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Baytex Energy Trust (BTE) SEC Filing 40-F Annual report for the fiscal year ending Friday, March 26, 2010

Baytex Energy Corp.

CIK: 1279495 Ticker: BTE


 
Exhibit 99.1

 

 
BAYTEX ENERGY TRUST
 

 

 

 
ANNUAL INFORMATION FORM
 
2009
 

 

 

 

 

 

 
MARCH 26, 2010
 

 

 
 

 

TABLE OF CONTENTS
 

 
 
Page
   
SELECTED TERMS
1
ABBREVIATIONS
3
CONVERSIONS
3
CONVENTIONS
4
SPECIAL NOTES TO READER
4
BAYTEX ENERGY TRUST
7
GENERAL DEVELOPMENT OF OUR BUSINESS
9
RISK FACTORS
10
DESCRIPTION OF OUR BUSINESS AND OPERATIONS
24
ADDITIONAL INFORMATION RESPECTING BAYTEX ENERGY TRUST
52
ADDITIONAL INFORMATION RESPECTING BAYTEX ENERGY LTD
61
AUDIT COMMITTEE INFORMATION
66
BAYTEX SHARE CAPITAL
68
MARKET FOR SECURITIES
68
RATINGS
70
LEGAL PROCEEDINGS AND REGULATORY ACTIONS
70
INTEREST OF INSIDERS AND OTHERS IN MATERIAL TRANSACTIONS
71
AUDITORS, TRANSFER AGENT AND REGISTRAR
71
INTERESTS OF EXPERTS
71
MATERIAL CONTRACTS
71
INDUSTRY CONDITIONS
72
ADDITIONAL INFORMATION
83
 
 
APPENDICES:
 
APPENDIX A
REPORT OF MANAGEMENT AND DIRECTORS ON OIL AND GAS DISCLSOURE
 
APPENDIX B
REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATOR
 
APPENDIX C
AUDIT 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.
 
Baytex Partnership means Baytex Energy Partnership, a general partnership, the partners of which are Baytex and Baytex Oil & Gas Ltd.
 
Baytex USA means Baytex Energy USA Ltd.
 
Board of Directors means the board of directors of Baytex.
 
Crew means Crew Energy Inc.
 
OPEC means the Organization of the Petroleum Exporting Countries.
 
Operating Entities means the subsidiaries of the Trust that are actively involved in the acquisition, production, processing, transportation and marketing of crude oil, natural gas liquids and natural gas, being Baytex, Baytex Partnership, Baytex Oil & Gas Ltd. and Baytex USA, each a direct or indirect wholly-owned subsidiary of the Trust, and Operating Subsidiary means any one of them, as applicable.
 
SEC means the United States Securities and Exchange Commission.
 
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" of the Canadian Securities Administrators.
 
Sproule means Sproule Associates Limited, independent petroleum consultants of Calgary, Alberta.
 
Sproule Report means the report prepared by Sproule dated March 19, 2010 entitled "Evaluation of the P&NG Reserves of Baytex Energy Trust and Baytex Energy USA Ltd. (As of December 31, 2009)".
 
Securities and Other Terms
 
Assignment and Novation Agreement means the assignment and novation agreement made as of January 1, 2010 among us, Baytex and Baytex Partnership.
 
Convertible Debentures means our 6.50% convertible unsecured subordinated debentures due December 31, 2010 and issued pursuant to the trust indenture dated June 6, 2005 among us, Baytex and Valiant Trust Company.
 
 
 

 
- 2 -
 

Credit Facilities means, collectively, the operating loan that Baytex has with a chartered bank and a 364-day revolving loan that Baytex has with a syndicate of chartered banks, in an aggregate amount of $515 million, which each mature on June 30, 2010 (subject to extension thereafter in certain circumstances).
 
Debentures means our 9.15% series A senior unsecured debentures due August 26, 2016 and issued pursuant to the Indenture.
 
DRIP means our distribution reinvestment plan.
 
Exchangeable Shares means the exchangeable shares of Baytex which are exchangeable for Trust Units.
 
Exchange Ratio means the ratio at which Exchangeable Shares may be converted to Trust Units.
 
GAAP means generally accepted accounting principles in Canada.
 
Indenture means the trust indenture dated August 26, 2009 among us, our Operating Entities and Baytex Marketing Ltd. (as guarantors) and Valiant Trust Company.
 
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 other Operating Entities to us from time to time.
 
Note Indenture means the note indenture relating to the Notes issued on September 2, 2003.
 
NPI means the net profit interests in certain petroleum substances owned by Baytex Partnership.
 
NPI Agreement means the amended and restated net profit interests agreement between us and Baytex made as of September 2, 2003, as further amended by an amending agreement dated January 1, 2010, providing for the creation of the NPI, which NPI Agreement was subsequently assigned by Baytex to Baytex Partnership on January 1, 2010 pursuant to the Assignment and Novation Agreement.
 
Special Voting Units means the special voting units issued by us entitling holders of Exchangeable Shares to voting rights at meetings of Unitholders.
 
Tax Act means the Income Tax Act (Canada), R.S.C. 1985, c. 1 (5th Supp.), as amended, including the regulations promulgated thereunder, as amended from time to time.
 
Trust Indenture means the third amended and restated trust indenture between our trustee, Valiant Trust Company, and Baytex made as of May 20, 2008.
 
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.
 
 
 

 
- 3 -
 
 
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
bbl/d
barrels per day
MMcf/d
million cubic feet per day
   
m3
cubic metres
   
MMbtu
million British Thermal Units
   
GJ
gigajoule
       
Other
     
BOE or boe
barrel of oil equivalent, using the conversion factor of 6 Mcf of natural gas being equivalent to one bbl of oil. BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 Mcf: 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
Mboe
thousand barrels of oil equivalent.
MMboe
million barrels of oil equivalent.
boe/d
barrels of oil equivalent per day.
WTI
West Texas Intermediate.
API
the measure of the density or gravity of liquid petroleum products derived from a specific gravity.
$ Million
means millions of dollars.
$000s
means thousands of dollars.
 
 

 
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
6.293
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
0.948
 
 
 

 
- 4 -
 
 
 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 "$" or "dollars" are to Canadian dollars and references to "US$" are to United States dollars.  All financial information contained in this Annual Information Form has been presented in Canadian dollars in accordance with GAAP.  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 NOTES TO READER
 
Forward-Looking Statements
 
In the interest of providing our Unitholders and potential investors with information about us, including management's assessment of our future plans and operations, certain statements in this Annual Information Form are "forward-looking statements" within the meaning of the United States Private Securities Litigation Reform Act of 1995 and "forward-looking information" within the meaning of applicable Canadian securities legislation (collectively, "forward-looking statements").  In some cases, forward-looking statements can be identified by terminology such as "anticipate", "believe", "continue", "could", "estimate", "expect", "forecast", "intend", "may", "objective", "ongoing", "outlook", "potential", "project", "plan", "should", "target", "would", "will" or similar words suggesting future outcomes, events or performance.  The forward-looking statements contained in this Annual Information Form speak only as of the date hereof and are expressly qualified by this cautionary statement.
 
In addition there are forward looking statements in this Annual Information Form under the headings: "Baytex Energy Trust – Federal Tax Changes for Income Trusts and Corporations" (as to our anticipated conversion to a corporation and related tax matters) and "Description of Our Business and Operations – Statement of Reserves Data and Other Oil and Gas Information" (as to our reserves and future net revenues from our reserves, pricing and inflation rates, future development costs, the development of our proved undeveloped reserves and probable undeveloped reserves, future development activities, hedging policies, reclamation and abandonment obligations, tax horizon, exploration and development activities and production estimates).
 
Specifically, this Annual Information Form contains forward-looking statements relating to:  the taxation of income trusts; our plans to convert our legal structure from a trust to a corporation, the timing of such conversion, the payment of dividends following such conversion, our ability to utilize our tax pools to reduced our taxable income following such conversion and the impact of such conversion on our unitholders; our distribution practice; the portion of our funds from operations to be allocated to cash distributions and our capital program; our ability to maintain production levels by investing approximately half of our internally generated funds from operations; our ability to grow our reserve base and add to production levels through exploration and development activities complemented by strategic acquisitions; our petroleum and natural gas reserves, including the quantum thereof and the present value of the future net revenue to be derived therefrom; development plans for our properties, including number of potential drilling locations, number of wells to be drilled in 2010, initial production rates from new wells and recovery factors; our heavy oil resource play at Seal, including the resource potential of our undeveloped land, initial production rates from new wells, the ability to recover incremental reserves using waterflood and cyclic steam recovery methods, our assessment of the viability and economics of a commercial-scale cyclic steam injection project, the timing for completion of a commercial-scale cyclic steam injection project and the ability to recover incremental reserves by reducing inter-well spacing; our light oil resource play in North Dakota, including our assessment of the number of wells to be drilled, initial production rates from new wells and average recoveries per well; our working interest production volume for 2010; the existence, operation, and strategy of our commodity price risk management program; funding sources for cash distributions and our capital program; and the impact of existing and proposed governmental and environmental regulation.  In addition, information and statements relating to reserves and resources are deemed to be forward-looking statements, as they involve implied assessment, based on certain estimates and assumptions, that the reserves described exist in quantities predicted or estimated, and that the reserves and resources can be profitably produced in the future.
 
 
 

 
- 5 -
 

These forward-looking statements are based on certain key assumptions regarding, among other things: petroleum and natural gas prices and differentials between light, medium and heavy oil prices; well production rates and reserve volumes; our ability to add production and reserves through our exploration and development activities; capital expenditure levels; the availability and cost of labour and other industry services; the amount of future cash distributions that we intend to pay; interest and foreign exchange rates; and the continuance of existing and, in certain circumstances, proposed tax and royalty regimes.  Readers are cautioned that such assumptions, although considered reasonable by Baytex at the time of preparation, may prove to be incorrect.
 
Actual results achieved during the forecast period will vary from the information provided herein as a result of numerous known and unknown risks and uncertainties and other factors.  Such factors include, but are not limited to: declines in petroleum and natural gas prices; variations in interest rates and foreign exchange rates; uncertainties relating to the weakened global economy and consequential restricted access to capital, stock market volatility, market valuations and increased borrowing costs; refinancing risk for existing debt and debt service costs; access to external sources of capital; risks associated with our hedging activities; third party credit risk; risks associated with the exploitation of our properties and our ability to acquire reserves; government regulation and control and changes in governmental legislation; changes in income tax laws, royalty rates and other incentive programs; uncertainties associated with estimating oil and natural gas reserves; risks associated with our conversion to a corporate structure; risks associated with acquiring, developing and exploring for oil and natural gas and other aspects of our operations; the timing of payment of distributions, if any; risks associated with large projects or expansion of our activities; the failure to realize anticipated benefits of acquisitions and dispositions or to manage growth; risks associated with residency restrictions in the ownership of our Trust Units; changes in climate change laws and other environmental regulations; competition in the oil and gas industry for, among other things, acquisitions of reserves, undeveloped lands, skilled personnel and drilling and related equipment; the application of accounting policies; the activities of our Operating Entities and their key personnel; depletion of our reserves; risks associated with securing and maintaining title to our properties; seasonality; our permitted investments; risks associated with our structure and ownership of Trust Units; risks for United States and other non-resident unitholders and other factors, many of which are beyond the control of Baytex.
 
Readers are cautioned that the foregoing list of risk factors is not exhaustive.  New risk 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.  Readers should also carefully consider the matters discussed under the heading "Risk Factors" in this Annual Information Form.
 
There is no representation by Baytex that actual results achieved during the forecast period will be the same in whole or in part as those forecast and Baytex does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required by applicable securities law.  The forward-looking statements contained in this Annual Information Form are expressly qualified by this cautionary statement.
 
Description of Funds from Operations
 
This Annual Information Form contains references to funds from operations derived from cash flow from operating activities before changes in non-cash working capital and other operating items. Funds from operations as presented does not have any standardized meaning prescribed by GAAP, and therefore it may not be comparable with the calculation of similar measures for other entities. Funds from operations as presented is not intended to represent operating cash flow or operating profits for the period nor should it be viewed as an alternative to cash flow provided by operating activities, net income or other measures of financial performance calculated in accordance with GAAP.
 
For more information, see our "Management's Discussion and Analysis of the operating and financial results" which includes a definition of "funds from operations" and a reconciliation to cash flow from operating activities and is accessible on the SEDAR website at www.sedar.com.
 
 
 

 
- 6 -
 

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 general matter, we are only required to comply with three of the NYSE rules: 1) we must have an audit committee that satisfies the requirements of the United States Securities Exchange Act of 1934; 2) our 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) we must 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 applicable to U.S. companies and confirm that our corporate governance practices do not differ significantly from such standards.
 
Access to Documents
 
Any document referred to in this Annual Information and described as being accessible on the SEDAR website at www.sedar.com (including those documents referred to as being incorporated by reference in this Annual Information Form) may be obtained free of charge from us at 2200, 205 – 5th Avenue S.W., Calgary, Alberta, Canada, T2P 2V7.
 
 
 

 
- 7 -
 
 
BAYTEX ENERGY TRUST
 
General
 
We are an open-ended, unincorporated investment trust created under the laws of the Province of Alberta pursuant to the Trust Indenture. Our head and principal office is located at Suite 2200, 205 – 5th Avenue S.W., Calgary, Alberta, T2P 2V7.
 
We were formed on July 24, 2003 and commenced operations on September 2, 2003 as a result of the completion of a plan of arrangement under the Business Corporations Act (Alberta) on September 2, 2003 involving us, Baytex, Crew, Baytex Acquisition Corp., Baytex ExchangeCo, Baytex Resources Ltd. and Baytex Exploration Ltd. Pursuant to the plan of arrangement, former holders of common shares of Baytex received common shares of Crew and Trust Units, or Exchangeable Shares or a combination thereof, in accordance with the elections made by such shareholders, and Baytex became a subsidiary of us.
 
Inter-Corporate Relationships
 
The following table provides the name, the percentage of voting securities owned by us and the jurisdiction of incorporation, continuance, formation or organization 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 Energy Partnership
100%
Alberta
Baytex Oil & Gas Ltd.
100%
Alberta
Baytex Energy USA Ltd.
100%
Colorado
BEL Liquidity Management LLC
100%
Hungary

 
 

 
- 8 -
 

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.
 
 
Note:
(1)  
Cash distributions are made on a monthly basis to Unitholders based upon our funds from operations. Our primary sources of funds from operations are NPI payments from Baytex Partnership 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.
 
