Exhibit 3.1

ANNUAL INFORMATION FORM

FOR THE YEAR ENDED

DECEMBER 31, 2005

March 28, 2006

TABLE OF CONTENTS

	Page
ABBREVIATIONS	i
CONVERSIONS	i
CERTAIN DEFINITIONS	ii
FORWARD-LOOKING STATEMENTS	vi
TRUE ENERGY TRUST	1
General	1
Inter-Corporate Relationships	1
Our Organization Structure	2
DESCRIPTION OF THE BUSINESS OF THE TRUST	2
Business of the Trust	2
True Energy Inc.	3
Business Strategy	3
GENERAL DEVELOPMENT OF OUR BUSINESS	3
True Energy Inc.	3
The 2005 Arrangement	6
Recent Developments	6
Significant Acquisitions	6
STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION	7
Disclosure of Reserves Data	7
Additional Information Relating to Reserves Data	15
Other Oil and Gas Information	16
ADDITIONAL INFORMATION RESPECTING THE TRUST	24
Trust Units	24
Special Voting Rights	25
Trust Unitholder Limited Liability	25
Issuance of Trust Units	26
Distributions on Trust Units	26
Redemption Right	26
Non-Resident Unitholders	28
Meetings of Trust Unitholders	28
Exercise of Voting Rights attached to Shares of True Energy	28
Take-over Bids	29
The Trustee	29
Liability of the Trustee	29
Amendments to the Trust Indenture	30
Termination of the Trust	30
SHARE CAPITAL OF TRUE ENERGY INC.	31
Common Shares	31
Exchangeable Shares	31
BORROWINGS	35
NOTES	36
Terms and Issue of Notes	36
Events of Default	37
CORPORATE GOVERNANCE	37
General	37
Trust Indenture	37
Decision Making	37
Directors and Officers of True Energy	38
Conflicts of Interest	39
AUDIT COMMITTEE INFORMATION	40
DISTRIBUTIONS TO UNITHOLDERS	41
MARKET FOR SECURITIES	42
INDUSTRY CONDITIONS	43
RISK FACTORS	47
HUMAN RESOURCES	54
General	54
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS	54

INTERESTS OF EXPERTS	55
LEGAL PROCEEDINGS	55
MATERIAL CONTRACTS	55
AUDITORS, TRANSFER AGENT AND REGISTRAR	55
ADDITIONAL INFORMATION	56
SCHEDULE “A” - REPORT OF MANAGEMENT AND DIRECTORS ON OIL AND GAS DISCLOSURE
SCHEDULE “B” - REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATORS
SCHEDULE “C” - MANDATE OF THE AUDIT COMMITTEE

ABBREVIATIONS

Oil and Natural Gas Liquids
Bbl	barrel
Bbls	barrels
Mbbls	thousand barrels
MMbbls	million barrels
Mstb	1,000 stock tank barrels
Bbls/d	barrels per day
BOPD	barrels of oil per day
NGLs	natural gas liquids
STB	stock tank barrels
Natural Gas
Mcf	thousand cubic feet
MMcf	million cubic feet
Mcf/d	thousand cubic feet per day
MMcf/d	million cubic feet per day
MMbtu	million British Thermal Units
Bcf	billion cubic feet
GJ	gigajoule
MM	Million

Other
AECO	EnCana Corp.’s natural gas storage facility located at Suffield, Alberta.
API	American Petroleum Institute
°API	an indication of the specific gravity of crude oil measured on the API gravity scale.
ARTC	Alberta Royalty Tax Credit
BOE	barrel of oil equivalent of natural gas and crude oil on the basis of 1 BOE for 6 Mcf of natural gas
BOE/d	barrel of oil equivalent per day
m3	cubic metres
MBOE	1,000 barrels of oil equivalent
$000s	thousands of dollars
WTI	West Texas Intermediate, the reference price paid in U.S. dollars at Cushing, Oklahoma for crude oil of standard grade

Disclosure provided herein in respect of 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.

CONVERSIONS

To Convert From	To	Multiply By
Mcf	Cubic metres	28.174
Cubic metres	Cubic feet	35.494
Bbls	Cubic metres	0.159
Cubic metres	Bbls oil	6.290
Feet	Metres	0.305
Metres	Feet	3.281
Miles	Kilometres	1.609
Kilometres	Miles	0.621
Acres (Alberta)	Hectares	0.400
Hectares (Alberta)	Acres	2.500
Acres (British Columbia)	Hectares	0.405
Hectares (British Columbia)	Acres	2.471

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CERTAIN DEFINITIONS

In this Annual Information Form, the following words and phrases have the following meanings, unless the context otherwise requires:

“ABCA” means Business Corporations Act (Alberta);

“Administration Agreement” means the administration agreement dated September 27, 2004 between the Trustee and True Energy pursuant to which True Energy provides certain administrative and advisory services in connection with the Trust;

“2004 Arrangement” means the plan of arrangement involving, inter alia, TKE Energy Inc., TUSK Energy Corporation and the Trust completed on November 2, 2004 under the ABCA pursuant to which, among other things, the Trust acquired all of the issued and outstanding common shares of TKE Energy Inc.;

“2005 Arrangement” means the plan of arrangement involving, inter alia, the Trust, True Energy Inc., TKE Energy Inc and Vero Energy Inc. completed on November 2, 2005 under the ABCA pursuant to which, among other things, the Trust acquired all of the issued and outstanding common shares of True Energy Inc.;

“Chapman” means Chapman Petroleum Engineering Ltd.;

“COGE Handbook” means the Canadian Oil and Gas Evaluation Handbook prepared jointly by the Society of Petroleum Evaluation Engineers (Calgary chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum;

“Common Shares” means the common shares in the capital of True Energy;

“Current Market Price of a Trust Unit” means, in respect of a Trust Unit on any date, the weighted average trading price of the Trust Units on the TSX on that date and the five (5) trading days preceding that date, or, if the Trust Units are not then listed on the TSX, on such other stock exchange or automated quotation system on which the Trust Units are listed or quoted, as the case may be, as may be selected by the board of directors of True Energy for such purpose; provided, however, that if in the opinion of the board of directors of True Energy the public distribution or trading activity of Trust Units does not result in a weighted average trading price which reflects the fair market value of a Trust Unit, then the Current Market Price of a Trust Unit shall be determined by the board of directors of True Energy, in good faith and in its sole discretion, and provided further that any such selection, opinion or determination by such board of directors shall be conclusive and binding;

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

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

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

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

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(d)provide improved recovery systems.

“Distributable Cash” means all amounts available for distribution during any applicable period to holders of Trust Units;

“Distribution” means a distribution paid by the Trust in respect of the Trust Units, expressed as an amount per Trust Unit;

“Distribution Payment Date” means any date that Distributable Cash is distributed to Unitholders, generally being the 15th day of the calendar month following any Distribution Record Date (or if such day is not a Business Day, on the next Business Day thereafter);

“Distribution Record Date” means the last day of each calendar month or such other date as may be determined from time to time by the Trustee, except that December 31 shall in all cases be a Distribution Record Date;

“DRIP” means the Trust’s Distribution Reinvestment and Optional Trust Unit Purchase Plan;

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

“Exchange Rights” means the exchange rights as defined pursuant to the voting and exchange trust agreement;

“Exchangeable Shares” means the series A exchangeable shares in the capital of True Energy which are exchangeable for Trust Units;

“Exchangeable Share Provisions” means the rights, privileges, restrictions and conditions attaching to the Exchangeable Shares;

“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.

“GLJ” means GLJ Petroleum Consultants Ltd.;

“GLJ Report” means the report of GLJ dated February 27, 2006 evaluating our crude oil, natural gas liquids and natural gas reserves as at December 31, 2005;

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“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.

“Income Tax Act” or “Tax Act” means the Income Tax Act (Canada), R.S.C. 1985, c. 1. (5th Supp), as amended, including the regulations promulgated thereunder;

“Net” means:

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

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

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

“NI 51-101” means National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities;

“Notes” means the unsecured, subordinated promissory notes issued by True Energy and held by the Trust;

“Note Indenture” means the note indenture, as amended and supplemented from time to time, relating to the issuance of the Notes;

“NPI” means the net profits interest granted under the NPI Agreement;

“NPI Agreement” means the net profits agreement between the Trustee, True Energy Inc. and TKE Partnership dated November 2, 2005;

“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;

“Special Voting Rights” means the special voting rights of the Trust, issued and certified under the Trust Indenture for the time being outstanding and entitled to the benefits and subject to the limitations set forth therein;

“Support Agreement” means the support agreement dated November 2, 2004 between the Trust and True Energy;

“True, we, us, our or Trust” means True Energy Trust (formerly TKE Energy Trust), a trust established under the laws of Alberta pursuant to the Trust Indenture and, where the context requires, all its controlled entities on a consolidated basis;

“True Energy” or the “Corporation” or the “Administrator” means True Energy Inc., a corporation amalgamated pursuant to the ABCA and the administrator of the Trust;

“Trustee” means Computershare Trust Company of Canada, the initial trustee of the Trust, or such other trustee, from time to time, of the Trust;

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“Trust Indenture” means the trust indenture dated as of September 27, 2004 between Computershare Trust Company of Canada and True Energy, as amended from time to time;

“Trust Unit” or “Unit” means a unit of the Trust;

“Trust Unitholders” or “Unitholders” means holders from time to time of Trust Units;

“TUSK” means TUSK Energy Inc., a corporation incorporated under the ABCA that changed its name to TKE Energy Inc. on December 14, 2004 and amalgamated with True Energy Inc. pursuant to the 2005 Arrangement and continued under the name True Energy Inc.;

“Voting and Exchange Trust Agreement” means the voting and exchange trust agreement dated November 2, 2004 between the Trust, True Energy and the Trustee; and

“Voting and Exchange Agreement Trustee” means Computershare Trust Company of Canada, the initial trustee under the Voting and Exchange Trust Agreement, or such other trustee, from time to time appointed thereunder.

Certain other terms used herein but not defined herein are defined in NI 51-101 and, unless the context otherwise requires, shall have the same meanings herein as in NI 51-101.

Unless otherwise specified, information in this Annual Information Form is as at the end of the Trust’s most recently completed financial year, being December 31, 2005.

All dollar amounts herein are in Canadian dollars, unless otherwise stated.

v

FORWARD-LOOKING STATEMENTS

Certain of the statements contained herein including, without limitation, financial and business prospects and financial outlook, reserve and production estimates, drilling and re-completion plans, timing of drilling, re-completion and tie-in of wells, productive capacity of wells and productive capacity of wells and capital expenditures and the timing thereof may be forward-looking statements. Words such as “may”, “will”, “should”, “could”, “anticipate”, “believe”, “expect”, “intend”, “plan”, “potential”, “continue” and similar expressions may be used to identify these forward-looking statements. These statements reflect management’s current beliefs and are based on information currently available to management. Forward-looking statements involve significant risk and uncertainties. A number of factors could cause actual results to differ materially from the results discussed in the forward-looking statements including, but not limited to, risks associated with oil and gas exploration, development, exploitation, production, marketing and transportation, loss of markets, volatility of commodity prices, currency fluctuations, imprecision of reserve estimates, environmental risks, competition from other producers, inability to retain drilling rigs and other services, incorrect assessment of the value of acquisitions, failure to realize the anticipated benefits of acquisitions, delays resulting from or inability to obtain required regulatory approvals and ability to access sufficient capital from internal and external sources and the risk factors outlined under “Risk Factors” and elsewhere herein. The recovery and reserve estimates of True’s reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. As a consequence, actual results may differ materially from those anticipated in the forward-looking statements. Readers are cautioned that the foregoing list of factors is not exhausted. Additional information on these and other factors that could effect True’s operations and financial results are included in reports on file with Canadian securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com), at True’s website (www.trueenergy.ab.ca). Although the forward-looking statements contained herein are based upon what management believes to be reasonable assumptions, management cannot assure that actual results will be consistent with these forward-looking statements. Investors should not place undue reliance on forward-looking statements. These forward-looking statements are made as of the date hereof and True assumes no obligation to update or review them to reflect new events or circumstances except as required by applicable securities laws.

