced in a given month, the type of natural gas and the vintage of the natural gas. As an incentive for the production and marketing of natural gas which may have been flared, the royalty rate on natural gas produced in association with oil is less than on non-associated natural gas. The royalty and production tax classifications of gas production are "fourth tier gas" introduced October 1, 2002, "third tier gas", "new gas" and "old gas". The Crown royalty and freehold production tax for gas is price sensitive and varies between the base royalty rate of five percent for "fourth tier gas" and 20 percent for "old gas". The marginal royalty rates are between 30 percent for "fourth tier gas" and 45 percent for "old gas".

On October 1, 2002, the following changes were made to the royalty and tax regime in Saskatchewan :

·      A new Crown royalty and freehold production tax regime is applicable to associated natural gas (gas produced from oil wells) that is gathered for use or sale. The royalty /tax will be payable on associated natural gas produced from an oil well that exceeds approximately sixty-five thousand cubic metres in a month.

·      A modified system of incentive volumes and maximum royalty/tax rates applicable to the initial production from oil wells and gas wells with a finished drilling date on or after October 1, 2002, was introduced. The incentive volumes are applicable to various well types and are subject to a maximum royalty rate of 2.5 percent and a freehold production tax rate of zero percent.

·     The elimination of the re-entry and short section horizontal oil well royalty/tax categories. All horizontal oil wells with a finished drilling date on or after October 1, 2002, will receive the "fourth tier" royalty/tax rates and new incentive volumes.

In 1975, the Government of Saskatchewan introduced a Royalty Tax Rebate ("RTR") as a response to the federal government disallowing crown royalties and similar taxes as a deductible business expense for income tax purposes.  As of January 1, 2007, the remaining balance of any unused RTR will be limited in its carry forward to five years since the federal government had the initiative to reintroduce the full deduction of provincial resource royalties from federal and provincial taxable income.

Environmental Regulation

The oil and natural gas industry is currently subject to environmental regulation pursuant to a variety of, provincial and federal legislation.  Environmental legislation provides for restrictions and prohibitions on the release or emission of various substances produced or utilized in association with certain oil and natural gas industry operations.  In addition, legislation requires that well and facilities sites be abandoned and reclaimed to the satisfaction of provincial authorities.  As well, applicable environmental laws may impose remediation obligations with respect to property designated as a contaminated site upon certain responsible persons, which include persons responsible for the substance causing the contamination, persons who caused the release of the substance and any past or present owner, tenant or other person in possession of the site.  Compliance with such legislation can require significant expenditures and a breach of such legislation may result in the suspension or revocation of necessary licenses and authorizations, civil liability for pollution damage, the imposition of fines and material penalties or the issuance of clean-up orders. 

Environmental legislation in the Province of Alberta has been consolidated into the Environmental Protection and Enhancement Act (Alberta) (the "EPEA"), which came into force on September 1, 1993 and the Oil and Gas Conservation Act (Alberta) (the "OGCA").  The EPEA and OGCA impose stricter environmental standards, require more stringent compliance, reporting and monitoring obligations and significantly increased penalties.  In 2006, the Alberta Government enacted regulations pursuant to EPEA to specifically target sulphur oxide and nitrous oxide emissions from industrial operations, including the oil and gas industry.  No additional expenses are foreseen that are associated with complying with the new regulations.  We are committed to meeting our responsibilities to protect the environment wherever we operate and anticipate 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 EPEA 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. 

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British Columbia's Environmental Assessment Act became effective June 30, 1995.  This legislation rolls the previous processes for the review of major energy projects into a single environmental assessment process with public participation in the environmental and review process. 