Federal Tax Changes for Income Trusts and Corporations
 
On June 22, 2007, the federal legislation (Bill C-52) (the "SIFT Rules") implementing the tax on distributions by certain publicly traded specified investment flow-through trust entities (a "SIFT") received Royal Assent.  The SIFT Rules are not expected to effect us until 2011 provided we do not exceed the normal growth guidelines announced by the Department of Finance.  We can increase our equity by approximately $1,160.7 million before 2011 without exceeding the normal growth guidelines. We do not anticipate that the normal growth guidelines will impair our ability to annually replace or grow reserves in the next year as the guidelines allow sufficient growth targets.
 
 
 

 
- 9 -
 
 
Under the SIFT Rules, the tax rate for a SIFT (the "SIFT tax") will be the federal general corporate income tax rate and the applicable provincial corporate rate. The federal general corporate income tax rate will be 16.5 percent in 2011 and 15 percent after 2011 and the provincial component will be 10 percent.
 
The tax legislation for the conversion of a SIFT into a taxable Canadian corporation on a tax deferred basis received Royal Assent on March 12, 2009.
 
Management and the Board of Directors continue to work on the plan for converting us to a corporation on or before January 1, 2011.  After the conversion, the corporation would expect to allocate its funds from operations among funding a portion of capital expenditures, periodic debt repayments, site reclamation expenditures and cash payments to shareholders in the form of dividends.  Current taxes payable by us after converting to a corporation will be subject to normal corporate tax rates.  Taxable income as a corporation will vary depending on total income and expenses and vary with changes to commodity prices, costs, claims for both accumulated tax pools and tax pools associated with current year expenditures.  As we have approximately $749.7 million of Canadian income tax pools as at December 31, 2009, it is expected that taxable income will be reduced or potentially eliminated for the initial period post-conversion.
 
Returns to shareholders after conversion to a corporation will be impacted by the reduction of funds from operations required to pay current income taxes, if any.  Over the longer term, we would expect Canadian investors who hold their Trust Units in a taxable account to be relatively indifferent on an after-tax basis as to whether we are structured as a corporation or as a trust in 2011.  However, Canadian tax deferred investors (those holding their trust units in a tax deferred vehicle such as a registered retirement savings plan, a registered retirement income fund or a pension plan) and foreign investors will realize a lower after-tax return on distributions in taxable years after 2011 due to the introduction of the SIFT tax should we stay as a trust, and their inability to claim the dividend tax credit if we convert to a corporation.
 
If a conversion from the trust structure to a corporation is approved by the Unitholders, the income tax payable will vary and each Unitholder should consult their own tax advisor for details on the direct impact to themselves.
 
For more information, see "Risk Factors – Risks Relating to our Business and Operations – Income tax laws, or other laws or government incentive programs or regulations relating to our industry may in the future be changed or interpreted in a manner that adversely affects us and our Unitholders" and "– We are in the process of converting to a corporate structure which may result in adverse consequences to our financial condition".
 
GENERAL DEVELOPMENT OF OUR BUSINESS
 
History and Development
 
On June 15, 2007, we completed a public offering of 7,000,000 subscription receipts (the "Sub Receipts") for gross proceeds of $149,450,000. Upon the June 26, 2007 closing of the property acquisition described below, the holders of the Sub Receipts received one Trust Unit in exchange for each Sub Receipt held. The net proceeds of this financing were used to partially fund the acquisition of properties at Pembina and Lindbergh described below.
 
On June 26, 2007, we completed the indirect acquisition of certain oil and gas producing properties in the Pembina and Lindbergh areas of Alberta for $238 million. These assets were producing approximately 4,500 boe/d of total production at the time of the acquisition. This production was comprised of 2,200 bbl/d of light oil and NGL and 8.0 MMcf/d of natural gas from the Pembina area, and 1,000 bbl/d of heavy oil from the Lindbergh area. The acquisition in the Pembina area allowed us to establish a new core area in the Nisku trend, offering greater exposure to high netback light oil and NGL targets. The assets included 26,000 net acres of undeveloped land in the Pembina area. Lindbergh is a project that offers a large heavy oil resource in place that is amenable to primary (cold) production. Its shallow-depth and multiple zone character provide a low-cost source of recompletion and drilling inventory. In addition to the primarily non-operated producing assets at Lindbergh, we also acquired 11,000 net acres of 100% interest undeveloped land that may include opportunities for shallow natural gas development.
 
 
 

 
- 10 -
 
 
On June 4, 2008, we acquired all of the issued and outstanding shares of Burmis Energy Inc. ("Burmis") on the basis of 0.1525 of a Trust Unit for each Burmis common share.  Approximately 6.38 million Trust Units were issued pursuant to this transaction, which was valued at approximately $180.5 million.  Pursuant to this transaction, we acquired multi-zone, liquids-rich natural gas and light oil properties located in west central Alberta and approximately 110,300 net acres of undeveloped land.  Production from the Burmis properties averaged 3,791 boe/d during the first quarter of 2008.
 
During the third quarter of 2008, we acquired a significant land position in a Bakken/Three Forks light oil resource play in the Williston Basin in northwest North Dakota from a private company (the "North Dakota Project").  Upon making all deferred payments associated with the transaction, we will have acquired a 37.5% interest in 263,000 (98,600 net) acres, 94% of which are undeveloped.  In addition, we acquired approximately 300 boe/d (95% oil) of production.  The seller retained the remaining 62.5% interest in the project lands and production.
 
On April 14, 2009, we completed a public offering of 7,935,000 Trust Units at a price of $14.50 per Trust Unit for gross proceeds of $115,057,500.  The net proceeds of the offering were used to repay outstanding bank indebtedness.
 
On July 30, 2009, we completed the acquisition of predominantly heavy oil assets located in the Kerrobert and Coleville areas of southwest Saskatchewan, plus certain natural gas assets located in the Ferrier area of west central Alberta effective May 1, 2009.  Aggregate cash consideration for the acquisition was $86.2 million, net of adjustments such as net operating income for the interim period from May 1, 2009 to July 30, 2009 and prepaid items.  The acquired assets were producing approximately 3,000 boe/d (72% heavy oil and 28% natural gas) at the time of the acquisition.  The acquired assets included approximately 47,700 net acres of developed land and 63,300 net acres of undeveloped land in close proximity to our Lloydminster area.
 
On August 26, 2009, we completed a public offering of $150 million principal amount of 9.15% Series A senior unsecured debentures due August 26, 2016.  The net proceeds of the offering along with funds drawn on the Credit Facilities were used to fund the redemption effective September 25, 2009 of the following senior subordinated notes of Baytex: 9.625% notes due July 15, 2010 (principal amount US$179.7 million) and 10.5% notes due February 15, 2011 (principal amount US$0.2 million).
 
In November, 2009, we reached an agreement with our joint venture partner in the North Dakota Project to pre-pay the remaining deferred acquisition payments.  The original participation agreement with the joint venture partner called for deferred acquisition payments totalling approximately US$36 million to be made prior to the spud date of each of the remaining 24 earning wells, occurring more or less rateably until approximately January 2011.  On December 15, 2009, we paid our joint venture partner US$33.2 million to complete the remaining deferred acquisition payments and to earn the right to operate a portion of the joint project area effective at the beginning of 2010.
 
Significant Acquisitions
 
During the year ended December 31, 2009, we did not complete any acquisitions for which disclosure was required under Part 8 of National Instrument 51-102.
 
 
RISK FACTORS
 
You should carefully consider the following risk factors, as well as the other information contained in this Annual Information Form and our other public filings before making an investment decision.  If any of the risks described below materialize, our business, financial condition or results of operations could be materially and adversely affected.  Additional risks and uncertainties not currently known to us that we currently view as immaterial may also materially and adversely affect our business, financial condition or results of operations.  Residents of the United States and other non-residents of Canada should have additional regard to the risk factors under the heading "– Certain Risks for United States and other non-resident Unitholders".
 
 
 

 
- 11 -
 
 
The information set forth below contains "forward-looking statements", which are qualified by the information contained in the section of this Annual Information Form entitled "Special Notes to Reader – Forward-Looking Statements".
 
Risks Relating to Our Business and Operations
 
Declines in oil and natural gas prices will adversely affect our financial condition
 
Our operational results and financial condition, and therefore the amounts we pay to Unitholders as distributions, will be dependent on the prices received for our oil and natural gas production.  The extreme volatility of oil and natural gas prices over the past few years has impacted our monthly distributions per Trust Unit, which reached a high of $0.25 for June to November 2008, before being reduced to $0.18 for December 2008 and January 2009 and $0.12 for February to November 2009.  With the recovery in oil and natural gas prices, monthly distributions per Trust Unit were increased to $0.18 in December 2009.  Declines in oil and natural gas prices will result in further declines in, or elimination of such distributions.  Oil and natural gas prices are determined by economic factors and in the case of oil prices, political factors and a variety of additional factors beyond our control.  These factors include economic conditions in the United States and Canada and worldwide, the actions of OPEC, governmental regulation, political stability in the Middle East and elsewhere, internal capacity to produce natural gas in the United States from shale deposits, the foreign supply of oil and natural gas, risks of supply disruption, the price of foreign imports and the availability of alternative fuel sources.  Any substantial and extended decline in the price of oil and natural gas would have an adverse effect on the carrying value of our proved and probable reserves, net asset value, borrowing capacity, revenues, profitability and funds from operations and ultimately on our financial condition and therefore on the amounts to be distributed to our Unitholders.  Volatile oil and natural gas prices make it difficult to estimate the value of producing properties for acquisitions and often cause disruption in the market for oil and natural gas producing properties, as buyers and sellers have difficulty agreeing on such value.  Price volatility also makes it difficult to budget for and project the return on acquisitions and development and exploitation projects.
 
Variations in interest rates and foreign exchange rates could affect our ability to service our debt
 
There is a risk that the interest rates will increase given the current historical low level of interest rates.  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, and could impact the market price of the Trust Units.
 
World oil prices are quoted in United States dollars and the price received by Canadian producers is therefore affected by the Canadian/U.S. dollar exchange rate that may fluctuate over time and in fact increased by 17% in 2009.  A material increase in the value of the Canadian dollar negatively impacts our production revenue and our ability to maintain future distributions.  Future Canadian/United States exchange rates could also impact the future value of our reserves as determined by our independent evaluator.
 
The global economy has not fully recovered and unforeseen events may negatively impact our financial condition
 
Market events and conditions, including disruptions in the international credit markets and other financial systems and the deterioration of global economic conditions, caused significant volatility to commodity prices over the last few years.  These conditions worsened in 2008 and continued in early 2009, causing a loss of confidence in the broader U.S. and global credit and financial markets and resulting in the collapse of, and government intervention in, major banks, financial institutions and insurers and creating a climate of greater volatility, less liquidity, widening of credit spreads, a lack of price transparency, increased credit losses and tighter credit conditions.  Notwithstanding various actions by governments, concerns about the general condition of the capital markets, financial instruments, banks, investment banks, insurers and other financial institutions caused the broader credit markets to further deteriorate and stock markets to decline substantially.  Although economic conditions improved towards the latter portion of 2009 and continue to improve in 2010, these factors have negatively affected company and trust valuations and continue to impact the performance of the global economy going forward.
 
 
 
 
 

 
- 12 -
 
 
Our bank credit facility will need to be renewed prior to June 30, 2010 and failure to renew, in whole or in part, or higher interest charges will adversely affect our financial condition
 
We currently have Credit Facilities in the amount of $515 million. At December 31, 2009, we had approximately $198 million of unused credit available under the Credit Facilities.  In the event that the Credit Facilities are not extended before June 30, 2010, indebtedness under the Credit Facilities will be repayable at that date.  There is also a risk that the Credit Facilities will not be renewed for the same amount or on the same terms.
 
As at December 31, 2009, our outstanding indebtedness included $7.8 million of Convertible Debentures which are convertible at the option of the holder at any time into fully-paid Trust Units at a price of $14.75 per unit and mature on December 31, 2010.  We intend to partially fund these debt maturities with our existing Credit Facilities; however, we are subject to limitations on the amounts we can draw on our Credit Facilities in order to repay the Convertible Debentures. Subject to certain rights we have under our Credit Facilities to the extent the amounts outstanding thereunder have been reduced by payments sourced from equity issues, asset sales or the unwinding of hedges, the maximum amount we may draw for any such repayments is 20% of the amount of our Credit Facilities and this amount is reduced to nil if the amount drawn on our Credit Facilities exceeds 75% of the amount thereof. In the event we are unable to refinance our debt obligations, it may impact our ability to fund our ongoing operations and distribute cash.
 
We are required to comply with covenants under the Credit Facilities and the indentures governing the Debentures and Convertible Debentures.  In the event that we do not comply with these covenants, our access to capital could be restricted or repayment could be required on an accelerated basis by our lenders, and the ability to make distributions to our Unitholders may be restricted.  The lenders under the Credit Facilities have security over substantially all of our assets.  If we become unable to pay our debt service charges or otherwise commit an event of default such as breach of our financial covenants, the lenders under the Credit Facilities may foreclose on or sell our working interests in our properties.
 
Amounts paid in respect of interest and principal on debt may reduce distributions.  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 distributions.  Certain covenants in the agreements with our lenders under the Credit Facilities and the holders of the Debentures may also limit distributions.  Although we believe the Credit Facilities will be sufficient for our immediate requirements, there can be no assurance that the amount will be adequate for our future financial obligations including our future capital expenditure program, or that we will be able to obtain additional funds.
 
From time to time we may enter into transactions which may be financed in whole or in part with debt.  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.
 
We have been historically reliant on external sources of capital, borrowings and equity sales, and if unavailable, our financial condition will be adversely affected
 
As future capital expenditures will be financed out of funds from operations, borrowings and possible future equity sales, our ability to do so is dependent on, among other factors, the overall state of capital markets and investor appetite for investments in the energy industry and our securities in particular.
 
To the extent that external sources of capital become limited or unavailable or available on onerous terms, our ability to make capital investments and maintain or expand existing assets and reserves may be impaired, and our assets, liabilities, business, financial condition, results of operations and distributions may be materially and adversely affected as a result.
 
Alternatively, we may issue additional Trust Units from treasury at prices which may result in a decline in production per Trust Unit and reserves per Trust Unit or may wish to borrow to finance significant acquisitions or development projects to accomplish our long term objectives on less than optimal terms or in excess of our optional capital structure.
 
 
 
 

 
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We believe that estimated funds from operations, together with the existing credit facility, will be sufficient to substantially finance our current operations, distributions to Unitholders and planned capital expenditures for the ensuing year.  The timing of most of our capital expenditures is discretionary and there are no material long-term capital expenditure commitments. The level of distributions is also discretionary, and we have the ability to modify distribution levels should funds from operations be negatively impacted by a reduction in commodity prices or other factors.  However, if funds from operations is lower than expected or capital costs for these projects exceed current estimates, or if we incur major unanticipated expenses related to development or maintenance of our existing properties, we may be required to seek additional capital to maintain our capital expenditures at planned levels.  Failure to obtain any financing necessary for our capital expenditure plans may result in a delay in development or production on our properties or a decrease in distributions.
 