Forward-looking statements and other information contained herein concerning the oil and gas industry and True’s general expectations concerning this industry is based on estimates prepared by management using data from publicly available industry sources as well as from reserve reports, market research and industry analysis and on assumptions based on data and knowledge of this industry which True believes to be reasonable. However, this data is inherently imprecise, although generally indicative of relative market positions, market shares and performance characteristics. While True is not aware of any misstatements regarding any industry data presented herein, the industry involves risks and uncertainties and is subject to change based on various factors.

vi

TRUE ENERGY TRUST

General

We are an open-end investment trust created on November 2, 2004 under the laws of the Province of Alberta pursuant to the Trust Indenture. Computershare Trust Company of Canada has been appointed as trustee under the Trust Indenture. The beneficiaries of the Trust are holders of the Trust Units. Our principal and head office is located at 2300, 530 – 8^th Avenue S.W., Calgary, Alberta T2P 3S8.

We commenced operations on November 2, 2004 following completion of the 2004 Arrangement under which TUSK Energy Inc. was reorganized into an income trust.

The Trust Units trade on the TSX under the symbol “TUI.UN”.

Inter-Corporate Relationships

The following are the names, the percentage of voting securities that we own and the jurisdiction of incorporation, continuance or formation of our subsidiaries, partnerships and trusts, direct and indirect, as at the date hereof.

	Percentage of voting securities (directly or indirectly)	Nature of Entity	Jurisdiction of Incorporation/ Formation
True Energy Inc.	100%	Corporation	Alberta
Marengo Exploration Ltd.	100%	Corporation	Alberta
True Partnership	100%	General Partnership	Alberta
TKE Partnership	100%	General Partnership	Alberta

Our Organization Structure

The following diagram describes the inter-corporate relationships among us and our material subsidiaries, trusts and partnerships.

Notes:

(1)Unitholders own 100% of our Trust Units.

(2)True Energy had a total of 788,558 Exchangeable Shares issued and outstanding as at December 31, 2005, which, as at December 31, 2005 were exchangeable for 454,888 Trust Units.

(3)Cash distributions are made on a monthly basis to Unitholders based upon our cash flow. Our primary sources of cash flow are payments from True Energy pursuant to interest on the principal amount of the Notes and income earned under the NPI Agreement. In addition to such amounts, prepayments in respect of principal on the Notes and other intercorporate notes may be made from time to time by True Energy before maturity of such Notes.

DESCRIPTION OF THE BUSINESS OF THE TRUST

Business of the Trust

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 direct and indirect subsidiaries and partnerships carry on the business of acquiring, developing, exploiting and holding interests in petroleum and natural gas properties and assets related thereto. Cash flow from the properties is flowed from True Energy to us by way of interest payments and principal repayments on the Notes and income earned under the NPI Agreement.

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Unitholders receive monthly distributions of the cash flow generated by True Energy. The Trust employs a strategy to: (i) provide Unitholders with a competitive annual cash on cash yield by making monthly cash distributions to such Unitholders; (ii) provide that True Energy’s assets are maintained efficiently at a sustainable level; and (iii) enable the Trust to continue to expand its business through development and acquisition opportunities that will provide long term stable cash flows and be accretive to Unitholders.

Cash distributions are made on or about the 15^th day of each month to Unitholders of record on or about the last calendar day of the immediately preceding month. The board of directors of True Energy reviews the Trust’s distribution policy from time to time. The actual amount distributed is dependent on various factors including the commodity price environment and is at the discretion of the board of directors of True Energy. The long term distribution vision targets the use of approximately sixty to eighty percent of cash available for distribution to Unitholders with the balance of cash available to fund a portion of the Trust’s annual capital expenditure program, including both exploitation expenditures and minor property acquisitions, but excluding major acquisitions. Distributions are reviewed monthly by the board of directors with a view to the long term health of the Trust.

True Energy Inc.

True Energy is a corporation amalgamated and subsisting pursuant to the laws of the province of Alberta. True Energy, formed on the amalgamation of True Energy Inc. and TKE Energy Inc. effective November 2, 2005 upon completion of the 2005 Arrangement, is actively engaged in the business of oil and natural gas exploitation, development, acquisition and production in western Canada. True Energy is the administrator and carries on the business of the Trust.

The Trust is the sole holder of Common Shares of True Energy. The Exchangeable Shares are owned by the public.

The head office of True Energy is located at Suite 2300, 530 - 8th Avenue S.W., Calgary, Alberta T2P 3S8 and its registered office is located at Suite 1400, 350 – 7^th Avenue S.W., Calgary, Alberta T2P 3N9.

Business Strategy

Our objective is to generate stable monthly distributions. In order to do so, we are pursuing an integrated growth strategy including development drilling within our core areas and, where appropriate, focused acquisitions. We will also focus on cost effective operations and the development of our property base.

The Trust is not managed by a third party manager but is managed by the management of True Energy, which is comprised of the majority of the same management as that which existed at True Energy prior to completion of the 2005 Arrangement. This structure enables the Trust to leverage the technical skill of the staff responsible for the historical finding and development of True Energy’s assets and to realize the full potential of those assets through continued development.

GENERAL DEVELOPMENT OF OUR BUSINESS

True Energy Inc.

Original Amalgamation

True Energy Inc. was originally formed on the amalgamation (the “Original Amalgamation”) of Sundance Resources Inc. (“Sundance”), 887733 Alberta Ltd. (“Holdco”) and 851431 Alberta Ltd. (“Newco”) pursuant to the ABCA effective August 31, 2000.

Sundance Resources Inc.

Sundance was incorporated as Sundance Resources Inc. under the ABCA on February 9, 1996. Sundance’s principal oil and gas properties at the time of the Original Amalgamation were located in the Province of Saskatchewan.

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Sundance completed its initial public offering as a junior capital pool company and commenced trading on the Alberta Stock Exchange on July 3, 1996.

Sundance’s major transaction as a junior capital pool company was comprised of two acquisitions. Pursuant to the first acquisition, effective November 7, 1997, Sundance purchased various oil and gas interests held by four private companies, including interests in six producing oil wells, one shut-in gas well, 11 suspended wells and numerous development targets. Sundance paid $510,000 for these interests, based on a third party evaluation of the proved and probable reserves associated with these interests. Pursuant to the second acquisition, effective February 25, 1998, Sundance acquired certain oil and gas interests held by Vandale Oil Inc., including interests in light and heavy oil processing facilities, as well as interests in properties containing 27 producing wells, three non-producing wells and seven abandoned wells or suspended injectors. Sundance paid $1,528,000 for these interests, based on a third party evaluation of the proved and probable reserves associated with these interests. The acquisitions were approved by shareholders of Sundance at the annual and special meeting of shareholders held on April 24, 1998. The purchase price for the acquisitions was paid through the issuance of 1,680,865 common shares of Sundance and a debenture that was subsequently converted into 2,857,143 common shares of Sundance in July, 1999 at $0.21 per share and 997,404 common shares of Sundance in November, 1999 at $0.225 per share.

887733 Alberta Ltd.

Holdco was incorporated under the ABCA on July 5, 2000. Prior to the Original Amalgamation, Holdco had not conducted any operations other than negotiating and entering into a petroleum, natural gas and general rights conveyance agreement dated July 20, 2000 pursuant to which it acquired (the “Clanrob Acquisition”) from Clanrob Resources Ltd. (“Clanrob”), effective August 31, 2000, certain petroleum and natural gas assets (the “Clanrob Assets”) in consideration of the assumption by Holdco of indebtedness in the amount of $700,000 and the issuance by Holdco to Clanrob of 2,950,000 Holdco common shares. The transaction occurred immediately prior to the Original Amalgamation.

851431 Alberta Ltd.

Newco was incorporated under the ABCA on October 26, 1999. Prior to the Original Amalgamation, Newco had not conducted operations other than engaging in discussions and negotiations for the purpose of completing a private placement that occurred prior to the Original Amalgamation, of 3,876,904 Newco common shares for aggregate consideration of $3,517,380.

The Amalgamation of Sundance, Holdco and Newco

The Original Amalgamation of Sundance, Holdco and Newco was effective August 31, 2000 pursuant to the ABCA. Pursuant to the Original Amalgamation (i) holders of common shares of Sundance received 0.444 common shares of True (“Common Shares”) for each Sundance common share held, (ii) holders of Newco common shares received one Common Share for each Newco common share held, and (iii) holders of Holdco common shares received one Common Share for each Holdco common share held. Immediately upon completion of the Original Amalgamation, a new management team and the board of directors of the Corporation was put in place. After giving effect to the Original Amalgamation, the Corporation had 10,649,934 Common Shares outstanding. The Common Shares commenced trading on the Canadian Venture Exchange (“CDNX”) on September 13, 2000.

Acquisition of Marengo Exploration Ltd.

Marengo Exploration Ltd. (“Marengo”) was incorporated under the ABCA on July 3, 1996. On November 3, 1997, the Corporation filed Articles of Amendment to remove the private company provisions and the restrictions on share transfer, consolidate the outstanding common shares on a 0.8 new for 1 old basis, increase the minimum number of directors to three, change the name of the common shares to Class A Shares and create Class B Shares.

Marengo was in the business of exploration, development and production of petroleum and natural gas, primarily in the Province of Saskatchewan.

Marengo closed its initial public offering at the end of December 1997 for gross proceeds of $4,647,000. Marengo had 3,894,100 Class A shares and 408,936 Class B shares outstanding. Marengo shares began trading on

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the CDNX (formerly the Alberta Stock Exchange) under the trading symbols “MRO.A” and “MRO.B” for the Class A and Class B shares respectively in March of 1998.

On December 31, 1998, Marengo closed a $650,000 private placement financing of 650,000 flow-through Class A common shares at a price of $1.00 per share.

On December 31, 1999, Marengo closed a $487,500 private placement financing of 975,000 flow-through Class A common shares at a price of $0.50 per share.

Pursuant to an offer dated February 6, 2001, True Energy acquired all of the outstanding Class A Shares and Class B Shares of Marengo in consideration for an aggregate of 947,251 Common Shares and $15,000,545 in cash.

Acquisition of Gresham Resources Inc.

Gresham Resources Inc. (“Gresham”) was incorporated under the laws of the Province of British Columbia on May 1, 1987 as “Mammoth Resources Ltd.”. On October 5, 1987, its name was changed to “Death Valley Resources Ltd.”, on March 23, 1989 its name was changed to “DVR Resources Ltd.”, and on June 14, 1993 its name was changed to “Gresham Resources Inc.” On February 6, 2001, by Articles of Continuance, Gresham continued from British Columbia to Alberta. Gresham shares traded on the TSX Venture Exchange under the trading symbol “GRC”.