In December, 2002, the Government of Canada ratified the Kyoto Protocol ("Protocol").  The Protocol calls for Canada to reduce its greenhouse gas emissions to six percent below 1990 "business-as-usual" levels between 2008 and 2012.  Given revised estimates of Canada's normal emissions levels, this target translates into an approximately 40 percent gross reduction in Canada's current emissions.  It remains uncertain whether the Kyoto target of 6% below 1990 emission levels will be enforced in Canada.  The Federal Government has introduced legislation aimed at reducing greenhouse gas emissions using a "intensity based" approach, the specifics of which have yet to be determined.  Bill C-288, which is intended to ensure that Canada meets its global climate change obligations under the Kyoto Protocol, was passed by the House of Commons on February 14, 2007.  As details of the implementation of this legislation have not yet been announced, the effect of our operations cannot be determined at this time.

We are committed to meeting our responsibilities to protect the environment wherever we operate and anticipate making increased, although not material, expenditures of both a capital and expense nature as a result of increasingly stringent laws relating to the protection of the environment. 

All government regulations and procedures will be followed in strict adherence to the law.  We believe in well abandonment and site restoration in a timely manner to ensure minimal damage to the environment and lower overall costs to us.

Proposed Federal Tax Changes

On October 31, 2006 the Federal Minister of Finance announced a proposal to apply a tax at the trust level on distributions of certain income from publicly traded mutual fund trusts at rates of tax comparable to the combined federal and provincial corporate tax and to treat such distributions as dividends to the unitholders  (the "October 31 Proposals").  On December 21, 2006 the Federal Minister of Finance released draft legislation to implement the October 31, 2006 Proposals pursuant to which, commencing January 1, 2011 (provided we only experience "normal growth" and no "undue expansion" before then) certain of our distributions which would have otherwise been taxed as ordinary income generally will be characterized as dividends in addition to being subject to tax at corporate rates at the Trust level.  On February 28, 2007 the House of Commons Finance Committee released its report on the proposed trust tax. The Committee recommended significant changes to the original proposal, including a reduction of the tax rate from 31.3 percent to 10 percent or an extension of the phase in period from four years to ten years. It is not yet certain if the government will accept these proposals. Assuming the October 31 Proposals are ultimately enacted in their current form, the implementation of such legislation would be expected to result in adverse tax consequences to us and certain Unitholders (including most particularly Unitholders that are tax deferred or non-residents of Canada) and may impact our cash distributions.

Management believes that the October 31 Proposals may reduce the value of the Trust Units, which would be expected to increase our cost of raising capital in the public capital markets.  In addition management believes that the October 31 Proposals are expected to:  (a) substantially eliminate the competitive advantage that we and other Canadian energy trusts enjoy relative to their corporate peers in raising capital in a tax-efficient manner; and (b) place us and other Canadian energy trusts at a competitive disadvantage relative to industry competitors, including U.S. master limited partnerships, which will continue to not be subject to entity level taxation.  The October 31 Proposals are also expected to make the Trust Units less attractive as an acquisition currency.  As a result, it may become more difficult to compete effectively for acquisition opportunities.  There can be no assurance that we will be able to reorganize our legal and tax structure to substantially mitigate the expected impact of the October 31 Proposals.

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Further, the October 31 Proposals provide that, while there is no intention to prevent "normal growth" during the transitional period, any "undue expansion" could result in the transition period being "revisited", presumably with the loss of the benefit to us of that transitional period.  As a result, the adverse tax consequences resulting from the October 31 Proposals could be realized sooner than January 1, 2011.  On December 15, 2006, the Department of Finance issued guidelines with respect to what is meant by "normal growth" in this context.  Specifically, the Department of Finance stated that "normal growth" would include equity growth within certain "safe harbour" limits, measured by reference to a "specified investment flow-through's" ("SIFT") market capitalization as of the end of trading on October 31, 2006 (which would include only the market value of the SIFT's issued and outstanding publicly-traded trust units, and not any convertible debt, options or other interests convertible into or exchangeable for trust units).  Those safe harbour limits are 40% for the period from November 1, 2006 to December 31, 2007, and 20% each for calendar 2008, 2009 and 2010.  Moreover, these limits are cumulative, so that any unused limit for a period carries over into the subsequent period.  Additional details of the Department of Finance's guidelines include the following:

·      new equity for these purposes includes units and debt that is convertible into units (and may include other substitutes for equity if attempts are made to develop those);

·     replacing debt that was outstanding as of October 31, 2006 with new equity, whether by a conversion into trust units of convertible debentures or otherwise, will not be considered growth for these purposes and will therefore not affect the safe harbour; and

·     the exchange, for trust units, of exchangeable partnership units or exchangeable shares that were outstanding on October 31, 2006 will not be considered growth for those purposes and will therefore not affect the safe harbour where the issuance of the trust units is made in satisfaction of the exercise of the exchange right by a person other than the SIFT.

Our market capitalization as of the close of trading on October 31, 2006, having regard only to our issued and outstanding publicly-traded Trust Units, was approximately $1.8 billion, which means our "safe harbour" equity growth amount for the period ending December 31, 2007 is approximately $730 million, and for each of calendar 2008, 2009 and 2010 is an additional $365 million approximately (in any case, not including equity, including convertible debentures, issued to replace debt that was outstanding on October 31, 2006).

While these guidelines are such that it is unlikely they would affect our ability to raise the capital required to maintain and grow our existing operations in the ordinary course during the transition period, they could adversely affect the cost of raising capital and our ability to undertake more significant acquisitions.

It is not known at this time when the October 31 Proposals will be enacted by Parliament, if at all, or whether the October 31 Proposals will be enacted in the form currently proposed.

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ADDITIONAL INFORMATION

Additional information relating to us can be found on SEDAR at www.sedar.com and on our website at www.baytex.ab.ca.  Additional information, including directors' and officers' remuneration and indebtedness, principal holders of our securities and securities issued and authorized for issuance under our equity compensation plans is contained in our Information Circular – Proxy Statement for the May 17, 2007 annual and special meeting of Unitholders.  Additional financial information is contained in our consolidated financial statements for the year ended December 31, 2006 and the related management's discussion and analysis which have been filed on SEDAR at www.sedar.com.  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, AlbertaT2P 2V7

Phone:             (403) 269-4282

Fax:                   (403) 205-3845

www.baytex.ab.ca

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                                                                                                                                                                                   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, 2006 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, 2006 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

(c)                 reviewed the reserves data with management and the independent qualified reserves evaluator.

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 Reserves 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

(c)                 the content and filing of this report.

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) "W. Derek Aylesworth"
Raymond T. Chan	W. Derek Aylesworth
President and Chief Executive Officer	Chief Financial Officer
(signed) "Dale O. Shwed""	(signed) "John A. Brussa"
Dale O. Shwed	John A. Brussa
Director	Director
March 2, 2007

                                                                                                       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, 2006.  The reserves data consist of the following:

(a)         (i)            proved and proved plus probable oil and gas reserves estimated as at December 31, 2006 using forecast prices and costs; and

(ii)         the related estimated future net revenue; and

(b)         (i)             proved oil and gas reserves estimated as at December 31, 2006 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, 2006, 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 Report	Location of Reserves (County)	Net Present Value of Future Net Revenue (before income taxes, 10% discount rate) ($Million)
			Audited	Evaluated	Reviewed	Total
Sproule Associates Limited	Evaluation of the P&NG Reserves of Baytex Energy Trust, as of December 31, 2006, prepared Oct 2006 to February 2007	Canada	-	1,631.3	-	1,631.3

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

March 2, 2007

                                                                                                                                                                          APPENDIX C

                                                                                                                                                                BAYTEX ENERGY LTD.

                                                                                                                          AUDITCOMMITTEE

                                                                                                                                              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

1.             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").

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

3.            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

1.            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.

2.           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.

3.          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.

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

5.        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

1.       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.

2.      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.

3.      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.

4.         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.

5.        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.

6.         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.

7.         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.

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

9.         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.

10.       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.

11.       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.

12.       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.