Our hedging activities may negatively impact our income and our financial condition
 
We may manage the risk associated with changes in commodity prices by entering into petroleum or natural gas price hedges.  If we hedge our commodity price exposure, we may forego some of the benefits we would otherwise experience if commodity prices were to increase.  As at December 31, 2009, our balance sheet reflected $25.9 million of net unrealized gains resulting from hedges to protect our commodity risk exposure.  For more information in relation to our commodity hedging program, see "Statement of Reserves Data and Other Oil and Natural Gas Information – Other Oil and Gas Information – Forward Contracts".  We may initiate certain hedges to attempt to mitigate the risk of the Canadian dollar appreciating against the U.S. dollar.  The increase in the exchange rate for the Canadian dollar and future Canadian/United States exchange rates will impact future distributions and the future value of our reserves as determined by independent evaluators.  These hedging activities could expose us to losses and to credit risk associated with counterparties with which we contract.
 
Failure of third parties to meet their contractual obligations to us may have a material adverse affect on our financial condition
 
We are exposed to third party credit risk through our contractual arrangements with our current or future joint venture partners, third party operators, marketers of our petroleum and natural gas production, hedge counterparties and other parties.  We manage this credit risk by entering into sales contracts with only creditworthy entities and reviewing our exposure to individual entities on a regular basis.  However, in the event such entities fail to meet their contractual obligations to us, such failures may have a material adverse effect on our business, financial condition, results of operations and prospects.  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 ability to maintain distributions is dependent on a number of factors including volatility of prices for oil and gas, interest rates, sources of capital, changes in legislation and those set forth below
 
Our ability to add to our oil and natural gas reserves is highly dependent on our success in exploiting existing properties and acquiring additional reserves.  Our long-term commercial success depends on our ability to find, acquire, develop and commercially produce petroleum and natural gas reserves. Future oil and natural gas exploration may involve unprofitable efforts, not only from dry wells, but also from wells that are productive but do not produce sufficient petroleum substances to return a profit after drilling, operating and other costs. Completion of a well does not assure a profit on the investment or recovery of drilling, completion and operating costs. In addition, drilling hazards or environmental damage could greatly increase the cost of operations, and various field operating conditions may adversely affect the production from successful wells. These conditions include delays in obtaining governmental approvals or consents, shut-ins of connected wells resulting from extreme weather conditions, insufficient storage or transportation capacity or other geological and mechanical conditions. While diligent well supervision and effective maintenance operations can contribute to maximizing production rates over time, production delays and declines from normal field operating conditions cannot be eliminated and can be expected to adversely affect revenue and cash flow levels to varying degrees. 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.
 
 
 
 

 
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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. Labour costs, electricity, gas processing, well servicing and chemicals are a few of our operating costs that are susceptible to material fluctuation. There is no assurance that further commercial quantities of petroleum and natural gas will be discovered or acquired by us.
 
There is no assurance we will be successful in developing additional reserves or acquiring additional reserves on terms that meet our investment objectives.  Without these reserves additions, our reserves will deplete and as a consequence, either production from, or the average reserves life of, our properties will decline, which will result in a reduction in the value of Trust Units and in a reduction in funds from operations available for distributions to Unitholders.
 
Our business is heavily regulated and such regulation increases our costs and may adversely affect our financial condition
 
Oil and natural gas operations (including land tenure, exploration, development, production, refining, pricing, transportation and marketing) are subject to extensive controls and regulations imposed by various levels of government, which may be amended from time to time. Governments may regulate or intervene with respect to prices, taxes, royalties and the exportation of oil and natural gas.  Regulation increases our costs.  In order to conduct oil and gas operations, we require licenses and permits 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.  See "Industry Conditions".
 
Income tax laws, or other laws or government incentive programs or regulations relating to our industry may in the future be changed or interpreted in a manner that adversely affects us and our Unitholders
 
We expect to continue to qualify as a mutual fund trust for purposes of the Tax Act. We may not, however, always be able to satisfy any future requirements for the maintenance of mutual fund trust status.
 
Should our status as a mutual fund trust be lost or successfully challenged by a relevant tax authority, certain adverse consequences may arise for us and 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 NPI 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.
 
·
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.
 
·
Trust Units could cease to be a qualified investment for registered retirement savings plans ("RRSPs"), registered education savings plans ("RESPs"), deferred profit sharing plans ("DPSPs"), registered disability savings plans ("RDSPs"), tax free savings accounts ("TFSAs") and registered retirement income funds ("RRIFs").  Where, at the end of a month, a RRSP, DPSP, RESP or RRIF holds Trust Units that cease to be a qualified investment, the plan must, in respect of that month, pay a tax equal to 1% of the fair market value of the Trust Units at the time such Trust Units were acquired by the plan.  Trusts governed by RRSPs, RDSPs, TFSAs or RRIFs which hold Trust Units that are not qualified investments will be subject to tax on the income attributable to the Trust Units while they are not qualified investments, including the full capital gains, if any, realized on the disposition of such Trust Units.  Where a trust governed by a RRSP or a RRIF acquires Trust Units that are not qualified investments, the value of the investment is included in the income of the annuitant for the year of the acquisition.  Trusts governed by RESPs which hold Trust Units that are not qualified investments can have their registration revoked by the Canada Revenue
 
 
 
 

 
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        Agency.  The holder of a RDSP or TFSA which holds Trust Units that are not qualified investments will be subject to tax equal to 50% of the fair market value of the Trust Units.
 
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 Tax Act.  See "Additional Information Respecting Baytex Energy Trust – Trust Indenture – Non-resident Unitholders".
 
Tax authorities having jurisdiction over us or Unitholders may disagree with how we calculate our income for tax purposes or could change administrative practices to our detriment or the detriment of Unitholders.
 
The oil and natural gas industry is subject to extensive controls and regulations governing its operations (including land tenure, exploration, development, production, refining, transportation, and marketing) imposed by legislation enacted by various levels of government and with respect to pricing and taxation of oil and natural gas by agreements among the governments of Canada, Alberta, British Columbia, and Saskatchewan, all of which should be carefully considered by investors in the oil and gas industry.  All of such controls, regulations and legislation are subject to revocation, amendment or administrative change, some of which have historically been material and in some cases materially adverse and there can be no assurance that there will not be further revocation, amendment or administrative change which will be materially adverse to our assets, reserves, financial condition or results of operations or prospects and our ability to maintain distributions.
 
There are numerous uncertainties inherent in estimating quantities of recoverable petroleum and natural gas reserves, including many factors beyond our control
 
Although we, together with Sproule, have carefully prepared the reserves figures included in this Annual Information Form 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.
 
In general, estimates of economically recoverable petroleum and natural gas reserves and resources and the future net revenues therefrom are based upon a number of variable factors and assumptions, such as historical production from the properties, production rates, ultimate reserve recovery, timing and amount of capital expenditures, marketability of petroleum and natural gas, royalty rates, the assumed effects of regulation by governmental agencies and future operating costs, all of which may vary materially from actual results.  All such estimates are based on professional judgment and classifications of reserves, which, by their nature have a high degree of subjectivity. For those reasons, estimates of the economically recoverable oil and natural gas reserves or estimates of resources attributable to any particular group of properties, classification of such reserves based on risk of recovery and estimates of future net revenues associated with reserves prepared by different engineers, or by the same engineers at different times, may vary.
 
The reserves and recovery information contained in the Sproule Report is only an estimate and the actual production and ultimate reserves from the properties may be greater or less than the estimates prepared by Sproule and such variations could be material.  The Sproule Report has been prepared using certain commodity price assumptions which are described in the notes to the reserves tables.  If we realize lower prices for crude oil, natural gas liquids and natural gas and they are substituted for the price assumptions utilized in the Sproule Report, the present value of estimated future net revenues for our reserves and our net asset value would be reduced and the reduction could be significant. The estimates in the Sproule Report are based in part on the timing and success of activities we intend to undertake in future years. The reserves and estimated cash flows to be derived therefrom contained in the Sproule Report will be reduced, in future years, to the extent that such activities do not achieve the level of success assumed in the Sproule Report.
 
Estimates of proved undeveloped reserves are sometimes based upon volumetric calculations and upon analogy to similar types of reserves rather than actual production history.  Recovery factors and drainage areas were estimated by experience and analogy to similar producing pools.  Estimates based on these methods are generally less reliable than those based on actual production history.  Subsequent evaluation of the same reserves based upon production history and production practices will result in variations in the estimated reserves and such variations could be material.
 
 
 

 
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We are in the process of converting to a corporate structure which may result in adverse consequences to our financial condition
 
New federal legislation passed in June 2007, will apply a tax at the trust level on distributions of certain income from trusts, such as us, at rates of tax comparable to the combined federal and provincial corporate tax and will treat such distributions as dividends to the Unitholders effective January 1, 2011.  The SIFT tax results 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 distributions.
 
The SIFT tax will substantially eliminate the competitive advantage that we and other Canadian energy trusts enjoyed relative to their corporate peers in raising capital in a tax-efficient manner, and will make the Trust Units less attractive as an acquisition currency. As a result, it may become more difficult for us 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 SIFT tax.
 
No assurance can be provided that the SIFT tax will not apply to us prior to January 1, 2011, or that the legislation will not be further changed in a manner which adversely affects us and our Unitholders.  For more information, see "Baytex Energy Trust – Federal Tax Changes for Income Trusts and Corporations".
 
Acquiring, developing and exploring for oil and natural gas involves many risks, which even a combination of experience, knowledge and careful evaluation may not be able to overcome
 
These risks include, but are not limited to, encountering unexpected formations or pressures, premature declines of reservoirs, blow-outs, craterings, equipment failures and other accidents, sour gas releases and spills, uncontrollable flows of oil, natural gas or well fluids, the invasion of water into producing formations, adverse weather conditions, pollution, other environmental risks, fires, spills and delays in payments between parties caused by operation or economic matters which could result in substantial damage to oil and natural gas wells, production facilities, other property and the environment, personal injuries, loss of life and other hazards, all of which could result in liability.  These risks will increase as the Trust undertakes more exploratory activity.  Although we maintain insurance in accordance with customary industry practice, we are not 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. In addition, the nature of these risks is such that liabilities could exceed policy limits, in which event we could incur significant costs that could have a material adverse effect upon our financial condition.
 
Exploration and development risks arise due to the uncertain results of searching for and producing petroleum and natural gas using imperfect scientific methods. These risks are mitigated by using highly skilled staff, focusing exploration efforts in areas in which we have existing knowledge and expertise or access to such expertise, using up-to-date technology to enhance methods and controlling costs to maximize returns.
 
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.  Other companies operate some of the properties in which we have an interest and as a result our returns on assets operated by others depends upon a number of factors outside our control.  To the extent the operator fails to perform these functions properly, operating income may be reduced.  In addition, 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. Our return on assets operated by others will therefore depend upon a number of factors that may be outside of our control, including the timing and amount of capital expenditures, the operator's expertise and financial resources, the approval of other participants, the selection of technology and risk management practices.
 
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 our Operating Entities, 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 properties or the establishment by the operator of reserves for such expenses.
 
 
 

 
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Losses resulting from the occurrence of any of these risks may have a material adverse effect on our business, financial condition, results of operations, prospects and our ability to maintain distributions.
 
The marketability of petroleum and natural gas that may be acquired or discovered by us will be affected by numerous factors beyond our control
 
These factors include demand for petroleum and natural gas, market fluctuations, the proximity and capacity of oil and natural gas pipelines and processing equipment and government regulations, including regulations relating to environmental protection, royalties, allowable production, pricing, importing and exporting of oil and natural gas and political events throughout the world that cause disruptions in the supply of oil. Any particular event could result in a material decline in prices and therefore result in a reduction of our net production revenue. 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.
 
Our Board of Directors has discretion in the payment of distributions and may not choose to maintain distributions in certain circumstances
 
The Trust Indenture provides that all of our distributable income at the end of any calendar month including December 31 shall be declared payable and distributed to Unitholders of record on the last day of each such calendar month.  The distribution by us of such distributable income is enforceable by such Unitholders of record.  However, if this amount is not determined and declared payable in accordance with the rules of the Toronto Stock Exchange, the right to receive this income will trade with the Trust Units.  The Trust Indenture provides that this distributable income is allocated to Unitholders for tax purposes and to the extent a Unitholder trades Trust Units in this period, they will be allocated such income but will have disposed of their right to receive such distribution.
 
In addition, the Trust Indenture provides that such distributable income may be paid in Trust Units.  The Trust Indenture also provides for the consolidation of the Trust Units in the discretion of our Board of Directors to the pre-distribution number of Trust Units after any pro-rata distribution of additional Trust Units to all Unitholders. Accordingly, the Trust Indenture allows for the payment of distributions in a form other than cash and Unitholders may have taxable income and cash taxes payable.
 
We may participate in larger projects and may have more concentrated risk in certain areas of our operations
 
We manage a variety of small and large projects in the conduct of our business.  Project delays may impact 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 depends 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;
·   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 could 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 only operate in western Canada and the United States and expansion outside of these areas may increase our risk exposure
 
Our operations and expertise are currently primarily focused on oil and gas production and development in the Western Canadian Sedimentary Basin and the United States.  In the future, we may acquire oil and gas properties outside of these geographic areas. In addition, the terms of the Trust Indenture do not limit us to oil and gas production and development, and we could acquire other energy related assets, such as oil and natural gas processing plants or pipelines, or an interest in an oil sands project. 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 adversely affect our business, financial condition or results of operations.
 
We may not be able to realize the anticipated benefits of acquisitions and dispositions or to manage growth
 
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 our operations.  There is no assurance that we will be able to continue to complete acquisitions or dispositions of oil and natural gas properties which realize all the synergistic benefits.
 
We periodically dispose of non-core assets so that management can focus its 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.
 
The price we pay for the purchase of any material properties is based on several criteria, including engineering and economic estimates of the reserves made by independent engineers modified to reflect our technical and economic views. These assessments include a number of material factors and assumptions.  Many of these factors are subject to change and are beyond our control.  Consequently, the reserves acquired may be less than expected, which could adversely impact cash flow from operating activities and distributions to Unitholders.  See "Baytex Energy Trust – General Development of the Business".
 
We may be subject to growth-related risks including capacity constraints and pressure on our internal systems and controls.  Our ability to manage growth effectively will require us to continue to implement and improve our operational and financial systems and to expand, train and manage our employee base.  Our inability to deal with this growth could have a material adverse effect on our business, financial condition, results of operations and prospects.
 