Gresham had one wholly-owned subsidiary, which was incorporated in Nevada, U.S.A., on November 20, 1987 under the name “Death Valley Resources (U.S.), Inc.” The name was changed to “Gresham Oil & Gas (USA) Inc.” on August 19, 1993.

Gresham’s petroleum and natural gas assets were located in Alberta. Effective December 31, 1999, Gresham sold its holdings in the south-west North Dakota sector of the Williston Basin. Proceeds of $4,329,000 from the sale were used to fund an acquisition and drilling at Rosevear, Alberta. On February 1, 2000, interests in the Rosevear area were purchased for $4,500,000 and 1,200,000 Gresham shares at an ascribed value of $0.83 per share.

On May 30, 2001, Gresham closed a $9.6 million acquisition at Doris Creek, effective April 1, 2001. The purchase included 47,000 net undeveloped acres of land.

Pursuant to a plan of arrangement, True acquired all of the issued and outstanding shares of Gresham, effective July 31, 2002, on the basis of 1.4 Common Shares of True for each outstanding common share of Gresham, for an aggregate of 12,232,654 Common Shares.

True Energy and its wholly owned subsidiary, Gresham, amalgamated effective December 1, 2002 pursuant to the ABCA, and continued under the name True Energy Inc. At December 1, 2002, True Energy had 45,117,756 Common Shares issued and outstanding.

As Gresham Oil & Gas (USA) Inc. no longer engaged in any activity nor had any assets in the United States or Canada, it was dissolved effective May 2003.

Acquisition of Meridian Energy Corporation

Meridian Energy Corporation (“Meridian”) was incorporated under the laws of the province of British Columbia on December 18, 1992 under the name “Meridian Petroleum Corporation”. On March 31, 1993, its name was changed to “Meridian Energy Corporation” and the company was continued under the laws of the province of Alberta on September 9, 1996. Meridian shares traded on the TSX Venture Exchange under the trading symbol “MDE”.

Meridian was in the business of exploration, development and production of petroleum and natural gas, primarily in the province of Alberta. On March 15, 2005 True Energy acquired over 95% of the issued and outstanding shares of Meridian pursuant to an offer to purchase on the basis of, at the election of Meridian shareholders, (i) 0.91 Common Shares of True Energy per Meridian share; or (ii) $3.85 in cash per Meridian share;

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or (iii) a combination thereof, provided that the maximum aggregate amount of cash payable pursuant to the offer be limited to $30 million. True Energy acquired the balance of the Meridian shares pursuant to the compulsory acquisition provisions under the ABCA on March 29, 2005. The previous shareholders of Meridian received a total of $619,742.20 in cash and 35,749,930 Common Shares of True Energy in exchange for all of the outstanding shares of Meridian. True and its then wholly owned subsidiary, Meridian, were amalgamated under the ABCA on November 2, 2005 under the name True Energy Inc.

The Business Acquisition Report dated May 27, 2005 in respect of the acquisition of Meridian is incorporated by reference herein and can be located on SEDAR under the Administrator’s SEDAR profile at www.sedar.com.

The 2005 Arrangement

General

On November 2, 2005 the 2005 Arrangement was completed pursuant to which (i) all of the outstanding Common Shares of True Energy were acquired by the Trust, (ii) the name of the Trust was changed from “TKE Energy Trust” to “True Energy Trust” and (iii) the outstanding Trust Units were consolidated on a one for two basis. The 2005 Arrangement also resulted in the creation of Vero Energy Inc., a junior oil and natural gas exploration and development company which acquired approximately 10% of True Energy’s oil and natural gas assets and certain undeveloped lands.

Under the 2005 Arrangement, former shareholders of True Energy received (i) 0.25 of a Trust Unit (on a post-consolidation basis), (ii) 0.10 of a common share of Vero, and (iii) one common share purchase warrant of Vero which entitled the holder to acquire 0.0655 of a common share of Vero for a period of thirty days following the effective date of the 2005 Arrangement.

Upon completion of the 2005 Arrangement, True Energy and TKE Energy Inc. were amalgamated under the ABCA under the name “True Energy Inc.”.

History of the TKE Energy Trust

The TKE Energy Trust was created on November 2, 2004 pursuant to the 2004 Arrangement which resulted in the conversion of TUSK into the TKE Energy Trust, a new oil and natural gas energy trust that acquired approximately 95% of TUSK’s then existing producing assets (based on production rates) and the creation of TUSK Energy Corporation, a junior oil and natural gas exploration and development company which acquired the balance of TUSK’s oil and natural gas assets and certain undeveloped lands.

Under the 2004 Arrangement, shareholders of TUSK received, at their election, either 0.5 of one Trust Unit or 0.5 of one Exchangeable Share, and 0.5 of a common share of TUSK Energy Corporation, for each outstanding common share of TUSK held.

Recent Developments

On March 27, 2006 the Trust announced the adoption of a Premium Distribution ^TM, Distribution Reinvestment and Optional Trust Unit Purchase Plan (“the Plan”). Eligible unitholders may elect to participate in the Plan commencing with the monthly cash distribution payable on April 17, 2006 to unitholders of record on March 31, 2006.

Significant Acquisitions

We have not completed any significant acquisitions or significant dispositions or entered into any significant probable acquisitions within or since the completion of our most recently completed financial year other than the acquisition of Meridian by True Energy Inc. and the 2005 Arrangement described above.

6

STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION

The statement of reserves data and other oil and gas information set forth below (the “Statement”) is dated March 28, 2005. The effective date of the Statement is December 31, 2005 and the preparation date of the Statement is March 27, 2006.

Disclosure of Reserves Data

The reserves data set forth below (the “Reserves Data”) is based upon evaluations by GLJ and Chapman with an effective date of December 31, 2005 contained in the GLJ 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 constant prices and costs and forecast prices and costs. The Reserves Data conforms with the requirements of NI 51-101. We engaged GLJ and Chapman to provide an evaluation of proved and proved plus probable reserves and no attempt was made to evaluate possible reserves. All of our reserves are in Canada in the provinces of Alberta, British Columbia and Saskatchewan. Field inspections were not conducted.

We are a taxable entity under the Tax Act and are taxable only on income that is not distributed or distributable to our Unitholders. As we distribute all of our taxable income to our Unitholders and meet the requirements of the Tax Act applicable to us, net present values of the future net revenues presented below have not been included on an after tax basis.

The Report of Management and Directors on Oil and Gas Disclosure in Form 51-101F3 and the Report on Reserves Data by our independent qualified reserves evaluators in Form 51-101F2 are attached as Schedule “A” and Schedule “B” respectively, hereto.

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

7

Reserves Data (Constant Prices and Costs)

SUMMARY OF OIL AND GAS RESERVES

AND NET PRESENT VALUES OF FUTURE NET REVENUE

AS OF DECEMBER 31, 2005

CONSTANT PRICES AND COSTS

	Light And Medium Oil		Heavy Oil		Conventional Natural Gas		Natural Gas Liquids
Reserves Category	Gross	Net	Gross	Net	Gross	Net	Gross	Net
	(Mbbls)	(Mbbls)	(Mbbls)	(Mbbls)	(MMcf)	(MMcf)	(Mbbls)	(Mbbls)
Proved Developed Producing	1,670	1,534	2,640	2,210	58,203	47,112	724	482
Proved Developed Non-Producing	10	8	26	21	11,598	9,130	116	74
Proved Undeveloped	335	310	496	389	6,205	5,198	124	85
Total Proved	2,015	1,853	3,162	2,621	76,005	61,440	964	641
Probable	1,142	1,012	1,891	1,559	49,936	40,329	588	377
Total Proved Plus Probable	3,156	2,864	5,052	4,179	125,941	101,769	1,552	1,018

	Net Present Values of Future Net Revenue
	Before Income Taxes Discounted At (%/year)
Reserves Category	0	5	10	15	20
	($000s)	($000s)	($000s)	($000s)	($000s)
Proved Developed Producing	441,841	368,315	319,598	284,460	257,709
Proved Developed Non-Producing	70,872	53,675	43,438	36,664	31,829
Proved Undeveloped	39,244	29,106	22,221	17,277	13,581
Total Proved	551,957	451,097	385,257	338,401	303,120
Probable	350,687	237,494	175,659	137,504	111,861
Total Proved Plus Probable	902,645	688,591	560,916	475,905	414,981

TOTAL FUTURE NET REVENUE
(UNDISCOUNTED)

AS OF DECEMBER 31, 2005
CONSTANT PRICES AND COSTS

Reserves Category	Revenue	Royalties	Operating Costs	Development Costs	Well Abandonment Costs	Future Net Revenue Before Income Taxes
	($000s)	($000s)	($000s)	($000s)	($000s)	($000s)
Proved Reserves	1,017,735	205,102	211,169	37,557	11,949	551,957
Proved Plus Probable	1,660,370	329,171	343,239	70,756	14,559	902,645

8

FUTURE NET REVENUE
BY PRODUCTION GROUP
AS OF DECEMBER 31, 2005
CONSTANT PRICES AND COSTS

Reserves Category	Production Group	Future Net Revenue Before Income Taxes (discounted at 10%/year)
		($000s)
Proved	Light and Medium Crude Oil (including solution gas and other by-products)	34,938
	Heavy Oil (including solution gas and other by-products)	28,265
	Natural Gas (including by-products but excluding solution gas from oil wells)	322,054
	Total	385,257
Proved Plus Probable	Light and Medium Crude Oil (including solution gas and other by-products)	47,020
	Heavy Oil (including solution gas and other by-products)	40,895
	Natural Gas (including by-products but excluding solution gas from oil wells)	473,001
	Total	560,916

Note:

(1)Other company revenue and costs not related to a specific production group (e.g., ARTC) have been allocated proportionately to production groups.

Reserves Data (Forecast Prices and Costs)

SUMMARY OF OIL AND GAS RESERVES

AND NET PRESENT VALUES OF FUTURE NET REVENUE
AS OF DECEMBER 31, 2005

FORECAST PRICES AND COSTS

	Light And Medium Oil		Heavy Oil		Conventional Natural Gas		Natural Gas Liquids
Reserves Category	Gross	Net	Gross	Net	Gross	Net	Gross	Net
	(Mbbls)	(Mbbls)	(Mbbls)	(Mbbls)	(MMcf)	(MMcf)	(Mbbls)	(Mbbls)
Proved Developed Producing	1,561	1,425	2,676	2,228	56,953	46,019	709	473
Proved Developed Non-Producing	10	9	32	27	11,565	9,096	115	74
Proved Undeveloped	334	309	489	378	6,205	5,192	122	84
Total Proved	1,906	1,743	3,197	2,633	74,723	60,308	946	630
Probable	1,111	978	1,882	1,543	48,908	39,469	568	367
Total Proved Plus Probable	3,016	2,722	5,079	4,175	123,631	99,777	1,514	997

	Net Present Values of Future Net Revenue
	Before Income Taxes Discounted At (%/year)
Reserves Category	0	5	10	15	20
	($000s)	($000s)	($000s)	($000s)	($000s)
Proved Developed Producing	382,532	330,863	295,516	269,152	248,446
Proved Developed Non-Producing	60,885	46,682	38,432	33,030	29,176
Proved Undeveloped	32,120	24,814	19,637	15,777	12,801
Total Proved	475,537	402,359	353,585	317,960	290,423
Probable	285,331	197,533	149,216	119,080	98,588
Total Proved Plus Probable	760,869	599,891	502,800	437,040	389,011

9

TOTAL FUTURE NET REVENUE
(UNDISCOUNTED)
AS OF DECEMBER 31, 2005
FORECAST PRICES AND COSTS

Reserves Category	Revenue	Royalties	Operating Costs	Development Costs	Well Abandonment Costs	Future Net Revenue Before Income Taxes
	($000s)	($000s)	($000s)	($000s)	($000s)	($000s)
Proved Reserves	939,477	194,602	217,480	37,828	14,031	475,537
Proved Plus Probable	1,520,999	304,817	365,587	71,731	17,995	760,869

FUTURE NET REVENUE
BY PRODUCTION GROUP
AS OF DECEMBER 31, 2005
FORECAST PRICES AND COSTS

Reserves Category	Production Group	Future Net Revenue Before Income Taxes (discounted at 10%/year)
		($000s)
Proved Reserves	Light and Medium Crude Oil (including solution gas and other by-products)	27,798
	Heavy Oil (including solution gas and other by-products)	38,027
	Natural Gas (including by-products but excluding solution gas from oil wells)	287,760
	Total	353,585
Proved Plus Probable	Light and Medium Crude Oil (including solution gas and other by-products)	36,110
	Heavy Oil (including solution gas and other by-products)	55,038
	Natural Gas (including by-products but excluding solution gas from oil wells)	411,652
	Total	502,800

Note:

(1)Other company revenue and costs not related to a specific production group (e.g., ARTC) have been allocated proportionately to production groups.

Notes to Reserves Data Tables:

1.Columns may not add due to rounding.

2.The crude oil, natural gas liquids and natural gas reserve estimates presented in the GLJ Report are based on the definitions and guidelines contained in the COGE Handbook. A summary of those definitions are set forth below.

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

•analysis of drilling, geological, geophysical and engineering data;

•the use of established technology; and

•specified economic conditions.

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

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(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 estimatedproved reserves.

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

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

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

(c)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.

(d)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.

In multi-well pools it may be appropriate to allocate total pool reserves between the developed and undeveloped categories or to subdivide the developed reserves for the pool between developed producing and developed non-producing. This allocation should be based on the estimator’s assessment as to the reserves that will be recovered from specific wells, facilities and completion intervals in the pool and their respective development and production status.

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.

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

3.Forecast Prices and Costs

Forecast prices and costs are those:

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

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

The forecast cost and price assumptions assume increases in wellhead selling prices and take into account inflation with respect to future operating and capital costs. Crude oil and natural gas benchmark reference pricing, inflation and exchange rates utilized by GLJ and Chapman in the GLJ Report were an average of forecast prices and costs published by GLJ, Sproule Associates Limited and McDaniel & Associates Consultants Ltd. as at January 1, 2006, which were as follows:

SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS FORECAST PRICES AND COSTS

	OIL								NATURAL GAS AECO Gas Price		NATURAL GAS LIQUIDS at Edmonton		INFLATION RATES(1)	EXCHANGE RATE(2)
Year	WTI Cushing Oklahoma		Edmonton Par Price 40° API		Hardisty Heavy 12° API		Cromer Medium 29.3° API
	($US/Bbl)		($Cdn/Bbl)		($Cdn/Bbl)		($Cdn/Bbl)		($Cdn/MMBtu)		($Cdn/Bbl)		%/Year	($US/$Cdn)
Forecast
2006	58.44		67.64		35.27		57.96		10.93		68.96		2.33	0.85
2007	57.34		66.40		35.38		57.31		9.88		67.89		2.33	0.85
2008	52.70		60.89		34.24		52.68		8.48		62.35		2.33	0.85
2009	49.23		56.83		33.19		49.21		7.59		58.16		2.00	0.85
2010	47.05		54.25		32.18		47.00		7.23		55.59		2.00	0.85
2011	47.19		54.41		33.21		47.16		7.24		55.75		2.00	0.85
2012	47.83		55.12		33.78		47.83		7.34		56.47		2.00	0.85
2013	48.81		56.20		34.49		48.76		7.48		57.60		2.00	0.85
2014	49.75		57.32		35.35		49.80		7.65		58.72		2.00	0.85
2015	50.77		58.53		36.09		50.85		7.83		59.97		2.00	0.85
2016	51.79		59.66		36.93		51.82		7.98		61.19		2.00	0.85
2017	52.85		60.91		37.69		52.99		8.14		62.48		2.00	0.85
2018	53.92		62.16		38.54		54.05		8.30		63.74		2.00	0.85
2019	54.99		63.45		39.31		55.12		8.48		65.07		2.00	0.85
2020	56.09		64.75		40.11		56.31		8.65		66.38		2.00	0.85
2021	57.20		66.06		41.00		57.42		8.83		67.71		2.00	0.85
2022	58.33		67.39		41.72		58.55		9.00		69.07		2.00	0.85
2023	59.48		68.74		42.63		59.78		9.19		70.44		2.00	0.85
Thereafter	+2.0/yr	%	+2.0/yr	%	+2.0/yr	%	+2.0/yr	%	+2.0/yr	%	+2.0/yr	%	2.00	0.85

Notes:

(1)Inflation rates for forecasting prices and costs.

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

(3)Natural Gas Liquids is represented by the pentanes plus price.

Weighted average historical prices realized by True for the year ended December 31, 2005, were $9.41/Mcf for natural gas, $64.19/Bbl for light and medium gravity crude oil, $32.23/Bbl for heavy oil and $52.69/Bbl for natural gas liquids.

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4.Constant Prices and Costs

Constant prices and costs are:

(a)our prices and costs as at the effective date of the estimation, held constant throughout the estimated lives of the properties to which the estimate applies; and

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

For the purposes of paragraph (a), our prices are the posted prices for oil and the spot price for gas, after historical adjustments for transportation, gravity and other factors.

The constant crude oil and natural gas benchmark references pricing and the exchange rate utilized in the Trust Engineering Report were as follows:

SUMMARY OF PRICING ASSUMPTIONS CONSTANT PRICES AND COSTS

	OIL
Year	WTI Cushing Oklahoma	Edmonton Par Price 40° API	LLB at Hardisty	Cromer Medium 29.3° API	NATURAL GAS AECO Gas Price	NATURAL GAS LIQUIDS at Edmonton	EXCHANGE RATE(1)
	($US/Bbl)	($Cdn/Bbl)	($Cdn/Bbl)	($Cdn/Bbl)	($Cdn/MMBtu)	($Cdn/Bbl)	($US/$Cdn)
Historical 2005 (2)	61.04	68.27	39.20	51.84	9.71	71.67	0.8577

Notes:

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

(2)As at December 31, 2005.

(3)Natural Gas Liquids is represented by the pentanes plus price.

5.The ARTC is included in the cumulative cash flow amounts. ARTC is based on the program announced November 1989 by the Alberta government with modifications effective January 1, 1995.

6.Estimated future abandonment costs related to a property have been taken into account by GLJ and Chapman in determining reserves that should be attributed to a property and in determining the aggregatefuture net revenue therefrom, there was deducted the reasonable estimated future well abandonment costs. No allowance was made, however, for reclamation of wellsites or the abandonment and reclamation of any facilities.

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

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Reconciliation of Changes in Reserves

The following table sets out the reconciliation of our net reserves as at December 31, 2004 compared to December 31, 2005 based on forecast prices and costs by principal product type:

													ASSOCIATED AND NON
	LIGHT AND MEDIUM OIL						HEAVY OIL						ASSOCIATED GAS
					Net						Net						Net
					Proved						Proved						Proved
	Net		Net		Plus		Net		Net		Plus		Net		Net		Plus
FACTORS	Proved		Probable		Probable		Proved		Probable		Probable		Proved		Probable		Probable
	(Mbbl)		(Mbbl)		(Mbbl)		(Mbbl)		(Mbbl)		(Mbbl)		(MMcf)		(MMcf)		(MMcf)
December 31, 2004(1)	353		83		436		2,092		880		2,972		32,951		14,483		47,434
Discoveries	36		14		50		—		—		—		2,824		2,588		5,412
Extensions	4		1		5		987		712		1,699		2,874		3,723		6,597
Infill Drilling	111		34		145		—		—		—		3,278		337		3,615
Improved Recovery	(4	)	—		(4	)	4		—		4		124		471		595
Technical Revisions	49		(12	)	37		69		(168	)	(99	)	126		(2,287	)	(2,161	)
Acquisitions(2)	1,402		873		2,275		58		97		155		31,065		21,835		52,900
Dispositions(3)	(80	)	(21	)	(101	)	—		—		—		(3,380	)	(1,690	)	(5,071	)
Economic Factors	33		8		41		52		21		73		(46	)	11		(35	)
Production	(162	)	—		(162	)	(628	)	—		(628	)	(9,509	)	—		(9,509	)
December 31, 2005	1,743		979		2,722		2,633		1,542		4,175		60,308		39,469		99,777

Notes:

(1)Represents the reserves of True Energy Inc. as at December 31, 2004.

(2)Includes the acquisition of Meridian Energy Corporation effective March 15, 2005 and the acquisition of TKE Energy Inc. effective November 2, 2005 pursuant to the 2005 Arrangement.

(3)Includes the disposition by True Energy Inc. of certain of its oil and gas assets to Vero Energy Inc. under the 2005 Arrangement.

(4)We do not have any synthetic oil or other products from non-conventional oil and gas activities.

(5)Natural gas liquids are not included in the reconciliation.

Net Revenue Reconciliation

The following table sets out a reconciliation of our net revenue as at January 1, 2005 compared to December 31, 2005 based on constant prices and costs and proved reserves:

FUTURE NET REVENUE (discounted at 10%/year)
PERIOD AND FACTOR
2005 ($000s)	After Tax		Before Tax
Estimated Future Net Revenue at Beginning of Year(1)	105,713		133,648
Sales and Transfers of Oil and Gas Produced, Net of Production Costs and Royalties(2)	(96,074	)	(96,074	)
Net Change in Prices, Production Costs and Royalties Related to Future Production(3)	82,121		82,121
Changes in Previously Estimated Development Costs Incurred During the Period(4)	76,257		76,257
Changes in Estimated Future Development Costs(5)	(66,161	)	(66,161	)
Extensions and Improved Recovery(6)	58,283		58,283
Discoveries	14,751		14,751
Acquisitions of Reserves(6)	183,334		183,334
Dispositions of Reserves(6)	(14,237	)	(14,237	)
Net Change Resulting from Revisions in Quantity Estimates	(590	)	(590	)
Accretion of Discount(7)	13,365		13,365
Net Change in Income Taxes(8)	20,630		—
All other changes(9)	7,866		561
Estimated Future Net Revenue at End of Year	385,257		385,257

Notes:

(1)Represents the reserves of True Energy Inc. as of December 31, 2004.

(2)Corporation actual before income taxes, excluding general and administrative expenses.

(3)The impact of changes in prices and other economic factors on future net revenue.

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(4)Actual capital expenditures relating to the exploration, development and production of oil and gas reserves.