We have the authority to impose restrictions on the issuance of Trust Units to, or the transfer by any Unitholder, of Trust Units to a non-resident
 
We intend to comply with the requirements under the Tax Act for "unit trusts" and "mutual fund trusts" at all relevant times such that we maintain our status of a unit trust and a mutual fund trust for purposes of the Tax Act.  In this regard, we may, from time to time, among other things, take all necessary steps to monitor our activities and ownership of the Trust Units.  If at any time we become aware that our activities and ownership of the Trust Units by non-residents (non-residents of Canada and partnerships) may threaten our status under the Tax Act as a "unit trust" or "mutual fund trust", we are authorized to take such action as may be necessary in our opinion to maintain our status as a unit trust and a mutual fund trust, including the imposition of restrictions on the issuance by the Trust, or the transfer by any Unitholder, of Trust Units to a non-resident.  See "Additional Information Respecting Baytex Energy Trust – Trust Indenture – Non-resident Unitholders".
 
Climate change laws and related environment regulation may impose restrictions or costs on our business which may adversely affect our financial condition and our ability to maintain distributions
 
Nearly all aspects of our operations are subject to environmental regulation pursuant to a variety of federal, provincial and local laws and regulations.  Environmental legislation provides for, among other things, restrictions
 
 
 

 
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and prohibitions or spills, releases or emissions of various substances produced in association with oil and natural gas operations.  The legislation also requires that wells and facility sites be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities.  A breach of such legislation may result in the imposition of fines or issuance of clean up orders in respect of us or our properties, some of which may be material.  We may also be exposed to civil liability for environmental matters or for the conduct of third parties, including private parties commencing actions and new theories of liability, regardless of negligence or fault.  Furthermore, management believes the political climate appears to favour new programs for environmental laws and regulation, particularly in relation to the reduction of emissions or emissions intensity, and there is no assurance that any such programs, laws or regulations, if proposed and enacted, will not contain emission reduction targets which we cannot meet, and financial penalties or charges could be incurred as a result of the failure to meet such targets.  For more information on the evolution and status of climate change and related environmental legislation, see "Industry Conditions – Climate Change Regulation".
 
There has been much public debate with respect to the Government's strategy or alternative strategies with respect to climate change and the control of greenhouse gases.  Implementation of strategies by either the provinces in which we operate our business or by the Government of Canada, and whether to meet international agreed limits, or as otherwise determined, for reducing greenhouse gases could have a material impact on the nature of oil and natural gas operations, including ours.  Given the evolving nature of the debate related to climate change and the control of greenhouse gases and resulting requirements, it is not possible to predict either the nature of those requirements or the impact on us and our operations and financial condition.  Although we provide for the necessary amounts in our annual capital budget to fund our currently estimated environmental and reclamation obligations, there can be no assurance that we will be able to satisfy our actual future environmental and reclamation obligations from such funds.
 
Although we believe that we are in material compliance with current applicable environmental regulations, no assurance can be given that environmental laws will not result in a curtailment of production, a reduction of product demand, a material increase in the costs of production, development or exploration activities or otherwise adversely affect our business, financial condition, results of operations or prospects. Future changes in other environmental legislation could occur and result in stricter standards and enforcement, larger fines and liability, and increased capital expenditures and operating costs, which could have a material adverse effect on our financial condition or results of operations and prospects.  See "Industry Conditions – Climate Change Regulation".
 
There is strong competition relating to all aspects of the oil and gas industry
 
There are numerous trusts and other companies in the oil and gas industry, who are competing with us for the acquisitions of properties with longer life reserves, properties with exploitation and development opportunities and undeveloped land.  As a result of such competition, it may be more difficult for us to acquire reserves on beneficial terms.  Many of these other oil and gas companies have significantly greater financial and other resources than we do.
 
We compete with other oil and gas entities to hire and retain skilled personnel necessary for running our daily operations including planning, capitalizing on available technical advances and the execution of our exploration and development program.  The inability to hire and retain skilled personnel could adversely impact certain of our operational and financial results.
 
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.
 
Application of GAAP or US GAAP to our financial results may result in non-cash losses which may adversely affect the market price of our Trust Units
 
GAAP requires that management 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
 
 
 

 
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write-downs may be viewed unfavourably by the market and may result in an inability to borrow funds and/or may result in a decline in the market price of our Trust Units.
 
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 revenues 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 gas properties are highly dependent upon the prices for petroleum and natural gas.
 
Under US GAAP, companies using the full cost method of accounting for oil and gas producing activities perform a ceiling test on each cost centre using discounted estimated future net revenue from proved oil and natural gas reserves using a discount rate of 10 percent.  Prices used in the US GAAP ceiling tests are based on the average price, during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period.  For further information, see Note 21 of our audited consolidated financial statements for the year ended December 31, 2009 which is incorporated by reference in this Annual Information Form and which has been filed on SEDAR at www.sedar.com.
 
Under GAAP, the accounting for derivatives may result in non-cash charges against net income as a result of changes in the fair market value of derivative instruments. A decrease in the fair market value of the derivative 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.
 
Our success depends in large measure on the activities of our Operating Entities and their key personnel
 
We are a limited purpose trust and are entirely dependent upon the operations and assets of our Operating Entities through our ownership, directly and indirectly, of securities of our Operating Entities, including the Notes, and the NPI.  Accordingly, our ability to pay distributions to Unitholders is dependent upon the ability of our Operating Entities to meet their interest, principal, dividend and other distribution obligations on their securities and to pay the NPI.  Our Operating Entities' income is derived from the production of oil and natural gas from their resource properties and is susceptible to the risks and uncertainties associated with the oil and natural gas industry generally.  If the oil and natural gas reserves associated with our Operating Entities' resource properties are not supplemented through additional development or the acquisition of additional oil and natural gas properties, the ability of our Operating Entities to meet their obligations to us and our ability to pay distributions to Unitholders may be adversely affected.
 
The loss of key personnel of our Operating Entities could delay the completion of certain projects or otherwise have a material adverse effect on us.  Unitholders will be dependent on our management in respect of the administration and management of all matters relating to our properties, the NPI, the Trust Units and the safekeeping of our primary workspace and computer systems.  As of December 31, 2009, we operated approximately 93 percent of the total daily production of our properties.  Investors who are not willing to rely on our management should not invest in our Trust Units.
 
Our petroleum and natural gas reserves are a depleting resource and decline as such reserves are produced
 
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 petroleum and natural gas reserves.  Our future petroleum and natural gas reserves and production, and therefore our funds from operations, will be highly dependent on our success in exploiting our reserves base and acquiring additional reserves. Without reserves additions through acquisition or development activities, our reserves and production may decline over time as reserves are produced.
 
 
 
 

 
- 21 -
 
 
We also distribute a significant proportion of our funds from operations to Unitholders rather than reinvesting it in reserves additions. Accordingly, 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 our petroleum and natural gas reserves may be impaired. To the extent that we use funds from operations to finance capital expenditures or property acquisitions, the level of funds from operations available for distribution to Unitholders will be reduced. There can be no assurance that we will be successful in developing or acquiring additional reserves on terms that meet our investment objectives.
 
Securing and maintaining title to our properties is subject to certain risks
 
Our properties are held in the form of licenses and leases and working interests in licenses and leases.  If we or the holder of the license or lease fails to meet the specific requirement of a license or lease, the license or lease may terminate or expire.  There can be no assurance that any of the obligations required to maintain each license or lease will be met.  The termination or expiration of a license or lease or the working interest relating to a license or lease may have a material adverse affect on our results of operations and business.  In addition title to the properties can become subject to dispute and defeat our claim to title over certain of our properties.
 
Aboriginal peoples have claimed aboriginal title and rights to portions of western Canada and have also made claims that certain developments, including oil and gas exploration and development, may have been proceeding without the Crown carrying out appropriate consultations in the course of allowing such developments to proceed.  We are not aware that any material claims have been made in respect of our properties and assets; however, if a claim arose and was successful this could have an adverse effect on us and our operations.
 
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.
 
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 such investments, 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.
 
Risks Relating to Our Structure and Ownership of Trust Units
 
Distributions do not represent a "yield" and are not comparable to debt instruments and rights of redemption have limited liquidity
 
Our Trust Units will have no value when reserves from our properties can no longer be economically produced or marketed and, as a result, 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
 
 
 

 
- 22 -
 
 
maturity in addition to a return on investment through interest payments.  Distributions represent a blend of return of Unitholders initial investment and a return on Unitholders initial investment.
 
Unitholders have a limited right to require a repurchase of their Trust Units, which is referred to as a redemption right.  It is anticipated that the redemption right will not be the primary mechanism for Unitholders to liquidate their investment.  The right to receive cash in connection with a redemption is subject to material limitations.  Any securities which may be distributed in specie to Unitholders in connection with a redemption may not be listed on any stock exchange and a market may not develop for such securities and such securities may be illiquid.  In addition, there may be resale restrictions imposed by law upon the recipients of the securities pursuant to the redemption right.  See "Additional Information Respecting Baytex Energy Trust – Trust Indenture – Redemption Right".
 
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 us.  Corporate law does not govern the Trust 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), the Companies' Creditors Arrangement Act (Canada) and in some cases the Winding Up and Restructuring 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.  Our sole assets will be the NPI and other investments in securities. The price per Trust Unit is a function of anticipated distributable income, the properties acquired by us and our ability 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 and our ability to acquire suitable oil and natural gas properties. Changes in market conditions may adversely affect the trading price of the Trust Units.
 
The Trust Units are not "deposits" within the meaning of the Canada Deposit Insurance Corporation Act (Canada) and are not insured under the provisions of that Act or any other legislation.  Furthermore, we are not a trust company and, accordingly, 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.
 
The Trust Units are also unlike conventional debt instruments in that there is no principal amount owing to Unitholders. The Trust Units will have no value when reserves from our properties can no longer be economically produced or marketed. Unitholders will only be able to obtain a return of the capital they invested during the period when reserves may be economically recovered and sold. Accordingly, the distributions received over the life of the investment may not be equal to or greater than the initial capital investment.
 
Unitholder limited liability is subject to contractual and statutory assurances which may have some enforcement risks
 
The Trust Indenture provides that no Unitholder will be subject to any liability in connection with us or our obligations and 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 will indemnify and hold harmless each Unitholder from any costs, damages, liabilities, expenses, charges and losses suffered by a Unitholder resulting from or arising out of such Unitholder not having such limited liability.
 
The Trust Indenture provides that all written instruments signed by or on behalf of the Trust must contain a provision to the effect that such obligation will not be binding upon Unitholders personally. The principal investment of the Trust is the NPI which contains such provisions.  Personal liability may also arise in respect of claims against 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 of this nature arising is considered unlikely.  The Income Trusts Liability Act (Alberta) came into force on July 1, 2004.  The legislation provides that a Unitholder
 
 
 

 
- 23 -
 
 
will not be, as a beneficiary, liable for any act, default, obligation or liability of the trustee that arises after the legislation came into force.
 
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.
 
Certain Risks for United States and other non-resident Unitholders
 
There is limited liability of residents in the United States to enforce civil remedies
 
We are a trust organized under the laws of Alberta, Canada and our principal place of business is in Canada.  Most of our directors and officers and the representatives of the experts who provide services to us (such as our auditors and our independent reserve engineers), and all or a substantial portion of our assets and the assets of such persons are located outside the United States.  As a result, it may be difficult for investors in the United States to effect service of process within the United States upon such directors, officers and representatives of experts who are not residents of the United States or to enforce against them judgements of the United States courts based upon civil liability under the United States federal securities laws or the securities laws of any state within the United States.  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 judgements of United States courts of liabilities based solely upon the United States federal securities laws or securities laws of any state within the United States.
 
There are differences in reporting practices in Canada and the United States
 
We report our production and reserve quantities in accordance with Canadian practices and specifically in accordance with NI 51-101.  These practices are different from the practices used to report production and to estimate reserves in reports and other materials filed with the SEC by companies in the United States.
 
We incorporate additional information with respect to production and reserves which is either not generally included or prohibited under rules of the SEC and practices in the United States.  We follow the Canadian practice of reporting gross production and reserve volumes (before deduction of Crown and other royalties); however, we also follow the United States practice of separately reporting reserve volumes on a net basis (after the deduction of royalties and similar payments).  We also follow the Canadian practice of using forecast prices and costs when we estimate our reserves; whereas the SEC rules require that a 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, be utilized.
 
We included in this Annual Information Form estimates of proved and proved plus probable reserves.  Probable reserves have a lower certainty of recovery than proved reserves. The SEC requires oil and gas issuers in their filings with the SEC to disclose only proved reserves but permits the optional disclosure of probable reserves.  The SEC definitions of proved reserves and probable reserves are different than NI 51-101; therefore, proved, probable and proved plus probable reserves disclosed in this Annual Information Form may not be comparable to United States standards.
 
As a consequence of the foregoing, our reserve estimates and production volumes in this Annual Information Form may not be comparable to those made by companies utilizing United States reporting and disclosure standards.
 
There is additional taxation applicable to non-residents
 
The Tax Act and the tax treaties between Canada and other countries may impose additional withholding or other taxes on the distributions or other property paid by us to Unitholders who are non-residents of Canada, and these taxes may change from time to time.  Since January 1, 2005, a 15 percent Canadian withholding tax is applied to the return of capital portion of distributions made to non-resident Unitholders.
 
 
 

 
- 24 -
 
 
Additionally, the reduced "Qualified Dividend" rate of 15 percent tax applied to our distributions under current U.S. tax laws is scheduled to expire at the end of 2010 and there is no assurance that this reduced tax rate will be renewed by the U.S. government at such time.
 
Furthermore, it is anticipated that the implementation of the SIFT tax may have tax consequences for non-residents of Canada that are more adverse than the tax consequences to other classes of Unitholders.
 
There is a foreign exchange risk for non-resident Unitholders
 
Our distributions are declared in Canadian dollars and converted to foreign denominated currencies at the spot exchange rate at the time of payment.  As a consequence, investors are subject to foreign exchange risk.  To the extent that the Canadian dollar strengthens with respect to their currency, the amount of the distribution will be reduced when converted to their home currency.
 
DESCRIPTION OF OUR BUSINESS AND OPERATIONS
 
Overview
 
We are an open-ended, unincorporated investment trust created under the laws of the Province of Alberta 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, make 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 Tax Act) 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 Tax Act.
 
Our principal undertaking is to issue Trust Units and other securities and to acquire and hold securities of subsidiaries, trusts and partnerships, net profits interests, royalties, notes and other interests.  Our Operating Entities carry on the business of acquiring, developing, exploiting and holding interests in petroleum and natural gas properties and assets related thereto in Canada (primarily in the provinces of British Columbia, Alberta and Saskatchewan) and in the United States (primarily in the states of North Dakota and Wyoming).  Cash flow from the business carried on by our Operating Entities is flowed to us by way of interest and principal repayments on the Notes and income earned under the NPI.
 