(5)The change in forecast development costs for the properties evaluated at the beginning of the period.

(6)End of period net present value of the related reserves.

(7)Estimated as 10% of the beginning of period net present value.

(8)The difference between forecast income taxes at beginning of period and the actual taxes for the period plus forecast income taxes at the end of period.

(9)Includes change due to revised production profiles, development timing, operating costs, royalty rates, actual price received in 2005 versus forecast.

Additional Information Relating to Reserves Data

Proved Undeveloped Reserves

A total of 6,205 Mmcf of natural gas, 334 Mbbl of liquid/medium oil, 488 Mbbl of heavy oil and 122 Mbbl of NGL’s were assigned as gross proved undeveloped reserves, representing approximately 11% of our total proved reserves.

These reserves are generally associated with infill drilling locations supported by offset well data and anticipated within a two year time frame, the majority in 2006.

Probable Undeveloped Reserves

A total of 29,042 Mmcf of natural gas, 1,521 Mbbl of oil and 370 Mbbl of NGL’s were assigned as gross probable undeveloped reserves, representing approximately 57% of our total probable reserves or 22% of total proved plus probable reserves.

The probable undeveloped reserves are generally assigned to drilling locations adjacent to proved reserves; additional probable reserves for wells assigned proved undeveloped reserves is also included. The development of most of these reserves is anticipated within two years.

Significant Factors or Uncertainties

While we do not anticipate any significant economic factors or significant uncertainties will affect any particular components of the reserves data, the reserves can be affected significantly by fluctuations in product pricing, capital expenditures, operating costs, royalty regimes and well performance that are beyond our control (see “Risk Factors”).

Future Development Costs

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

	Forecast Prices and Costs		Constant Prices and Costs
Year	Proved Reserves	Proved Plus Probable Reserves	Proved Reserves
	($000s)	($000s)	($000s)
2006	30,559	56,627	30,529
2007	4,489	9,569	4,388
2008	618	789	565
2009	38	142	11
2010	983	1,315	895
Thereafter	1,141	3,289	1,169
Total: Undiscounted	37,828	71,731	37,557
Total: Discounted at 10%/year	34,627	64,849	34,387

We expect to be able to fund our capital expenditure program, including estimated future development costs, using cash flow from operations and available credit facilities. Equity financing may also be used to fund operations. If cash flows are other than projected, capital expenditure levels will be adjusted. Our practices of

15

continually monitoring spending opportunities in comparison to expected cash flow levels allow for adjustments to the capital program as required.

We do not expect that the costs of funding our capital expenditures will have a material effect on the economics of the programs.

Other Oil and Gas Information

Principal Properties

The Trust’s properties are located onshore within the Western Canadian Sedimentary Basin in five regions ranging from northeast British Columbia to southeast Saskatchewan. Our principal properties are described below as at December 31, 2005. Unless otherwise indicated, production stated is approximate current production based on field estimates, received in respect of our working interest share before deduction of royalties. Unless otherwise specified, gross and net acres are as at December 31, 2005.

Peace River Arch Region

This region includes properties in northeast British Columbia and northwest Alberta. Production of approximately 500 BOE/d is primarily light oil and natural gas produced from depths of 500 to 2,800 metres. We hold 15,992 acres (6,314 net acres) of developed land and 27,437 acres (10,073 net acres) of undeveloped land in this region.

Gage & Gage North Area

Gage is located approximately five kilometres northwest of Fairview, Alberta. True has interests in a total of 5,432 acres (2,011 net acres) of developed land and 7,597 acres (3,799 net acres) of undeveloped land.

Production at Gage is from the Montney formation (oil and solution gas) and the Gething formation (gas). Current production is 200 BOPD and 630 Mcf/d.

The area saw active development of gathering and processing infrastructure in 2005 with the construction of an oil battery, gas conservation and related pipelines, reducing operating costs and increasing gas sales. Non producing reserves in the area primarily relate to a pool delineation application for concurrent production of gas and oil presently before the regulatory authority. Down spacing has been approved for the area; implementation awaits the delineation ruling.

Meekwap

Located approximately 200 kilometres northwest of Edmonton, Alberta, True has a 10% working interest in the Meekwap
D-2A Unit No. 1, a 0.875% net profits interest in Unit production and working interests varying from 5% to 50% in non-unitized lands. Meekwap is operated by a third party. The property consists of 8,800 acres (1,393 net acres) of developed land and 2,560 acres (1,100 net acres) of undeveloped land.

Current production is approximately 70 BOE/d of light oil (60 BOPD) with solution gas.

Northeast Alberta Region

True has interests in 183,987 acres (103,342 net acres) of developed land and 246,137 acres (141,451 net acres) of undeveloped land northeast and northwest of Edmonton. Production of 1,600 BOE/d is primarily natural gas. Well depths are shallow, ranging from 200 to 1,400 metres.

Saddle Lake and Whitefish Lake

This natural gas property is located in the vicinity of St. Paul, Alberta, on the Saddle Lake First Nation and the Whitefish Lake First Nation northeast of Edmonton in two blocks about 30 kilometres apart. True holds a 50% interest in a joint venture with Keyano Pimee Exploration Company Ltd., a company that is owned by the Saddle

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Lake and Whitefish Lake First Nations. The leases on the joint venture lands provide for payment of royalties to Indian Oil and Gas Canada (“IOGC”). The royalties payable to IOGC are Alberta Crown equivalent, calculated using the rules and regulations applicable to Alberta Crown royalties.

Production totals 3.7 MMcf/d (610 BOE/d) from wells ranging in depth from 550 to 700 metres. The area features multiple productive horizons that include some non producing reserves which are deferred until lower zones in existing wells are depleted. An optimization program will involve accessing non-producing horizons and optimization of down hole equipment to improve production. True operates all the wells and three compressor/dehydrator stations as well as three field booster compressors. A minor amount of production is compressed at a third-party compressor. The property is comprised of 31,360 acres (15,552 net acres) of developed land and 43,418 acres (21,709 net acres) of undeveloped land.

Thorhild

Thorhild is another multi zone shallow gas property, located approximately 30 kilometres northeast of Edmonton, Alberta. True holds interests in 59,840 acres (33,533 net acres) of developed land and 26,720 acres (20,193 net acres) of undeveloped land.

All production from the Thorhild area is sweet natural gas. Wells are generally less than 900 metres in depth; current production is about 2.1 MMcf/d. Our interest in the property includes ownership in three compressor stations. Development activities include recompletion in shallower zones as deeper horizons decline and tie in of step out drilling that took place in 2005; some of the shallower zones and the wells awaiting tie in have been assigned non producing reserves.

Successful well optimization work in early 2006 will continue along with tie in of new wells.

West Central Alberta Region

This diverse region extends from east of Calgary to west of Edmonton parallel to the Rocky Mountains. Both light oil and gas rich in natural gas liquids are produced from wells ranging from shallow (500 metres) to deep (4,000 metres). Production totals 3,300 BOE/d. Land holdings are 70,249 acres (36,762 net acres) of developed land and 65,911 acres (33,464 net acres) of undeveloped land.

Brazeau

This new area, located approximately 50 kilometres southwest of Drayton Valley, Alberta, is emerging as an important property for the Trust. Land holdings are 4,480 acres (2,044 net acres) of developed land and 8,160 acres (4,544 net acres) of undeveloped land. Initial drilling and production infrastructure construction commenced in 2005 and is continuing in 2006. Current production is 400 BOE/d of gas and NGL and growing as newer wells are being connected. Principal formations are the Rock Creek and Notikewin at depths of 2,700 metres and 2,450 metres respectively. Production is routed to existing third party facilities in the area for processing.

Willesden Green

The Willesden Green area is located approximately forty-five kilometres north of Rocky Mountain House, Alberta. This was the main asset coming from True’s acquisition of Meridian in March, 2005. Our largest property produces liquids-rich natural gas from four deep zones (1,800 to 2,800 meters), including the Cardium, Notikewin, Ellerslie and Rock Creek, and sweet dry natural gas from five shallower horizons (300 to 1,200 meters), including the Paskapoo, Ardley, Horseshoe Canyon, Edmonton and Belly River. True has 17,120 gross (9,245 net) acres of developed land and 14,720 gross (7,897 net) acres of undeveloped land. Drilling will continue in 2006 for primarily Rock Creek and Notikewin targets, with secondary zone potential.

Active drilling in 2005 continues into this year along with construction of pipelines to serve non producing wells. Both high pressure and low pressure systems are installed to produce deep and shallow zones effectively. True owns interests in and operates three compressor stations in the area. This liquids rich gas is processed to pipeline specification at third party plants.

Current production is 2,100 BOE/d, 77% natural gas, the majority of which is operated by True.

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West Central Saskatchewan Region

This area includes the properties on which True Energy was founded and remains our most productive area. Most of our properties in this region are in an east – west oriented band approximately 110 kilometres in length located between Kindersley and Kerrobert, Saskatchewan. The majority of the production is natural gas, however this region also contains all of our heavy oil and some light oil, in total approximately 6,200 BOE/d. Wells depths range down to 1,200 metres deep and are spread over 103,260 acres (81,498 net acres) of developed land and 182,725 acres (155,645 net acres) of undeveloped land.

Smiley

The Smiley property, located about 35 kilometres northwest of Kindersley, produces natural gas, light and heavy oil. The property consists of 12,266 gross (9,372 net) acres of developed land and 13,455 gross (11,019 net) acres of undeveloped land. Targeted formations in the Smiley area include the Viking, Colony, Waseca, Detrital and Bakken zones at depths of 700 to 900 meters.

True owns and operates the main facility for compressing, dehydrating and sweetening natural gas and solution gas in the Smiley area and a heavy oil processing facility was constructed in 2005. Drilling success in the northwest portion of the field has resulted in the need to expand this battery, planned for 2006. True also has a 25% working interest in the Loverna oil and gas facility, which has oil processing, water disposal, compression, dehydration and liquids extraction capabilities.

Current production of 1,850 BOE/d is 61% heavy oil, 1% light oil and 38% natural gas. Continuation of heavy oil drilling is forecast for 2006.

Coleville Driver

The Coleville Driver area, located approximately 25 kilometres north-west of Kindersley produces primarily natural gas from shallow 700 to 825 metre Bakken and Mannville zones. Sales currently average 6.8 MMcf/d of natural gas and 50 Bbls/d of heavy oil, or 1,180 BOE/d. Three non producing wells are forecast to be tied in by 2007. The property consists of 21,532 gross (16,449 net) acres of undeveloped land, and 18,820 gross (16,646 net) acres of developed land.

Coleville Driver facilities include a wholly owned and operated natural gas compressor station with dehydration and sweetening capabilities.

True acquired its working interests in the Coleville Driver area through a combination of acquisitions, farmins, and drilling operations. An additional gas well is planned for 2006.

Kerrobert

Kerrobert is located approximately 40 kilometres north of the town of Kindersley. The property consists of 4,351 gross (2,552 net) developed acres and 8,736 gross (7,094 net) undeveloped acres of land. Kerrobert currently produces 260 Bbl/d of Viking zone light oil and 1,300 Bbl/day of heavy oil from a McLaren channel.

Up to five additional horizontal heavy oil wells are possible in 2006 to further develop the McLaren channel. Longer term, the McLaren channel wells are candidates for steam assisted gravity drainage (“SAGD”) enhanced recovery technology, which could significantly increase the overall recovery of the heavy oil from current levels.

Dodsland

The Dodsland area is located approximately 30 kilometres north of Kindersley. The property consists of 49,437 gross (43,453 net) developed acres and 105,367 gross (97,455 net) undeveloped acres.

The Dodsland Viking Gas Unit (89%) gas processing facilities compress, dehydrate, sweeten and extract natural gas liquids for unit and non-unit gas production from the Viking and Bakken Formations. A second 100% owned gas processing facility with compression, dehydration and liquids extraction capabilities was built to handle

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new Viking gas development wells in 2004 and in 2005, a third gas processing facility with compression, dehydration and natural gas liquids extraction was constructed to serve the Viking gas development at Stranraer in the eastern part of the field.

The Dodsland property produces primarily natural gas, currently 7.8 MMcf/d. Up to 20 Viking gas downspacing locations are planned for 2006.

Southeast Saskatchewan Region

This region, located in the southeast corner north of Estevan, produces about 400 Bbl/d of light oil from from the Kisbey and Frobisher formations. Landholdings are 2,787 gross (1,002 net) developed acres and 400 gross (160 net ) undeveloped acres.

Hartaven

The Hartaven property, approximately 130 kilometres southeast of Regina, produces most of the region’s oil, currently about 400 Bbl/d. A number of infill horizontal locations are available, continuing the program carried out in 2005. The field is served by an oil treating battery and water disposal pumps and wells, in which the Trust has a 44% working interest.

The Hartaven property is comprised of 1,806 gross (919 net) developed acres and 400 gross (160 net) undeveloped acres.

Oil and Gas Wells

The following table sets forth the number and status of wells in which we have a working interest as at December 31, 2005.

	Oil Wells				Natural Gas Wells
	Producing		Non-Producing		Producing		Non-Producing
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Saskatchewan	753	132.8	56	29.6	180	136.1	44	30.1
Alberta	135	56.1	108	31.4	355	131.2	143	72.3
British Columbia	5	0.9	22	4.3	12	3.3	6	1.7
Total	893	189.8	186	65.3	547	270.6	193	104.1

Properties with No Attributed Reserves

The following table sets out our developed and undeveloped land holdings as at December 31, 2005(1).

	Developed Acres		Undeveloped Acres		Total Acres
	Gross	Net	Gross	Net	Gross	Net
Alberta	290,992	121,886	354,292	186,846	645,284	308,732
British Columbia	16,799	4,641	10,085	3,280	26,884	7,921
Saskatchewan	120,708	82,500	185,868	155,805	306,576	238,305
Total	428,499	209,027	550,245	345,930	978,744	554,957

(1)May not add due to rounding

We expect that rights to explore, develop and exploit 71,509 net acres of our undeveloped land holdings may expire by December 31, 2006. We plan to drill or submit application to continue selected portions of the above acreage.

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Forward Contracts and Marketing

Our commodity marketing strategy is to sell production in the spot market, complemented from time to time by price risk management instruments. As at December 31, 2005, we did not have any commodity price swaps or fixed price sales contracts in place other than a put option on 1,300 bbl/day of WTI with a strike price (floor) of US $40/Bbl, which expired December 31, 2005.

Subsequent to the fiscal year ending December 31, 2005 the Trust has entered into a costless collar arrangement on 2000 bbl/d of WTI with a Canadian chartered bank for the period commencing April 1, 2006 through December 31, 2006. The floor price of the collar is US $58.00/bbl and the ceiling price is US $69.35/bbl.

Additional Information Concerning Abandonment and Reclamation Costs

We have included the estimated future well abandonment costs for existing and future reserves wells in the economic forecasts. We use our historical cost information on an area by area basis as the means for estimating the future abandonment and reclamation costs. When this information is not available, the estimate is determined with reference to appropriate regulatory standards and requirements. Additional abandonment and reclamation costs associated with non-reserves wells, reclamation costs for wells with reserves and facility abandonment and reclamation expenses have not been included in the reserve report analysis.

In the GLJ Report, the number of net oil and gas wells for which revenues and costs, including future well abandonment costs, varies by year depending on when wells commence and end production. The total amount of such costs, all of which is deducted in the total proved forecast price and cost reserve report, before estimated salvage value, is $14,031,000 ($6,389,000 discounted at 10%). In the constant prices and costs total proved reserve report, the total of such costs, fully deducted, is $11,949,000 ($5,450,000 discounted at 10%). In the next three financial years, these costs are as follows:

Forecast Prices and Costs (Total Proved)

		Abandonment
Year	Net Wells	Costs
		($000’s)
2006		539
2007		801
2008		1,137
Subtotal		2,477
Remainder		11,554
Total	612	14,031
Total, discounted at 10%		6,389

Constant Prices and Costs (Total Proved)

		Abandonment
Year	Net Wells	Costs
		($000’s)
2006		579
2007		694
2008		1,010
Subtotal		2,283
Remainder		9,666
Total	612	11,949
Total, discounted at 10%		5,450

At December 31, 2005, the estimated total undiscounted amount required to settle the asset retirement obligations (being abandonment and reclamation costs for net producing and shut-in wells and facilities) of the Trust is approximately $28.4 million, of which $10.5 million has been recorded in various fiscal periods. The incremental costs for future site restoration for surface leases and pipelines, reduced by the estimated salvage values for all including wells, is estimated to be nominal.

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Included in the GLJ Report (constant prices and costs) for 2006 are 460.5 net producing wells, the same number of net producing wells utilized in determining the total future site restoration costs for net producing and shut-in wells above.

Tax Horizon

As a result of the Trust’s tax efficient structure, annual taxable income is transferred from our operating entities to the Trust and from the Trust to Unitholders. Therefore, it is expected that no income tax liability will be incurred by the Trust for so long as the Trust maintains its current structure, based on existing legislation. True Energy also should not be taxable so long as the interest on the Notes held by the Trust, royalty payments under the NPI and other expenses in True Energy are sufficient to reduce taxable income to nil. We do not expect True Energy to be required to pay income taxes for the 2006 financial year.

Capital Expenditures

The following table summarizes capital expenditures (net of incentives and net of certain proceeds and including capitalized general and administrative expenses) related to our assets and activities for the year ended December 31, 2005 ($000s):

Meridian – proved corporate acquisition	$	183,796
TKE Energy Trust – proved corporate acquisition	292,082
Property acquisition costs
Proved properties	166
Undeveloped properties	8,667
Exploration costs	23,965
Development costs	82,962
Dispositions	(26,892		)
Corporate Assets	324
Total	$	565,071

Exploration and Development Activities

The following table sets forth the gross and net exploratory and development wells in which True Energy Inc. participated during the year ended December 31, 2005.

	Exploratory Wells		Development Wells
	Gross	Net	Gross	Net
Light and Medium Oil	—	—	14.0	8.6
Natural Gas	20.0	15.1	82.0	63.8
Heavy Oil	—	—	15.0	13.5
Service	—	—	2.0	2.0
Dry	3.0	2.1	5.0	5.0
Total	23.0	17.2	118.0	92.9

The following table sets forth the gross and net exploratory and development wells in which TKE Energy Inc. participated during the period from January 1, 2005 to November 2, 2005, being the effective date of the completion of the 2005 Arrangement:

	Exploratory Wells		Development Wells
	Gross	Net	Gross	Net
Light and Medium Oil	—	—	6.0	3.7
Natural Gas	4.0	2.4	7.0	2.1
Heavy Oil	—	—	1.0	0.5
Service	—	—	—	—
Dry	3.0	1.3	1.0	0.4
Total	7.0	3.7	15.0	6.7

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For details on the important current and likely exploration and development activities during 2006, see “Statement of Reserves Data and Other Oil and Gas Information – Other Oil and Gas Information – Principal Properties”.

Production Estimates

The following tables sets out the volume of our production estimated for the year ended December 31, 2006, which is reflected in the estimate of future net revenue disclosed in the Forecast Price tables contained under “Disclosure of Reserves Data” above.

FORECAST PRICES AND COSTS

	Light And Medium Oil		Heavy Oil		Natural Gas		Natural Gas Liquids		Total
Reserves Category	Gross	Net	Gross	Net	Gross	Net	Gross	Net	Gross	Net
	(Bbls/d)	(Bbls/d)	(Bbls/d)	(Bbls/d)	(Mcf/d)	(Mcf/d)	(Bbls/d)	(Bbls/d)	(BOE/d)	(BOE/d)
Total Proved	1,252	1,112	2,548	2,068	43,919	33,154	519	347	11,637	9,051
Total Proved Plus
Probable	1,384	1,220	2,927	2,350	50,726	38,162	585	393	13,350	10,322

CONSTANT PRICES AND COSTS

	Light And Medium Oil		Heavy Oil		Natural Gas		Natural Gas Liquids		Total
Reserves Category	Gross	Net	Gross	Net	Gross	Net	Gross	Net	Gross	Net
	(Bbls/d)	(Bbls/d)	(Bbls/d)	(Bbls/d)	(Mcf/d)	(Mcf/d)	(Bbls/d)	(Bbls/d)	(BOE/d)	(BOE/d)
Total Proved	1,251	1,111	2,548	2,086	43,934	33,208	519	348	11,639	9,078
Total Proved Plus
Probable	1,384	1,220	2,927	2,375	50,741	38,236	585	394	13,352	10,361

No individual property accounts for more than 20% of the estimated production disclosed.

Production History

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

	Quarter Ended
	2005
	Dec. 31	Sept. 30	June 30	Mar. 31
Average Daily Production(1)
Light and Medium Crude Oil (Bbls/d)	1,061	641	447	206
Heavy Oil (Bbls/d)	2,265	2,112	1,935	1,982
Gas (Mcf/d)	42,509	33,455	34,705	26,308
NGLs (Bbls/d)	373	340	306	146
Combined (BOE/d)	10,784	8,669	8,472	6,718
Average Price Received (after hedge)
Light and Medium Crude Oil ($/Bbl)	61.57	68.83	63.07	53.97
Heavy Oil ($/Bbls)	30.53	43.96	31.49	22.16
Gas ($/Mcf)	11.88	9.81	7.69	7.11
NGLs ($/Bbls)	57.43	54.54	45.89	50.31
Combined ($/BOE)	61.50	55.81	43.66	37.12

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	Quarter Ended
	2005
	Dec. 31	Sept. 30	June 30	Mar. 31
Royalties Paid
Light and Medium Crude Oil ($/Bbls)	12.93	9.83	11.63	12.38
Heavy Oil ($/Bbls)	6.56	11.34	4.75	3.92
Gas ($/Mcf)	3.16	2.62	2.17	2.00
NGLs ($/Bbls)	13.90	10.19	6.13	13.40
Combined ($/BOE)	15.60	14.00	10.82	9.65
Operating Expenses
Light and Medium Crude Oil ($/Bbls)	10.57	10.34	6.81	10.62
Heavy Oil ($/Bbls)	8.86	5.79	7.76	6.06
Gas ($/Mcf)	1.16	1.23	0.86	0.91
NGLs ($/Bbls)	5.49	5.50	2.95	4.37
Combined ($/BOE)	7.66	7.15	5.75	5.76
Netback Received before Transportation
Light and Medium Crude Oil ($/Bbl)	38.07	48.66	44.63	30.97
Heavy Oil ($/Bbls)	15.11	26.83	18.98	12.18
Gas ($/Mcf)	7.56	5.96	4.66	4.20
NGLs ($/Bbls)	38.04	38.85	36.81	32.54
Combined ($/BOE)	38.24	34.66	27.09	21.71
Transportation Costs
Light and Medium Crude Oil ($/Bbls)	2.09	0.76	0.04	0.02
Heavy Oil ($/Bbls)	1.75	1.71	1.23	0.97
Gas ($/Mcf)	0.19	0.18	0.15	0.17
NGLs ($/Bbls)	0.17	—	—	—
Combined ($/BOE)	1.32	1.18	0.91	0.95
Netback Received after Transportation (2)
Light and Medium ($/Bbls)	38.20	47.90	44.59	30.95
Heavy Oil ($/Bbls)	13.36	25.12	17.75	11.21
Gas ($/Mcf)	7.37	5.78	4.51	4.03
NGLs ($/Bbls)	37.87	38.85	36.81	32.54
Combined ($/BOE)	36.92	33.48	26.18	20.76

Notes:

(1)Before deduction of royalties.