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 or about the 15th day following the end of each calendar month to Unitholders of record on or about the last business day of each such calendar month.  Our current distribution practice targets the use of
 
 
 

 
- 25 -
 
 
between 50 to 60 percent of our funds from operations for capital expenditures to fund both exploration and development expenditures and minor property acquisitions, but excludes 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 their obligations under the Credit Facilities or upon a material borrowing base shortfall or default.
 
Our Debentures also contain certain limitations on maximum cumulative distributions.  Restricted payments include the declaration or payment of any dividend or distribution by us and the payment of interest or principal on subordinated debt owed by us.  We and certain of our subsidiaries are restricted from making any restricted payments unless at the time of, and immediately after giving effect to, the proposed restricted payment, no default or event of default under the Indenture has occurred and is continuing, and either:  (i) (a) we could incur at least $1.00 of additional indebtedness (other than certain permitted debt) in accordance with the "Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock" covenant in the Indenture; (b) the ratio of consolidated debt to consolidated cash flow from operations does not exceed 3.0 to 1.0; and (c) the aggregate amount of all restricted payments declared or made after August 26, 2009 (other than certain permitted restricted payments) does not exceed the sum of: (A) 80% of consolidated cash flow from operations accrued on a cumulative basis since August 26, 2009, plus (B) 100% of the aggregate net cash proceeds received by us after August 26, 2009 from (x) the issuance by us of convertible debentures, or (y) capital contributions in respect of certain permitted equity that we receive from any person; plus (C) the aggregate net proceeds, including the fair market value of property received after August 26, 2009 other than cash (as determined by the Board of Directors), received by us from any person, other than a subsidiary, from the issuance or sale of debt securities (including convertible debentures) or disqualified stock that have been converted into or exchanged for certain permitted equity of us, plus the aggregate net cash proceeds received by us at the time of such conversion or exchange; or (ii) the aggregate amount of all restricted payments declared or made pursuant to paragraph (i) does not exceed the sum of certain unpaid funds from restricted payments not previously expended under paragraph (i), plus $50,000,000.
 
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 exploration, exploitation, development, acquisition and production in Canada. We are the sole common shareholder of Baytex.
 
The head office of Baytex is located at Suite 2200, 205 – 5th Avenue S.W., Calgary, Alberta, T2P 2V7 and its registered office is located at Suite 1400, 350 – 7th Avenue S.W., Calgary, Alberta T2P 3N9.
 
NPI
 
Effective January 1, 2010, we are a party to the NPI Agreement with Baytex Partnership pursuant to which we have the right to receive a NPI on certain petroleum and natural gas rights owned by Baytex Partnership (the "NPI Properties").  Pursuant to the terms of the NPI Agreement, we are entitled to a payment from the owner of the NPI Properties for each month equal to the amount by which 99 percent of the gross proceeds from the sale of production attributable to the NPI Properties for such month exceed 99 percent of certain deductible costs for such period.  The owner of the NPI Properties is entitled to set off amounts reimbursable to it against NPI payments payable by it.  The term of the NPI Agreement is for so long as there are petroleum and natural gas rights to which the NPI applies.
 
Notes
 
A Note was issued by Baytex to us under the Note Indenture in connection with the plan of arrangement completed on September 2, 2003.  The Note is unsecured, payable on demand and bears 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.
 
 
 
 

 
- 26 -
 
 
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 trustee appointed under the Note Indenture to exercise the powers and remedies available under the Note Indenture upon an event of default and either we or 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 Baytex the flexibility to delay payments of interest or principal otherwise due to us while payment is made to the Non-Fund Holders, and to allow the Non-Fund Holders to be paid out before us. 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.
 
Statement of Reserves Data and Other Oil and Natural Gas Information
 
The statement of reserves data and other oil and natural gas information set forth below is dated December 31, 2009. The statement is effective as of December 31, 2009 and the preparation date of the statement by Sproule is March 19, 2010. 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.
 
Disclosure of Reserves Data
 
The reserves data set forth below is based upon an evaluation by Sproule with an effective date of December 31, 2009 as contained in the Sproule Report. The reserves data summarizes our crude oil, natural gas liquids and natural gas reserves and the net present values of future net revenue for these reserves using forecast prices and costs, not including the impact of any hedging activities. The Sproule Report has been prepared in accordance with the standards contained in the COGE Handbook and the reserve definitions contained in NI 51-101. Sproule was engaged by us to provide an evaluation of our proved and proved plus probable reserves and no attempt was made to evaluate possible reserves. See also "Definitions and Other Notes to Reserve Data Tables" below.
 
Our reserves are located in Canada, specifically in the provinces of Alberta, British Columbia and Saskatchewan, and in the United States, specifically in the states of North Dakota and Wyoming.
 
All evaluations of future net revenue are after the deduction of future income tax expenses (unless otherwise noted in the tables), royalties, development costs, production costs and well abandonment costs but before consideration of indirect costs such as administrative, overhead and other miscellaneous expenses. The estimated future net revenue contained in the following tables does not necessarily represent the fair market value of our reserves. There is no assurance that the forecast price and cost assumptions contained in the Sproule Report will be attained and variations could be material. Other assumptions and qualifications relating to costs and other matters are summarized in the notes to or following the tables below. The recovery and reserve estimates described herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Readers should review the definitions and information contained in "Definitions and Notes to Reserves Data Tables" in conjunction with the following tables and notes. For more information as to the risks involved, see "Risk Factors".
 
 
 
 

 
27 -
 
 
 
SUMMARY OF OIL AND NATURAL GAS RESERVES
AS OF DECEMBER 31, 2009
FORECAST PRICES AND COSTS
 
CANADA
 
 
LIGHT AND MEDIUM OIL
HEAVY OIL
NATURAL GAS LIQUIDS
RESERVES CATEGORY
Gross
(Mbbl)
Net
(Mbbl)
Gross
(Mbbl)
Net
(Mbbl)
Gross
(Mbbl)
Net
(Mbbl)
PROVED:
           
Developed Producing
4,584.2
3,373.3
31,357.7
25,997.0
1,989.3
1,450.3
Developed Non-Producing
   487.4
   368.6
16,333.8
13,782.6
   515.9
   373.7
Undeveloped
3,789.3
2,813.6
49,363.0
41,952.9
   312.9
   225.5
TOTAL PROVED
8,860.9
6,555.5
97,054.5
81,732.5
2,818.1
2,049.5
PROBABLE
4,232.3
2,964.8
48,542.3
40,959.7
1,500.2
1,083.6
TOTAL PROVED PLUS PROBABLE
13,093.2  
9,520.3
    145,596.8      
  122,692.2   
4,318.3
3,133.1
   
     
 
NATURAL GAS
TOTAL RESERVES
   
RESERVES CATEGORY
Gross
(MMcf)
Net
(MMcf)
Gross
(Mboe)
Net
(Mboe)
   
PROVED:
           
Developed Producing
68,234.4
57,240.4
49,303.6
40,360.7
   
Developed Non-Producing
11,780.3
  8,882.0
19,300.5
16,005.2
   
Undeveloped
  7,140.3
  5,632.8
54,655.3
45,930.8
   
TOTAL PROVED
      87,155.0      
71,755.2
 123,259.4   
  102,296.7   
   
PROBABLE
      41,044.5      
32,544.8
61,115.6
50,432.2
   
TOTAL PROVED PLUS PROBABLE
    128,199.5      
  104,300.0    
    184,375.0      
  152,728.9    
   
 
 
 
UNITED STATES
 
 
LIGHT AND MEDIUM OIL
HEAVY OIL
NATURAL GAS LIQUIDS
RESERVES CATEGORY
Gross
(Mbbl)
Net
(Mbbl)
Gross
(Mbbl)
Net
(Mbbl)
Gross
(Mbbl)
Net
(Mbbl)
PROVED:
           
Developed Producing
  1,494.0
1,214.3
-
-
-
-
Developed Non-Producing
           -
        -
-
-
-
-
Undeveloped
  4,213.1
3,458.9
-
-
-
-
TOTAL PROVED
  5,707.1
4,673.2
-
-
-
-
PROBABLE
  6,000.7
4,881.6
-
-
-
-
TOTAL PROVED PLUS PROBABLE
11,707.8
9,554.8
-
-
-
-
 
     
 
NATURAL GAS
TOTAL RESERVES
 
RESERVES CATEGORY
Gross
(MMcf)
Net
(MMcf)
Gross
(Mboe)
Net
(Mboe)
   
PROVED:
           
Developed Producing
   311.6
   253.5
1,545.9
1,256.6
   
Developed Non-Producing
-
-
-
-
   
Undeveloped
2,190.9
1,784.8
4,578.3
3,756.3
   
TOTAL PROVED
2,502.5
2,038.3
6,124.2
5,012.9
   
PROBABLE
3,045.2
2,470.6
6,508.2
5,293.4
   
TOTAL PROVED PLUS PROBABLE
5,547.7
4,508.9
12,632.4  
    10,306.3      
   
 
 
 
 

 
- 28 -
 
 
 
TOTAL
 
 
LIGHT AND MEDIUM OIL
HEAVY OIL
NATURAL GAS LIQUIDS
RESERVES CATEGORY
Gross
(Mbbl)
Net
(Mbbl)
Gross
(Mbbl)
Net
(Mbbl)
Gross
(Mbbl)
Net
(Mbbl)
PROVED:
           
Developed Producing
  6,078.2
  4,587.6
31,357.7
25,997.0
1,989.3
1,450.3
Developed Non-Producing
     487.4
     368.6
16,333.8
13,782.6
   515.9
   373.7
Undeveloped
  8,002.4
  6,272.5
49,363.0
41,952.9
   312.9
   225.5
TOTAL PROVED
14,568.0
11,228.7
97,054.5
81,732.5
2,818.1
2,049.5
PROBABLE
10,233.0
  7,846.4
48,542.3
40,959.7
1,500.2
1,083.6
TOTAL PROVED PLUS PROBABLE
24,801.0
19,075.1
    145,596.8      
   122,692.2     
4,318.3
3,133.1
   
     
 
NATURAL GAS
TOTAL RESERVES
   
RESERVES CATEGORY
Gross
(MMcf)
Net
(MMcf)
Gross
(Mboe)
Net
(Mboe)
   
PROVED:
           
Developed Producing
68,546.0
57,493.9
50,849.5
41,617.3
   
Developed Non-Producing
11,780.3
  8,882.0
19,300.5
16,005.2
   
Undeveloped
 9,331.2
  7,417.6
59,233.6
49,687.1
   
TOTAL PROVED
89,657.5
73,793.5
    129,383.6      
   107,309.6     
   
PROBABLE
44,089.7
35,014.4
67,623.8
55,725.6
   
TOTAL PROVED PLUS PROBABLE
133,747.2   
  108,808.9    
    197,007.4      
   163,035.2     
   

 
 

 
- 29 -
 
 
 
SUMMARY OF NET PRESENT VALUES OF FUTURE NET REVENUE
AS OF DECEMBER 31, 2009
FORECAST PRICES AND COSTS
CANADA
BEFORE INCOME TAXES DISCOUNTED AT (%/year)
RESERVES CATEGORY
0%
($000s)
5%
($000s)
10%
($000s)
15%
($000s)
20%
($000s)
PROVED:
         
Developed Producing
1,697,967
1,420,066
1,239,572
1,111,355
1,014,538
Developed Non-Producing
711,236
539,201
423,496
341,880
282,129
Undeveloped
1,913,199      
1,332,078      
982,376      
759,303      
607,675      
TOTAL PROVED
4,322,402
3,291,345
2,645,444
2,212,538
1,904,342
PROBABLE
2,175,593      
1,437,071      
1,037,388      
791,887      
628,486      
TOTAL PROVED PLUS PROBABLE
6,497,995      
4,728,416      
3,682,832      
3,004,425      
2,532,828      
           
UNITED STATES
 
RESERVES CATEGORY
         
PROVED:
         
Developed Producing
81,938
53,211
39,465
31,667
26,688
Developed Non-Producing
-
-
-
-
-
Undeveloped
205,350      
97,852      
50,284      
25,660      
11,420      
TOTAL PROVED
287,288
151,063
89,749
57,327
38,108
PROBABLE
420,363      
140,138      
60,386      
28,926      
13,403      
TOTAL PROVED PLUS PROBABLE
707,651      
291,201      
150,135      
86,253      
51,511      
           
TOTAL
 
RESERVES CATEGORY
         
PROVED:
         
Developed Producing
1,779,905
1,473,277
1,279,037
1,143,022
1,041,226
Developed Non-Producing
711,236
539,201
423,496
341,880
282,129
Undeveloped
2,118,549      
1,429,930      
1,032,660      
784,963      
619,095      
TOTAL PROVED
4,609,690
3,442,408
2,735,193
2,269,865
1,942,450
PROBABLE
2,595,956      
1,577,209      
1,097,774      
820,813      
641,889      
TOTAL PROVED PLUS PROBABLE
7,205,646      
5,019,617      
3,832,967      
3,090,678      
2,584,339      
 
 
 

 
- 30 -
 

 
 
SUMMARY OF NET PRESENT VALUES OF FUTURE NET REVENUE
AS OF DECEMBER 31, 2009
FORECAST PRICES AND COSTS
CANADA
AFTER INCOME TAXES DISCOUNTED AT (%/year)
RESERVES CATEGORY
0%
($000s)
5%
($000s)
10%
($000s)
15%
($000s)
20%
($000s)
PROVED:
         
Developed Producing
1,694,844
1,418,963
1,239,160
1,111,193
1,014,472
Developed Non-Producing
518,211
405,456
327,172
270,377
227,750
Undeveloped
1,395,954      
971,514      
713,403      
549,064      
437,859      
TOTAL PROVED
3,609,009
2,795,933
2,279,735
1,930,634
1,680,081
PROBABLE
1,612,560      
1,057,570      
760,701      
579,778      
460,111      
TOTAL PROVED PLUS PROBABLE
5,221,569      
3,853,503      
3,040,436      
2,510,412      
2,140,192      
           
UNITED STATES
 
RESERVES CATEGORY
         
PROVED:
         
Developed Producing
81,938
53,211
39,465
31,667
26,688
Developed Non-Producing
-
-
-
-
-
Undeveloped
154,745      
80,225      
43,450      
22,782      
10,124      
TOTAL PROVED
236,683
133,436
82,915
54,449
36,812
PROBABLE
244,771      
83,387      
36,626      
17,317      
7,180      
TOTAL PROVED PLUS PROBABLE
481,454      
216,823      
119,541      
71,766      
43,992      
           
TOTAL
 
RESERVES CATEGORY
         
PROVED:
         