(2)Netbacks are calculated by subtracting royalties, operating and transportation costs from revenues.

The following table indicates average daily gross production from important fields in respect of our assets for the year ended December 31, 2005:

	Light and Medium Crude Oil	Heavy Oil	Condensate	Gas	NGLs	BOE
	(Bbls/d)	(Bbls/d)	(Bbls/d)	(Mcf/d)	(Bbls/d)	(BOE/d)
Peace River Arch Region
Gage & Gage North Area, Alberta	36.3	—	—	124.0	2.7	59.6
Meekwap, Alberta	12.0	—	—	13.1	2.3	16.5
Minor Properties	68.1	—	10.6	1,349.8	7.5	311.2
	116.4	—	10.6	1,486.9	12.5	387.3

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	Light and Medium Crude Oil	Heavy Oil	Condensate	Gas	NGLs	BOE
	(Bbls/d)	(Bbls/d)	(Bbls/d)	(Mcf/d)	(Bbls/d)	(BOE/d)
Northeast Alberta Region
Saddle Lake & Whitefish Lake	—	—	—	656.8	—	109.5
Thorhild	0.2	—	—	207.0	—	34.7
Minor Properties	0.1	—	1.2	3,368.7	4.2	567.0
	0.3	—	1.2	4,232.5	4.2	711.2
West Central Alberta Region
Brazeau	1.2	—	—	8.8	—	2.6
Willesden Green	118.0	—	14.6	8,951.1	243.5	1,867.9
Minor Properties	87.0	—	19.5	1,793.2	21.8	427.2
	206.2	—	34.1	10,753.1	265.3	2,297.8
West Central Saskatchewan Region
Smiley	19.6	870.8	—	4,322.3	—	1,610.6
Coleville Driver	—	41.7	—	7,040.4	—	1,215.1
Kerrobert	90.3	1,090.4	0.2	20.8	1.6	1,186.0
Dodsland	39.9	—	1.9	5,773.6	8.3	1,012.5
Minor Properties	—	71.5	0.1	657.0	—	181.1
	149.8	2,074.4	2.2	17,814.1	10.0	5,205.3
Southeast Saskatchewan Region
Hartaven	67.9	—	—	—	—	67.9
Minor Properties	2.5	—	—	—	—	2.5
	70.4	—	—	—	—	70.4
TOTALS	543.1	2,074.4	48.1	34,286.6	292.0	8,672.0

Crude oil production from our assets for the year ended December 31, 2005 was 6% light and medium quality crude oil (25° API or greater) and 24% heavy crude oil (less than 15° API).

For the twelve months ended December 31, 2005, approximately 27% of gross revenue from our assets was derived from crude oil and natural gas liquids production and 73% was derived from natural gas production.

The above information is data for 2005, including acquired assets and wells drilled from the date acquired or commencement of production as the case may be.

ADDITIONAL INFORMATION RESPECTING THE TRUST

The following is a summary description of certain provisions of the Trust Indenture and does not purport to be complete and is subject to, and is qualified in its entirety by, reference to the Trust Indenture. A copy of the Trust Indenture is available on SEDAR at www.sedar.com.

Trust Units

An unlimited number of Trust Units may be created and issued pursuant to the Trust Indenture.

Voting

Each Trust Unit shall entitle the holder thereof to one vote at all meetings of the holders of Trust Units.

Distributions

Each Trust Unit represents an equal fractional undivided beneficial interest in any distribution from the Trust (whether of net income, net realized capital gains or other amounts) and in any net assets of the Trust in the event of termination or winding-up of the Trust. All Trust Units shall rank among themselves equally and rateably without discrimination, preference or priority.

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Pre-Emptive Rights, Redemption and Conversion

Each Trust Unit is not subject to pre-emptive or conversion rights and entitles the holder thereof to require the Trust to redeem any or all of the Trust Units held by such holder. See “Redemption Right”.

Nature of Trust Units

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

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

Special Voting Rights

In order to allow the Trust flexibility in pursuing corporate acquisitions, the Trust Indenture allows for the creation of Special Voting Rights entitling the holders thereof to such number of votes at meetings of Unitholders as may be prescribed by True Energy and as are set out in any applicable voting and exchange trust agreement in respect of the Special Voting Rights and also have such other rights or limitations and may be issued on such terms and may take such form as True Energy may determine and as are set out in the applicable voting and exchange trust agreement. Special Voting Rights will enable the Trust to provide voting rights to holders of Exchangeable Shares and, in the future, to holders of other exchangeable shares that may be issued by True Energy or other subsidiaries of the Trust in connection with other exchangeable share transactions.

An unlimited number of Special Voting Rights may be created and issued pursuant to the Trust Indenture.  A single Special Voting Unit was issued to the Voting and Exchange Trust Agreement Trustee for the benefit of the holders of the Exchangeable Shares issued in connection with the 2004 Arrangement and which entitles the holders of the Exchangeable Shares to instruct the Voting and Exchange Trust Agreement Trustee to vote a number of votes in respect of each Exchangeable Share equal to the number of Trust Units issuable at the applicable record date in respect of each Exchangeable Share held. Holders of Special Voting Units shall not be entitled to any distributions of any nature whatsoever from the Trust or have any beneficial interest in any assets of the Trust upon its termination.

Trust Unitholder Limited Liability

The Trust Indenture provides that no Unitholder, in its capacity as such, shall incur or be subject to any liability in contract or in tort or of any other kind whatsoever to any person in connection with the properties and assets of the Trust or the obligations or the affairs of the Trust or with respect to any act performed by the Trustee or by any other person pursuant to the Trust Indenture or with respect to any act or omission of the Trustee or any other person in the performance or exercise, or purported performance or exercise, of any obligation, power, discretion or authority conferred upon the Trustee or such other person thereunder or with respect to any transaction entered into by the Trustee or by any other person pursuant to the Trust Indenture. Pursuant to the Trust Indenture, no Unitholder shall be liable to indemnify the Trustee or any such other person with respect to any such liability or liabilities incurred by the Trustee or by any such other person or persons or with respect to any taxes payable by the Trust or by the Trustee or by any other person on behalf of or in connection with the Trust. Notwithstanding the foregoing, to the extent that any Unitholders are found by a court of competent jurisdiction to be subject to any such liability, such liability shall be enforceable only against, and shall be satisfied only out of, the properties and assets of the Trust, and the Trust (to the extent of the properties and assets of the Trust) is liable to, and shall indemnify and save harmless any Unitholder against any costs, damages, liabilities, expenses, charges or losses suffered by any Unitholder from or arising as a result of such Unitholder not having any such limited liability.

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The Trust Indenture provides that every written contract entered into by or on behalf of the Trust, whether by the Trustee, the Administrator or otherwise, shall (except as the Trustee or the Administrator may otherwise determine) include a provision to the effect that such obligation will not be binding upon Trust Unitholders personally. Notwithstanding the terms of the Trust Indenture, Trust Unitholders may not be protected from liabilities of the Trust to the same extent a shareholder is protected from the liabilities of a corporation. Personal liability may also arise in respect of claims against the Trust (to the extent that claims are not satisfied by the Trust) that do not arise under contracts, including claims in tort, claims for taxes and possibly certain other statutory liabilities. The possibility of any personal liability to Trust Unitholders of this nature arising is considered unlikely in view of the fact that the primary activity of the Trust is to hold securities, and all of the business operations of the Trust are carried on by True Energy directly or indirectly. In addition, the Income Trust Liability Act (Alberta) was proclaimed in Alberta on June 30, 2004. The Income Trust Liability Act (Alberta) provides that the beneficiary of a trust that is (a) created by a trust instrument governed by the laws of Alberta, and (b) a reporting issuer as defined in the Securities Act (Alberta), is not liable as a beneficiary for any act, default, obligation or liability of the trustee.

The activities of the Trust and the Administrator are 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 to the Trust Unitholders for claims against the Trust including by obtaining appropriate insurance, where available, for the operations of True Energy and having contracts signed by or on behalf of the Trust include a provision that such obligations are not binding upon Trust Unitholders personally.

Issuance of Trust Units

The Trust Indenture provides that Trust Units, including rights, Special Voting Rights, warrants, special warrants, subscription receipts, instalment receipts, exchangeable securities or other securities to purchase, to convert into, redeem for, or to exchange into Trust Units, may be created, issued, sold and delivered on such terms and conditions and at such times as the Administrator may determine. The Trust Indenture also provides that the Administrator may authorize the creation and issuance of debentures, notes and other evidences of indebtedness of the Trust, which debentures, notes or other evidences of indebtedness may be created and issued from time to time on such terms and conditions to such persons and for such consideration as the Administrator may determine.

Distributions on Trust Units

The Trustee may, upon recommendation of the Administrator, declare payable to the Unitholders all or any part of the net income of the Trust earned from interest income on the Notes, from the income generated under the NPI Agreement and from any dividends paid on the common shares of True Energy, less all expenses and liabilities of the Trust due and accrued and which are chargeable to the net income of the Trust. In addition, Unitholders may, at the discretion of the board of directors of True Energy, receive distributions in respect of prepayments of principal on the Notes made by True Energy to the Trust before the maturity of the Notes. The Trust may also invest in or acquire royalties, and amounts paid thereon may also constitute part of the net income of the Trust available for distribution to Unitholders.

Cash distributions are payable on a monthly basis to Unitholders of record on the last business day of each month. The board of directors of True Energy on behalf of the Trust reviews the Trust’s distribution policy from time to time. The actual amount distributed will be dependent on various factors including the commodity price environment and is at the discretion of the board of directors of True Energy. See “Distributions to Unitholders”.

Pursuant to our credit facilities, the Trust is restricted from making distributions to Unitholders in the following circumstances: (i) after the Trustee has received notice that a demand has been made under the credit facilities; (ii) after the Trustee has received notice of a default or event of default under the credit facilities or of the borrowings thereunder exceeding the borrowing base established from time to time by the lender; and (iii) if such distribution would result in a default or event of default under the credit facilities or would impair the ability of the Corporation to satisfy its obligations under the credit facilities.