Developed Producing
1,776,782
1,472,174
1,278,625
1,142,860
1,041,160
Developed Non-Producing
518,211
405,456
327,172
270,377
227,750
Undeveloped
1,550,699      
1,051,739      
756,853      
571,846      
447,983      
TOTAL PROVED
3,845,692
2,929,369
2,362,650
1,985,083
1,716,893
PROBABLE
1,857,331      
1,140,957      
797,327      
597,095      
467,291      
TOTAL PROVED PLUS PROBABLE
5,703,023      
4,070,326      
3,159,977      
2,582,178      
2,184,184      

 
TOTAL FUTURE NET REVENUE (UNDISCOUNTED)
AS OF DECEMBER 31, 2009
FORECAST PRICES AND COSTS
TOTAL PROVED
RESERVES
REVENUE
($000s)
ROYALTIES
($000s)
OPERAT-
ING
COSTS
($000s)
DEVELOP-
MENT
COSTS
($000s)
WELL
ABANDON-
MENT
COSTS
($000s)
FUTURE NET
REVENUE
BEFORE INCOME
TAXES
($000s)
INCOME
TAXES
($000s)
FUTURE NET
REVENUE
AFTER INCOME
TAXES
($000s)
Canada
    8,875,682
    1,407,196
2,450,816
538,340
156,928
         4,322,402
   713,392
           3,609,010
United States
      655,768
       201,997
     89,158
  77,325
           -
            287,288
     50,606
              236,682
Total
   9,531,450
    1,609,193
2,539,974
615,665
156,928
         4,609,690
   763,998
           3,845,692
TOTAL PROVED PLUS
PROBABLE RESERVES
               
Canada
 13,522,570
    2,167,032
3,926,742
738,303
192,496
         6,497,997
1,276,425
           5,221,572
United States
   1,522,810
       470,564
   212,227
132,369
           -
            707,650
   226,198
              481,452
Total
 15,045,380
    2,637,596
4,138,969
870,672
192,496
         7,205,647
1,502,623
           5,703,024
 

 
 

 
- 31 -
 


 
FUTURE NET REVENUE BY PRODUCTION GROUP
AS OF DECEMBER 31, 2009
FORECAST PRICES AND COSTS
 
RESERVES
CATEGORY
PRODUCTION GROUP
FUTURE NET REVENUE
BEFORE INCOME TAXES
(discounted at 10%/year)
($000s)
 
 
UNIT VALUE
($/boe) (1)
       
CANADA
     
       
Proved
Light and Medium Crude Oil (including solution gas and other
   by-products)
   194,223
26.52
 
Heavy Oil (including solution gas and other by-products)
2,170,804
26.46
 
Natural Gas (including by-products but excluding natural gas
   from oil wells)
   280,417
21.66
 
 
Total Canada
 
2,645,444
 
       
Proved plus Probable
Light and Medium Crude Oil (including solution gas and other
   by-products)
   275,270
25.83
 
Heavy Oil (including solution gas and other by-products)
3,008,370
24.44
 
Natural Gas (including by-products but excluding natural gas
   from oil wells)
   399,192
21.06
 
 
Total Canada
 
 3,682,832
 
       
UNITED STATES
     
       
Proved
Light and Medium Crude Oil (including solution gas and other
   by-products)
     89,749
17.90
 
Heavy Oil (including solution gas and other by-products)
-
-
 
Natural Gas (including by-products but excluding natural gas
   from oil wells)
-
-
 
Total United States
 
      89,749
 
       
Proved plus Probable
Light and Medium Crude Oil (including solution gas and other
   by-products)
      150,135  
14.57
 
Heavy Oil (including solution gas and other by-products)
-
-
 
Natural Gas (including by-products but excluding natural gas
   from oil wells)
-
-
 
Total United States
 
     150,135
 
       
TOTAL
     
       
Proved
Light and Medium Crude Oil (including solution gas and other
   by-products)
   283,972
23.02
 
Heavy Oil (including solution gas and other by-products)
2,170,804
26.46
 
Natural Gas (including by-products but excluding natural gas
   from oil wells)
   280,417
21.66
 
 
Total
 
 2,735,193
 
       
Proved plus Probable
Light and Medium Crude Oil (including solution gas and other
   by-products)
   425,406
20.29
 
Heavy Oil (including solution gas and other by-products)
3,008,370
24.44
 
Natural Gas (including by-products but excluding natural gas
   from oil wells)
   399,192
21.06
 
 
Total
 
3,832,968
 
 
Note:
 
(1)           Unit values are based on net reserve volumes.
 
 
 

 
- 32 -
 
 
Definitions and Notes to Reserves Data Tables
 
In the tables set forth above under the subheading "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.
 
(c)  
"Economic Assumptions" will be the forecast prices and costs used in the estimate.
 
        Development and Production Status
 
Each of the reserve categories (proved and probable) may be divided into developed and undeveloped categories:
 
 

 
- 33 -
 
 
               
(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.
 
4.  
"Exploratory well" means a well that is not a development well, a service well or a stratigraphic test well.
 
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;
 
 
 

 
- 34 -
 
 
(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.
 
9.  
"Forecast Prices and Costs"
 
These are prices and costs that are:
 
(a)  
generally acceptable as being a reasonable outlook of the future; and
 
(b)  
if and only to the extent that, there are fixed or presently determinable future prices or costs to which Baytex is legally bound by a contractual or other obligation to supply a physical product, including those for an extension period of a contract that is likely to be extended, those prices or costs rather than the prices and costs referred to in paragraph (a).
 
10.  
Numbers may not add due to rounding.
 
11.  
The estimates of future net revenue presented in the tables above do not represent fair market value.
 
12.  
This year we have reported the estimates of our bitumen reserves with our heavy oil reserves.  As the volume of bitumen reserves is relatively small compared to our volume of heavy oil reserves, this inclusion is permitted under NI 51-101 and the COGE Handbook.  This reporting is consistent in all of the reserves disclosure in this Annual Information Form.
 

 
 

 
- 35 -
 
 
 
As of December 31, 2009, Sproule attributed gross probable undeveloped bitumen reserves of 8,196.3 Mbbl to our permanent steam project at Seal, Alberta.  By comparison, as of December 31, 2008, Sproule attributed gross probable undeveloped bitumen reserves of 2,463.7 Mbbl to our permanent steam project at Seal, Alberta.  Sproule did not attribute any other bitumen reserves in any other category or any other area this year or last.  After deducting the volumes of probable undeveloped bitumen reserves, Sproule's estimates of our total proved plus probable heavy oil reserves were 137,400.5 Mbbl as of December 31, 2009, and 123,589.8 Mbbl as of December 31, 2008.
 
13.  
On March 11, 2010, the Alberta government announced changes to Alberta's royalty system intended to increase Alberta's competitiveness in the oil and natural gas industry, which included a decrease in the maximum royalty rates for conventional oil and natural gas production effective for the January 2011 production month and certain temporary incentive programs currently in place being made permanent.  See "Industry Conditions".  Further details with respect to the changes to Alberta's royalty system are expected to be provided in the coming months.  Reserves and net present values reflected in the above tables do notreflect the potential effect of these new changes to Alberta's royalty system and no sensitivities were provided by Sproule as to the potential impact of same.

Pricing Assumptions
 
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, 2009, inflation and exchange rates utilized in the Sproule Report were as follows:
 
SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS
FORECAST PRICES AND COSTS AS AT DECEMBER 31, 2009
 
OIL
NATURAL GAS
INFLATION
RATES (1)
%/year
EXCHANGE
RATE (2)
($US/$Cdn)
WTI
Cushing
Oklahoma
($US/bbl)
Edmonton
Par Price 40°
API
($Cdn/bbl)
Hardisty
Heavy
12° API
($Cdn/bbl)
AECO-C
($Cdn/MMbtu)
Historical
           
             
2005
56.46
69.29
34.35
8.58
1.3
0.826
2006
66.09
73.30
43.32
7.16
1.5
0.882
2007
72.27
77.06
44.77
6.65
2.0
0.935
2008
99.59
102.85
76.32
8.15
1.0
0.943
2009 Est.
61.63
66.20
55.59
4.19
2.0
0.880
Forecast
           
2010
79.17
84.25
69.93
5.36
2.0
0.920
2011
84.46
89.99
73.79
6.21
2.0
0.920
2012
86.89
92.61
74.08
6.44
2.0
0.920
2013
90.20
96.19
75.03
7.23
2.0
0.920
2014
92.01
98.13
74.58
7.98
2.0
0.920
             
Thereafter.
Various escalation rates
 
 Notes:
(1)           Inflation rates for forecasting prices and costs.
(2)           Exchange rate used to generate the benchmark reference prices in this table.

Weighted average prices realized by us for the year ended December 31, 2009, excluding hedging activities, were $4.35/Mcf for natural gas, $54.25/bbl for light oil and NGL and $49.88/bbl for heavy oil.

 
 

 
- 36 -
 
 

RECONCILIATION OF
GROSS RESERVES
BY PRINCIPAL PRODUCT TYPE
FORECAST PRICES AND COSTS
 
 
LIGHT AND MEDIUM OIL
HEAVY OIL
CANADA
Proved
(Mbbl)
Probable
(Mbbl)
Proved Plus
Probable
(Mbbl)
Proved
(Mbbl)
Probable
(Mbbl)
Proved Plus
Probable
(Mbbl)
December 31, 2008
11,081.9
5,461.8
16,543.7
86,936.9
39,116.6
126,053.5
Extensions
37.9
155.5
193.4
7,553.6
6,138.3
13,691.9
Improved Recovery
914.0
506.9
1,420.9
6,412.0
4,666.7
11,078.7
Technical Revisions
(1,742.4)
(2,020.4)
(3,762.8)
(120.5)
(2,740.6)
(2,861.1)
Discoveries
83.3
103.6
186.9
83.9
32.0
115.9
Acquisitions
85.4
21.4
106.8
5,122.0
1,348.4
6,470.4
Dispositions
-
-
-
(6.6)
(5.8)
(12.4)
Economic Factors
19.9
3.5
23.4
80.6
(13.3)
67.3
Production
(1,619.1)
-
(1,619.1)
(9,007.5)
-
(9007.5)
December 31, 2009
8,860.9
4,232.3
13,093.2
97,054.4
48,542.3
145,596.7
 
 

 
ASSOCIATED, NON-ASSOCIATED
AND SOLUTION GAS
NATURAL GAS LIQUIDS
CANADA
Proved
(MMcf)
Probable
(MMcf)
Proved Plus
Probable
(MMcf)
Proved
(Mbbl)
Probable
(Mbbl)
Proved Plus
Probable
(Mbbl)
December 31, 2008
117,960.0
55,016.0
172,976.0
3,725.5
1,846.3
5,571.8
Extensions
36.0
2,021.0
2,057.0
1.2
77.8
79.0
Improved Recovery
1,329.0
920.0
2,249.0
37.3
33.5
70.8
Technical Revisions
(14,456.0)
(18,873.0)
(33,329.0)
(281.8)
(509.7)
(791.5)
Discoveries
795.0
405.0
1,200.0
32.9
16.4
49.3
Acquisitions
5,599.0
1,817.0
7,416.0
114.5
33.2
147.7
Dispositions
(169.0)
(43.0)
(212.0)
-
-
-
Economic Factors
(2,686.0)
(218.0)
(2,904.0)
(43.2)
2.8
(40.4)
Production
(21,252.0)
-
(21,252.0)
(768.3)
-
(768.3)
December 31, 2009
87,156.0
41,045.0
128,201.0
2,818.1
1,500.3
4,318.4

 
 
OIL EQUIVALENT
CANADA
Proved
(Mboe)
Probable
(Mboe)
Proved Plus
Probable
(Mboe)
December 31, 2008
121,404.4
55,594.0
176,998.4
Extensions
7,598.7
6,708.4
14,307.1
Improved Recovery
7,584.8
5,360.4
12,945.2
Technical Revisions
(4,554.0)
(8,416.2)
(12,970.2)
Discoveries
332.6
219.5
552.1
Acquisitions
6,255.1
1,705.9
7,961.0
Dispositions
(34.8)
(13.0)
(47.8)
Economic Factors
(390.4)
(43.3)
(433.7)
Production
(14,936.9)
-
(14,936.9)
December 31, 2009
123,259.5
61,115.7
184,375.2
 
 
 

 
- 37 -
 

 
LIGHT AND MEDIUM OIL
ASSOCIATED, NON-ASSOCIATED
AND SOLUTION GAS
UNITED STATES
Proved
(Mbbl)
Probable
(Mbbl)
Proved Plus
Probable
(Mbbl)
Proved
(MMcf)
Probable
(MMcf)
Proved Plus
Probable
(MMcf)
December 31, 2008
3,947.6
5,322.0
9,269.6
2,016.0
3,210.0
5,226.0
Extensions
1,022.1
1,904.7
2,926.8
399.0
979.0
1,378.0
Improved Recovery
-
-
-
-
-
-
Technical Revisions
880.7
(1,232.4)
(351.7)
111.0
(1,144.0)
(1,033.0)
Discoveries
-
-
-
-
-
-
Acquisitions
2.7
5.0
7.7
-
-
-
Dispositions
-
-
-
-
-
-
Economic Factors
(1.6)
1.4
(0.2)
-
-
-
Production
(144.4)
-
(144.4)
(23.0)
-
(23.0)
December 31, 2009
5,707.1
6,000.7
11,707.8
2,503.0
3,045.0
5,548.0

 
 
OIL EQUIVALENT
UNITED STATES
Proved
(Mboe)
Probable
(Mboe)
Proved Plus
Probable
(Mboe)
December 31, 2008
4,283.6
5,857.0
10,140.6
Extensions
1,088.6
2,067.9
3,156.5
Improved Recovery
-
-
-
Technical Revisions
899.2
(1,423.1)
(523.9)
Discoveries
-
-
-
Acquisitions
2.7
5.0
7.7
Dispositions
-
-
-
Economic Factors
(1.6)
1.4
(0.2)
Production
(148.2)
-
(148.2)
December 31, 2009
6,124.3
6,508.2
12,632.5

 
 
 
LIGHT AND MEDIUM OIL
HEAVY OIL
TOTAL
Proved
(Mbbl)
Probable
(Mbbl)
Proved Plus
Probable
(Mbbl)
Proved
(Mbbl)
Probable
(Mbbl)
Proved Plus
Probable
(Mbbl)
December 31, 2008
15,029.5
10,783.8
25,813.3
86,936.9
39,116.6
126,053.5
Extensions
1,060.0
2,060.2
3,120.2
7,553.6
6,138.3
13,691.9
Improved Recovery
914.0
506.9
1,420.9
6,412.0
4,666.7
11,078.7
Technical Revisions
(861.7)
(3,252.8)
(4,114.5)
(120.5)
(2,740.6)
(2,861.1)
Discoveries
83.3
103.6
186.9
83.9
32.0
115.9
Acquisitions
88.1
26.4
114.5
5,122.0
1,348.4
6,470.4
Dispositions
-
-
-
(6.6)
(5.8)
(12.4)
Economic Factors
18.3
4.9
23.2
80.6
(13.3)
67.3
Production
(1,763.5)
-
(1,763.5)
(9,007.5)
-
(9,007.5)
December 31, 2009
14,568.0
10,233.0
24,801.0
97,054.4
48,542.3
145,596.7
 
 
 

 
- 38 -
 
 
 
 
ASSOCIATED, NON-ASSOCIATED
AND SOLUTION GAS
NATURAL GAS LIQUIDS
TOTAL
Proved
(MMcf)
Probable
(MMcf)
Proved Plus
Probable
(MMcf)
Proved
(MMcf)
Probable
(MMcf)
Proved Plus
Probable
(MMcf)
December 31, 2008
119,976.0
58,226.0
178,202.0
3,725.5
1,846.3
5,571.8
Extensions
435.0
3,000.0
3,435.0
1.2
77.8
79.0
Improved Recovery
1,329.0
920.0
2,249.0
37.3
33.5
70.8
Technical Revisions
(14,345.0)
(20,017.0)
(34,362.0)
(281.8)
(509.7)
(791.5)
Discoveries
795.0
405.0
1,200.0
32.9
16.4
49.3
Acquisitions
5,599.0
1,817.0
7,416.0
114.5
33.2
147.7
Dispositions
(169.0)
(43.0)
(212.0)
-
-
-
Economic Factors
(2,686.0)
(218.0)
(2,904.0)
(43.2)
2.8
(40.4)
Production
(21,275.0)
-
(21,275.0)
(768.3)
-
(768.3)
December 31, 2009
89,659.0
44,090.0
133,749.0
2,818.1
1,500.3
4,318.4

 
 
OIL EQUIVALENT
TOTAL
Proved
(Mboe)
Probable
(Mboe)
Proved Plus
Probable
(Mboe)
December 31, 2008
125,688.0
61,451.0
187,139.0
Extensions
8,687.3
8,776.3
17,463.6
Improved Recovery
7,584.8
5,360.4
12,945.2
Technical Revisions
(3,654.8)
(9,839.3)
(13,494.1)
Discoveries
332.6
219.5
552.1
Acquisitions
6,257.8
1,710.9
7,968.7
Dispositions
(34.8)
(13.0)
(47.8)
Economic Factors
(392.0)
(41.9)
(433.9)
Production
(15,085.1)
-
(15,085.1)
December 31, 2009
129,383.8
67,623.9
197,007.7

Additional Information Relating to Reserves Data
 
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.
 
Approximately 50 to 60 percent of our expected funds from operations are available for capital expenditures related to exploration and development activities and the balance is distributed to our Unitholders. We allocate development capital to our assets in an efficient and disciplined process. We reduce risk by technically assessing the results of each of our development programs before committing additional capital. This disciplined approach to investing in development means that in most 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 reserves and probable undeveloped reserves over the next six years.
 
Our capital spending on development projects is budgeted annually for each of our business units. Once a development program is executed, we measure and analyze the results of that capital investment, make any changes to the program that are necessary, and then repeat the process until all economic oil and gas reserves are developed. There are a number of factors that could result in delayed or cancelled development, including the following: (i) changing economic conditions (due to pricing, operating and capital expenditure fluctuations); (ii) changing technical conditions (including production anomalies, such as water breakthrough or accelerated depletion); (iii) multi-zone developments (for instance, a prospective formation completion may be delayed until the initial completion is no longer economic); (iv) a larger development program may need to be spread out over several years
 
 
 

 
- 39 -
 
 
to optimize capital allocation and facility utilization; and (v) surface access issues (including those relating to land owners, weather conditions and regulatory approvals). For more information, see "Risk Factors".
 
Proved Undeveloped Reserves
 
The following table discloses, for each product type, the volumes of proved undeveloped reserves that were attributed in each of the most recent three financial years and, in the aggregate, before that time.
 
 
Light and Medium Oil
 Gross (Mbbl)
Heavy Oil
 Gross (Mbbl)
NGLs
 Gross (Mbbl)
Natural Gas
Gross (MMcf)
 
Year
First
Attributed
Booked at
Year End
First
Attributed
Booked at
Year End
First
Attributed
Booked at
Year End
First
Attributed
Booked at
Year End
Prior
1,966.6
4,921.8
36,545.6
78,705.9
832.9
1,629.6
20,069.1
44,292.8
 
2007
2,112.0
3,574.1
9,833.3
38,168.8
55.6
378.4
2,559.0
15,587.0
 
2008
2,830.6
6,234.1
2,175.9
37,584.1
37.3
375.4
3,234.0
15,446.0
 
2009
1,874.4
8,002.4
18,084.9
49,363.0
106.1
312.9
3,123.0
9,331.0
 
 
Sproule assigned a total of 482 well locations to the proved undeveloped reserve category, of which 394 are located on our Canadian heavy oil producing properties. The 394 heavy oil proved undeveloped locations are scheduled to be drilled over the next six years. Sixty-nine of the total proved undeveloped locations are within our Canadian conventional oil and gas producing properties. These conventional oil and gas well locations are scheduled to be drilled over the next five years. The remaining 19 proved undeveloped wells are located in the United States within Divide County, North Dakota. This is a conventional, light oil development project area for Baytex. The wells in North Dakota are scheduled to be drilled over the next four years.
 
It would not be prudent from both a financial and technical perspective for us to develop all of our proved undeveloped reserves over the next two years. Our operating budget allocates between 50 to 60 percent of expected funds from operations to exploration and development activities.  This restricts the number of development wells we drill in any given year to approximately 90 net wells based on 2009 spending and activity levels. Not all of the development wells that we drill in any given year are contained within the Sproule defined proved undeveloped inventory. At our current pace of investment and drilling it will take approximately six years to develop all the currently identified proved undeveloped reserves in the Sproule Report.
 
Probable Undeveloped Reserves
 
The following table discloses, for each product type, the volumes of probable undeveloped reserves that were first attributed in each of the most recent three financial years and, in the aggregate, before that time.
 
 
Light and Medium Oil
 Gross (Mbbl)
Heavy Oil
 Gross (Mbbl)
NGLs
 Gross (Mbbl)
Natural Gas
 Gross (MMcf)
 
Year
First
Attributed
Booked at
Year End
First
Attributed
Booked at
Year End
First
Attributed
Booked at
Year End
First
Attributed
Booked at
Year End
Prior
694.9
1,721.6
19,117.0
42,565.2
671.2
972.4
14,150.0
26,529.1
 
2007
1,040.8
1,557.5
3,804.1
20,410.1
513.3
615.7
5,476.0
10,832.0
 
2008
5,179.3
6,404.7
7,296.9
23,098.4
76.3
362.2
5,467.0
13,587.0
 
2009
3,457.1
7,518.2
19,426.4
31,494.5
135.4
368.2
4,444.0
11,210.0
 
 
Sproule assigned a total of 176 well locations to the probable undeveloped reserve category, of which 149 are located within our Canadian primary heavy oil producing properties. The majority of these 149 heavy oil locations are scheduled to be drilled over the next six years. Forty of these probable undeveloped locations are thermal heavy oil wells located in the Seal area of Alberta. Sproule has scheduled these thermal wells to be drilled by the end of 2014. Thirteen of these probable undeveloped locations are located on our Canadian conventional oil and gas producing properties. These conventional oil and gas locations are scheduled to be drilled over the next five years. The remaining 14 probable undeveloped wells are located in the United States within Divide County, North Dakota.
 
 
 
 

 
- 40 -
 
 
This is a conventional light oil development project area for Baytex. These wells in North Dakota are scheduled to be drilled over the next four years.
 
For the same reasons given above, we will not develop all of our probable undeveloped reserves over the next two years. Our operating budget allocates between 50 to 60 percent of our expected funds from operations to exploration and development activities.  This restricts the number of development wells we drill in any given year to approximately 90 net wells based on 2009 spending and activity levels. Not all of the development wells that we drill in any given year are contained within the Sproule defined proved undeveloped or probable undeveloped inventory. At our current pace of investment and drilling it will take approximately six years to develop all the currently identified probable undeveloped reserves.
 
Significant Factors or Uncertainties
 
We have a significant amount of proved non-producing and proved undeveloped reserves assigned to our Canadian heavy oil properties located in the Province of Saskatchewan and at our Seal, Ardmore and Cold Lake heavy oil properties located in the Province of Alberta. Our conventional light oil and gas properties in Stoddart, British Columbia, the Pembina and Ferrier areas of Alberta and Divide County, North Dakota, USA also contain a significant quantity of proved non-producing and proved undeveloped reserves. 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. In addition, reserves can be affected significantly by fluctuations in capital expenditures, operating costs, royalty regimes, and well performance that are beyond our control and which could impact our development decisions. See also "Risk Factors".
 
 Future Development Costs
 
The following table sets forth development costs deducted in the estimation of the future net revenue attributable to the reserve categories noted below.
 
 
FORECAST PRICES AND COSTS
YEAR
Proved Reserves
($000s)
Proved Plus Probable Reserves
($000s)
   
 
CANADA
2010
83,661
94,114
2011
126,873
147,839
2012
115,573
141,981
2013
50,644
91,565
2014
36,916
93,289
Remaining
124,673
169,515
Total (Undiscounted)
538,340
738,303
   
 
UNITED STATES
2010
18,822
31,122
2011
35,439
65,018
2012
18,695
28,691
2013
4,369
7,538
2014
-
-
Remaining
-
-
Total (Undiscounted)
77,325
132,369
   
 
TOTAL
2010
102,483
125,236
2011
162,312
212,857
2012
134,268
170,672
2013
55,013
99,103
2014
36,916
93,289
Remaining
124,673
169,515
Total (Undiscounted)
615,665
870,672

 
 

 
- 41 -
 
 
We expect to fund the development costs of our reserves through a combination of internally generated cash flow, debt and equity financings. Our operating budget allocates between 50 to 60 percent of our expected funds from operations to exploration and development activities.
 
There can be no guarantee that funds will be available or that our Board of Directors will allocate funding to develop all of the reserves attributed in the Sproule Report. Failure to develop those reserves could 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 set forth herein 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 of these properties 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, 2009. Unless otherwise specified, gross and net acres and well count information are as at December 31, 2009. Well counts indicate gross wells, except where otherwise indicated. Production information represents average working interest production, for the year ended December 31, 2009, except where otherwise indicated.
 
Our crude oil and natural gas operations are organized into Canadian Heavy Oil, Canadian Light Oil and Gas and United States business units. Each business unit has a portfolio of operated properties and development prospects with upside potential. Within these business units, Baytex has established a total of eight 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.
 
Baytex invested approximately $103 million in undeveloped land over the past two years targeting three light oil resource plays.  These plays include the Bakken/Three Forks in the Williston Basin of North Dakota, the Viking in southwestern Saskatchewan and eastern Alberta and a Mowry Shale exploratory play in the Powder River Basin of eastern Wyoming. These light oil resource plays provide the opportunity for long term light oil production and reserve growth to complement our heavy oil growth projects. These resource plays are described in more detail in the business unit descriptions below.
 
 
 

 
- 42 -
 
 
The map below highlights the geographic location of our principal properties.
 
Baytex Energy Trust – Principal Properties
 
 
 
 
 
Canadian Heavy Oil Business Unit
 
The Canadian Heavy Oil Business Unit accounts for more than 60% of current production and more than 70% of oil-equivalent reserves. 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 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 500 bbl/d of crude with gravities ranging from 11 to 18 degrees API. Once produced, the oil is trucked or pipelined to markets in both Canada and the United States. Heavy crude is usually blended with light-hydrocarbon diluents (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 diluents.
 
In 2009, production in the Canadian Heavy Oil Business Unit averaged approximately 25,913 boe/d, which was comprised of 24,678 bbl/d of heavy oil and 7,409 Mcf/d of natural gas. During 2009, Baytex drilled 90 (82.3 net) wells in the Canadian Heavy Oil Business Unit resulting in 83 (76.3 net) oil wells, 2 (2.0 net) stratigraphic test wells, 2 (1.0 net) service wells, and 3 (3.0 net) dry and abandoned wells, for a success rate of 97% (96% net).
 
 
 

 
- 43 -
 
 
The Canadian Heavy Oil Business Unit possesses a large inventory of development projects within the operating areas of west-central Saskatchewan and Cold Lake/Ardmore and Peace River in Alberta. Baytex's ability to generate relatively low-cost replacement production through conventional cold production methods is key to maintaining our overall production rate. Due to the size of inventory of heavy oil projects, we are able to select from a wide range of investment opportunities to maintain heavy oil production rates.
 
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 historical area of emphasis around Lloydminster. Our net undeveloped lands in the Canadian Heavy Oil Business Unit totalled approximately 382,000 acres at year-end 2009.
 
Listed below is a brief description of the principal properties within the Canadian Heavy Oil Business Unit:
 
Ardmore, Alberta:  Acquired in 2002, this property has since been extensively developed in the Sparky, McLaren and Colony formations. Average production during 2009 was approximately 1,012 bbl/d of oil and 374 Mcf/d of natural gas (1,074 boe/d). Two successful oil wells were drilled in the area during 2009. Baytex anticipates drilling one well in this area in 2010. Net undeveloped lands were 39,000 acres at year-end 2009.
 
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. Five new wells were drilled in 2009 which, combined with relatively low production declines due mostly to strong performance of the ongoing waterflood, led to a year-over-year production increase. The waterflood was expanded in 2009 and Baytex plans to further expand the waterflood area in 2010. We plan to drill 16 wells in the Carruthers area in 2010. Average production in 2009 was approximately 2,164 bbl/d of heavy oil and 583 Mcf/d of natural gas (2,261 boe/d). Net undeveloped lands were 12,600 acres at year-end 2009.
 
Celtic, Saskatchewan: This producing property was acquired in October 2005, in a transaction where Baytex purchased cold heavy oil production of 1,600 bbl/d and natural gas production of 900 Mcf/d. As a result of Baytex's well re-completion and drilling activities, production averaged 4,326 bbl/d of heavy oil and 878 Mcf/d of natural gas (4,472 boe/d) during 2009. Celtic is a key asset for Baytex because, like the adjacent Tangleflags property, it contains a large resource base with multiple prospective horizons. As a result, the Celtic property provides a multi-year inventory of drilling locations and re-completion opportunities. 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 2010, Baytex expects to drill 7 new wells and re-complete approximately 20 existing wells. Net undeveloped lands were 8,700 acres at year-end 2009.
 
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 2009 was approximately 476 bbl/d. Baytex drilled five successful oil wells in the Cold Lake area in 2009, and we plan to drill one new well in the area in 2010. Net undeveloped lands were 13,600 acres at year-end 2009.
 
Dodsland, Saskatchewan:  During 2008, Baytex developed a new resource play in the Viking sand in southwest Saskatchewan. The zone is regionally charged with light (34 degrees API) oil, and in its more permeable areas, has been a prolific oil horizon since the 1960s. Baytex targeted the less permeable but undeveloped areas of the play and drilled a 1,400 metre horizontal well in 2008. The horizontal well was completed with 7 fracture stimulations, applying the same multi-zone fracture technology that is used to stimulate horizontal wells in the Bakken oil play in southeast Saskatchewan and North Dakota. Production performance from the first Dodsland Viking well was encouraging and Baytex intends to drill several additional horizontal Viking tests in 2010.  At year-end 2009, Baytex had leased 34,500 net acres in the play. Ultimately, more than 150 wells may be drilled on these lands.
 
Kerrobert/Coleville, Saskatchewan: Baytex acquired assets in the Kerrobert and Coleville areas of Saskatchewan on July 30, 2009. The acquisition provides numerous opportunities for cold infill drilling and steam-assisted gravity drainage (SAGD) optimization. In addition, the Kerrobert area offers significant potential for light oil development in the Viking formation using horizontal wells with multi-stage hydraulic fractures, similar to the Dodsland Viking opportunities described above. Baytex also holds a 50% non-operated interest in a pilot project in the Kerrobert area using toe-to-heel air injection in horizontal wells. At the time of the acquisition, the acquired assets produced
 
 
 

 
- 44 -
 
 
approximately 3,000 boe/d. Baytex drilled two (1.0 net) oil wells and two (1.0 net) service wells in this area in 2009, and performed workovers on several wells. Baytex plans to drill 9 wells in this area in 2010. Net undeveloped lands were 50,135 acres at year-and 2009.
 
Lindbergh, Alberta: Lindbergh is a primarily non-operated heavy oil property that was purchased in June 2007. Baytex has a 21.25% working interest in this property, which is operated by a senior Canadian producer.  Average production in this area during 2009 was approximately 577 bbl/d of heavy oil. Like Tangleflags and Celtic, Lindbergh is a multi-zone property that is expected to provide future development projects for many years. Thus far, economic production has been obtained from the Dina, Cummings, General Petroleum, Sparky and Colony formations. Seven (1.5 net) wells were drilled in this area in 2009. Net undeveloped lands were 1,400 acres at year-end 2009.
 
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 degrees API. Initial per well production rates are typically 40 to 70 bbl/d. Primary recovery factors can be as high as 30% 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 production in this area during 2009 was approximately 3,270 bbl/d of oil and 409 Mcf/d of natural gas (3,338 boe/d). Seven (7.0 net) successful oil wells and two (2.0 net) dry holes were drilled in this region in 2009. For 2010, a further 10 wells are planned. Net undeveloped lands were 24,000 acres at year-end 2009.
 
Seal, Alberta:  Seal is a highly prospective property located in the Peace River oil sands area of northern Alberta. Baytex holds a 100% working interest in 105 sections of long-term oil sands leases. In certain parts of this land base, heavy oil can be produced using horizontal wells at initial production rates of 150 to 500 bbl/d per well, without employing more cost-intensive methods such as steam injection. In 2009, Baytex drilled two stratigraphic test wells, designed to identify extensions to our current development areas. Baytex also drilled 17 horizontal production wells in 2009, bringing the total number of producing wells to 61. The average production rate during 2009 was 5,095 bbl/d of heavy oil. Reservoir analysis of the Seal property has indicated that both waterflood and cyclic steam recovery methods have the potential to increase economic oil reserves beyond what is achievable with cold primary recovery. A cyclic steam pilot project was carried out on an existing horizontal producer during 2008 to validate the numerical reservoir simulation models. Based on our successful pilot, we are conducting the remaining design activities and reservoir modeling to install a permanent steam project, with start-up targeted for late 2011. As the region continues to develop, the Seal property will take an increasingly more prominent role in our production profile. During 2010, Baytex plans to drill six stratigraphic test wells, 20 cold horizontal production wells, and we intend to re-enter several existing single-leg horizontal wells and drill additional legs at closer inter-well spacing to increase recovery from these older wells. Net undeveloped lands were 63,000 acres at year-end 2009.
 
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. In 2009, Baytex drilled 8 (8.0 net) wells in the area. We plan to drill approximately 17 wells in the area in 2010. Average production during 2009 was approximately 2,062 bbl/d of heavy oil and 683 Mcf/d of natural gas (2,176 boe/d). Net undeveloped lands were 7,800 acres at year-end 2009.
 
Canadian Light Oil and Gas Business Unit
 
Although Baytex is best known as a "heavy oil" energy trust, we also possess a growing array of light oil and natural gas properties. In addition to Baytex's historical light oil and natural gas properties in northern and south-eastern Alberta, the geographic scope of our conventional oil and gas operations has expanded to central Alberta and northeast British Columbia, providing exposure to some of the most prospective areas in Western Canada.
 
The Canadian Light Oil and Gas Business Unit produces light and medium gravity crude oil, natural gas and natural gas liquids from various fields in Alberta and British Columbia. During 2009, production from this business unit averaged 15,063 boe/d, which was comprised of 51.1 MMcf/d of natural gas sales and 6,540 bbl/d of light oil and NGL. During 2009, the Canadian Light Oil and Gas Business Unit drilled 16 (14.5 net) wells resulting in 5 (3.5 net) gas wells, 10 (10.0 net) oil wells, and 1 (1.0 net) dry hole for a success rate of 94% (93% net). Our net undeveloped lands in this business unit were approximately 289,000 acres at year-end 2009.
 
 
 

 
- 45 -
 
 
Listed below is a brief description of the principal properties within the Canadian Light Oil and Gas Business Unit:
 
Bon Accord, Alberta:  This multi-zone property was acquired by Baytex in 1997. Production is obtained from the Belly River, Viking and Mannville formations. During 2009, production for the area averaged approximately 2,073 Mcf/d of gas and 304 bbl/d of light oil (650 boe/d). Natural gas is processed at two Baytex-operated plants and oil is treated at three Baytex-operated batteries. In the past two years, Baytex has worked to exploit the Viking sand utilizing horizontal drilling technology. During 2009, Baytex drilled three (3.0 net) horizontal Viking oil wells in this area, and we plan to drill up to six horizontal Viking oil wells in the area in 2010. At year-end 2009, Baytex had 8,700 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 Baytex-operated gas plants. Production during 2009 averaged approximately 1,844 Mcf/d of gas (307 boe/d). At year-end 2009, Baytex had 13,400 net undeveloped acres in this area.
 
Leahurst, Alberta:  Production averaged approximately 3,705 Mcf/d of gas and 13 bbl/d of NGL (631 boe/d) during 2009 from this multi-zone, year-round access area. Natural gas production from the Edmonton, Belly River, Viking and Mannville formations is processed at several plants, one of which is Baytex-operated. During 2009, Baytex drilled one (1.0 net) dry hole in the area. At year-end 2009, Baytex had 8,300 net undeveloped acres in this area.
 
Pembina, Alberta:  Baytex acquired its initial position in Pembina in June 2007 and further expanded its presence in the area through the acquisition of Burmis in June 2008.  Production is primarily from the Nisku formation and to a lesser extent from Cretaceous and Jurassic age formations including the Ellerslie, Glauconite, Notikewin, Rock Creek and Nordegg. The majority of Baytex's production in this area is treated at a Baytex-operated oil battery with the remaining production treated at two third-party oil batteries. Gas production is delivered to a combination of four mid-stream gas processing facilities and two producer-operated gas processing facilities. Baytex owns a working interest in one of the producer-operated gas processing facilities and a minor working interest in one of the mid-stream gas processing facilities. During 2009, Pembina production averaged 3,547 bbl/d of light oil and NGL and 21,170 Mcf/d of gas (7,075 boe/d). Baytex participated in drilling 6 (5.7 net) operated and 2 (0.8 net) non-operated locations in 2009. Two wells (2.0 net) were drilled to test Nisku prospects, resulting in 2 (2.0 net) oil wells. Four (2.5 net) wells were drilled for development of multi-zone potential in the Cretaceous in 2009, resulting in 4 (2.5 net) gas wells. Two Cardium horizontal wells (2.0 net) were successfully drilled and completed with multi-stage fracture stimulations resulting in 2 (2.0 net) oil wells. During the first quarter of 2009, Baytex constructed a pipeline in the O'Chiese area which facilitated an increase in gas production and improved netback prices. The 2010 drilling program for Pembina is planned to include up to five additional Cardium oil tests, two wells to evaluate Nisku prospects, and four wells for multi-zone Cretaceous potential.  At year-end 2009, Baytex had 28,000 net undeveloped acres in this area.
 
Richdale/Sedalia, Alberta:  Baytex acquired its initial position in this area in 2001, and significantly increased its presence with a 2004 acquisition of a private company. During 2009, production averaged approximately 5,400 Mcf/d of sales gas and 11 bbl/d of NGL (911 boe/d). This area has year-round access and multi-zone potential in the Second White Specks, Viking and Mannville formations. Most of the gas produced from this area is processed at two Baytex-operated gas plants. During 2009, Baytex drilled 1 (1.0 net) successful gas well in this area. At year-end 2009, Baytex had 27,500 net undeveloped acres in this area.
 
Red Earth/Goodfish/Lafond, 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 Baytex-operated sweet oil batteries. Natural gas production from the Bluesky formation is handled at two gas plants, one of which is Baytex-operated. Production from this area during 2009 averaged approximately 3,191 Mcf/d of gas and 703 bbl/d of light oil and NGL (1,235 boe/d). Baytex did not drill any wells in this area in 2009, but we plan to drill one well in the area in 2010. At year-end 2009, Baytex had 28,200 net undeveloped acres in this area.
 
Stoddart, British Columbia:  The Stoddart asset acquisition was completed in December 2004. Oil and liquids-rich gas production in this largely year-round-access area comes from the Doig, Halfway, Baldonnel, Coplin and Bluesky formations. Oil is treated at two Baytex-operated batteries and natural gas is compressed at four Baytex-operated sites and sent for further processing at the outside-operated West Stoddart and Taylor Younger plants. Production
 
 
 

 
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from this area during 2009 averaged approximately 6,899 Mcf/d of gas and 1,122 bbl/d of oil and NGL (2,272 boe/d). Baytex drilled 2 (2.0 net) successful oil wells in 2009. We plan to drill one well in the area in 2010. At year-end 2009, Baytex had 27,500 net undeveloped acres in this area.
 
Turin, Alberta:  This multi-zone, year-round access property was acquired in 2004. Production during 2009 averaged approximately 476 bbl/d of oil and NGL and 1,147 Mcf/d of gas (667 boe/d). Production is from the Second White Specks, Milk River, Bow Island, Mannville, Sawtooth and Livingstone formations. Oil production is treated at three Baytex-operated batteries and gas is processed at two outside-operated gas plants. Baytex did not drill any wells in this area in 2009, but we plan to drill one well in this area in 2010. At year-end 2009, Baytex had 9,400 net undeveloped acres in this area.
 
United States Business Unit
 
Through our wholly-owned subsidiary, Baytex USA, we acquired significant land positions in the Williston and Powder River Basins in 2007 and 2008. During 2009, Baytex USA drilled 7 (2.2 net) wells and increased its acreage position to over 126,100 net acres.  Net production from the United States properties averaged 408 boe/d in 2009, as compared to 188 boe/d in 2008. Development activity ramped up in the second half of 2009, and net production reached approximately 600 boe/d in December, 2009.
 
Listed below is a brief description of the principal properties within the United States Business Unit:
 
Williston Basin – Bakken/Three Forks Project: This light oil resource play is located in the Divide and Burke Counties of North Dakota.  Production is primarily from horizontal wells using multi-zone hydraulic fracturing in the Bakken and Three Forks formations.  Both zones are accessed through a single horizontal lateral.  Baytex USA has invested in approximately 251,000 (94,000 net) acres of land, of which 230,632 (88,127 net) acres were undeveloped at year-end 2009. In 2009, Baytex USA participated in 6 (1.6 net) wells. Net production from the project averaged approximately 354 boe/d in 2009.  In 2010, Baytex USA plans to drill approximately 20 (7.5 net) horizontal wells. Ultimately, the project has the potential to include 150 to 300 wells with average initial production rates expected to be approximately 300 boe/d per well and average recoveries expected to be approximately 275 Mboe/well.
 
Powder River Basin – Mowry Shale Play (Wild West):  In September 2007, Baytex USA acquired its initial leasehold interest in this Mowry shale play in Wyoming covering approximately 15,300 (9,200 net) acres. A vertical well (Baytex USA 60% working interest) was drilled in 2008 to acquire core and ultimately serve as a microseismic monitoring well for subsequent horizontal-well fracturing. Completion of the vertical well, including hydraulic fracturing, was conducted in the first quarter of 2009. We drilled and completed our first horizontal well in the second half of 2009.
 
Average Production
 
The following table indicates our average daily production from our principal areas for the year ended December 31, 2009.
 
 
Light Oil and NGL
(bbl/d)
Heavy Oil
(bbl/d)
Natural Gas
(Mcf/d)
Oil Equivalent
(boe/d)
Canadian Heavy Oil Business Unit
       
Ardmore
-
1,012
374
1,074
Carruthers
-
2,164
583
2,261
Celtic
-
4,326
878
4,472
Cold Lake
-
476
-
476
Golden lake
-
783
-
783
Greenstreet
-
42
1,059
219
Hoosier
-
445
-
445
Kerrobert / Coleville (1)
 
914
1,755
1,207
Lashburn
-
48
-
48
Lindbergh
-
577
61
587
Maidstone
-
852
-
852
 
 
 

 
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Light Oil and NGL
(bbl/d)
Heavy Oil
(bbl/d)
Natural Gas
(Mcf/d)
Oil Equivalent
(boe/d)
        Marsden - 584 - 584
        Neilburg - 498 - 498
Poundmaker
-
1,609
439
1,682
Seal
-
5,095
-
5,095
Silverdale / Epping / Macklin / Buzzard
-
2,686
409
2,754
Sugden
-
407
-
407
Tangleflags
-
2,062
683
2,176
Remaining properties
-
98
1,160
291
Total Canadian Heavy Oil Business Unit
-
24,678
7,401
25,911
         
Canadian Light Oil and Gas Business Unit
       
Bon Accord
304
-
2,073
650
Darwin/Nina
-
-
1,844
307