Redemption Right

Trust Units are redeemable at any time on demand by the holders thereof upon delivery to the Trust of the certificate or certificates representing such Trust Units, accompanied by a duly completed and properly executed notice requiring redemption. Upon receipt of the notice to redeem Trust Units by the Trust, the holder thereof shall

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only be entitled to receive a price per Trust Unit (the “Market Redemption Price”) equal to the lesser of: (a) 90% of the “market price” of the Trust Units on the principal market on which the Trust Units are quoted for trading during the 10 trading day period commencing immediately after the date on which the Trust Units are tendered to the Trust for redemption; and (b) the closing market price on the principal market on which the Trust Units are quoted for trading on the date that the Trust Units are so tendered for redemption.

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

The Market Redemption Price payable by the Trust in respect of any Trust Units tendered for redemption during any calendar month shall be satisfied by way of a cash payment on the last day of the following month. The entitlement of Unitholders to receive cash upon the redemption of their Trust Units is subject to the limitation that the total amount payable by the Trust in respect of such Trust Units and all other Trust Units tendered for redemption in the same calendar month shall not exceed $250,000, provided that the Administrator may, in its sole discretion, waive such limitation in respect of any calendar month. If this limitation is not so waived, the Market Redemption Price payable in respect of Trust Units tendered for redemption in such calendar month shall be paid on the last day of the following month as follows: (a) firstly, by the Trust distributing the Notes or such series of promissory notes of the Corporation (“Other Notes”) as the Corporation may issue to the Trust in payment of the Notes, and (b) secondly, to the extent that the Trust does not hold Notes having a sufficient principal amount outstanding to effect such payment, by the Trust issuing its own promissory notes to the Unitholders who exercised the right of redemption having an aggregate principal amount equal to any such shortfall, which promissory notes (herein referred to as “Redemption Notes”) shall have terms and conditions substantially identical to those of the Notes and/or Other Notes.

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

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

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Non-Resident Unitholders

In order that we maintain our status as a “mutual fund trust” under the Tax Act, certain provisions of the Tax Act require that we not be established nor maintained primarily for the benefit of non-residents of Canada (“non-residents”). Accordingly, in order to comply with such provisions, the Trust Indenture contains restrictions on the ownership of Trust Units by Unitholders who are non-residents. In this regard, we shall, among other things, take all necessary steps to monitor the ownership of the Trust Units to carry out such intentions. If at any time we become aware that the beneficial owners of 40% or more of the Trust Units then outstanding are or may be non-residents or that such a situation is imminent, we shall take such action as may be necessary to carry out the forgoing intentions.

The Administrator may, from time to time or at anytime, require the Trustee or the transfer agent to make reasonable efforts to obtain declarations as to the jurisdictions in which beneficial owners of Trust Units are resident. If the Administrator becomes aware that non-residents are or may be the beneficial holders of 40% or more of the Trust Units then outstanding or that such situation is imminent or foreseeable, the Administrator may advise the Trustee to take certain actions including refusing to accept any subscription for Trust Units or to register or transfer Trust Units to a person unless such person provides an ownership declaration satisfactory to the Administrator that such persons are not non-residents. In addition, if the Administrator determines that 40% or more of the Trust Units are or appear to be beneficially owned by non-residents the Administrator may require the transfer agent to provide notice to such Unitholders, chosen in reverse order to the order of acquisition and registration or in such other manner as the Administrator considers practicable: (i) requiring them to sell their Trust Units to a person that is a non-resident or, if not so sold within the prescribed period, requiring the transfer agent on behalf of such Unitholders to sell such Trust Units to persons that are not non-residents and in the interim may suspend voting and distribution rights attached to such Trust Units; or (ii) advising such Unitholders that their Trust Units or a portion thereof will be redeemed in accordance with the redemption provisions attaching to such Units as if they had tendered such Units for redemption under the Trust Indenture, subject to certain modifications thereto as specified in the Trust Indenture. Additionally, the Trustee may take such other actions as specified by the Administrator to ensure compliance with the Tax Act and the provisions of the Trust Indenture in respect of non-resident ownership.

Meetings of Trust Unitholders

Special Meetings of Unitholders may be convened at any time and for any purpose by the Trustee and must be convened, except in certain circumstances, if requisitioned in writing by the holders of not less than 5 percent of the Trust Units then outstanding. A requisition must, among other things, state in reasonable detail the business purpose for which the meeting is to be called.

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

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

Exercise of Voting Rights attached to Shares of True Energy

The Trust Indenture prohibits the Trustee from voting the shares of True Energy with respect to: (i) the election of directors of True Energy; (ii) the appointment of auditors of True Energy; or (iii) the approval of True Energy’s financial statements, except in accordance with an ordinary resolution adopted at an annual or other meeting of Unitholders. The Trustee is also not permitted to vote, or cause to be voted, the shares of True Energy (or the shares of any other corporation of which all or at least 66 2/3% of the voting shares are owned by the Trust) to authorize:

(a)any sale, lease or other disposition of, or any interest in, all or substantially all of the assets of True Energy (or such other corporation), except in conjunction with an internal reorganization of

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the direct or indirect assets of True Energy (or such other corporation) as a result of which either True Energy (or such other corporation) or the Trust has the same, or substantially similar, interest, whether direct or indirect, in the assets as the interest, whether direct or indirect, that it had prior to the reorganization;

(b)any statutory amalgamation of True Energy (or such other corporation) with any other corporation or any amalgamation, merger or other transaction, as the case may be, of True Energy (or such other corporation) with any other entity, except in conjunction with an internal reorganization as referred to in paragraph (a) above;

(c)any statutory arrangement involving True Energy (or such other corporation), except in conjunction with an internal reorganization as referred to in paragraph (a) above;

(d)any amendment to the articles of True Energy (or such other corporation) to increase or decrease the minimum or maximum number of directors; or

(e)any material amendment to the articles of True Energy (or such other corporation) to change the authorized share capital or amend the rights, privileges, restrictions and conditions attaching to any class of True Energy’s shares (or such other corporation’s shares) in a manner which may be prejudicial to the Trust other than the creation of a class or series or additional classes or series of Exchangeable Shares;

without the approval of the Unitholders by special resolution (66 2/3% approval) at a meeting of Unitholders called for that purpose.

Take-over Bids

The Trust Indenture contains provisions to the effect that if a take-over bid is made for the Trust Units and not less than 90% of the Trust Units (other than Trust Units held at the date of the takeover bid by or on behalf of the offeror or associates or affiliates of the offeror) are taken up and paid for by the offeror, within the time provided in the take-over bid or within 120 days from the date the take-over bid is made (whichever shorter), the offeror will be entitled to acquire the Trust Units held by Unitholders who did not accept the takeover bid on the terms offered by the offeror upon compliance with the provisions relating thereto as provided in the Trust Indenture.

The Trustee

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

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

Liability of the Trustee

The Trustee, its directors, officers, employees, shareholders and agents shall not be liable to any Unitholder or any other person, in tort, contract or otherwise, in connection with any matter pertaining to the Trust or the property of the Trust arising from the exercise by the Trustee of any powers, authorities or discretion conferred under the Trust Indenture, including, without limitation, any action taken or not taken in good faith in reliance on any documents that are prima facie properly executed, any depreciation of, or loss to, the property of the Trust incurred by reason of the sale of any asset, any inaccuracy in any evaluation provided by any other appropriately

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qualified person, any reliance on any such evaluation, any action or failure to act of the Administrator or any other person to whom the Trustee has, with the consent of the Corporation, delegated any of its duties hereunder, or any other action or failure to act (including failure to compel in any way any former trustee to redress any breach of trust or any failure by the Administrator to perform its duties under or delegated to it under the Trust Indenture or any other contract), unless and to the extent such liabilities arise out of the gross negligence, wilful misconduct or fraud of the Trustee or any of its directors, officers, employees, shareholders or agents. If the Trustee has retained an appropriate expert, adviser or legal counsel with respect to any matter connected with its duties under the Trust Indenture, the Trustee may act or refuse to act based on the advice of such expert, adviser or legal counsel, and the Trustee shall not be liable for and shall be fully protected from any loss or liability occasioned by any action or refusal to act based on the advice of any such expert, adviser or legal counsel. In the exercise of the powers, authorities or discretion conferred upon the Trustee under the Trust Indenture, the Trustee is and shall be conclusively deemed to be acting as Trustee of the assets of the Trust and shall not be subject to any personal liability for any debts, liabilities, obligations, claims, demands, judgments, costs, charges or expenses against or with respect to the Trust or the property of the Trust. In addition, the Trust Indenture contains other customary provisions limiting the liability of the Trustee.

Amendments to the Trust Indenture

The provisions of the Trust Indenture may only be amended with the consent of Unitholders evidenced by special resolution; provided that the Trust Indenture may, without the consent of the Unitholders, be amended at any time for certain purposes, including:

(a)ensuring the Trust’s continuing compliance with applicable laws or requirements of any governmental agency or authority of Canada or of any province;

(b)ensuring that the Trust will obtain and maintain its status as a “unit trust” and a “mutual fund trust” under the Tax Act as from time to time amended or replaced and that the Trust Units will not be “foreign property” for purposes of the Tax Act;

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

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

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

Termination of the Trust

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

Unless the Trust is earlier terminated or extended by vote of the Unitholders, the Trustee shall commence to wind-up the affairs of the Trust on December 31, 2099. In the event that the Trust is wound-up, the Trustee will sell and convert into money the property of the Trust in one transaction or in a series of transactions at public or private sale and do all other acts appropriate to liquidate the property of the Trust, and shall in all respects act in accordance with the directions, if any, of the Unitholders in respect of termination authorized pursuant to the special resolution authorizing the termination of the Trust. Notwithstanding anything herein contained, in no event shall the Trust be wound up until the NPI and all other net profits interests or royalties, if any, shall have been disposed of. After paying, retiring or discharging, or making provision for the payment, retirement or discharge of, all known liabilities and obligations of the Trust and providing for indemnity against any other outstanding liabilities and

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obligations, the Trustee shall distribute the remaining part of the proceeds of the sale of the assets, together with any cash forming part of the property of the Trust, among the Unitholders in accordance with their pro rata share.

SHARE CAPITAL OF TRUE ENERGY INC.

True Energy is authorized to issue an unlimited number of common shares and an unlimited number of exchangeable shares issuable in series, of which an unlimited number of Exchangeable Shares are authorized. The Trust is the sole holder of the issued and outstanding common shares of True Energy and is also the sole holder of the Notes.

Common Shares

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

Exchangeable Shares

As at December 31, 2005 there were 788,558 Exchangeable Shares issued and outstanding which were, on such date, exchangeable for an aggregate of 454,888 Trust Units. The following is a summary description of the material provisions of the Exchangeable Shares and the related ancillary and indirect rights of holders of Exchangeable Shares under the terms of the Voting and Exchange Trust Agreement and the Support Agreement. This summary is qualified in its entirety by reference to the full text of: (i) the Exchangeable Share Provisions; (ii) the Support Agreement; and (iii) the Voting and Exchange Trust Agreement, copies of which provisions and agreements are filed on SEDAR at www.sedar.com.

Each Exchangeable Share is intended to have, to the extent possible, economic rights (including the right to have the Exchange Ratio adjusted to account for distributions paid to Unitholders) and voting attributes (through the benefit of the Special Voting Right granted to the Voting and Exchange Trust Agreement Trustee) equivalent to those of the Trust Units into which they are exchangeable from time to time. In addition, holders of Exchangeable Shares have the right to receive Trust Units at any time in exchange for their Exchangeable Shares on the basis of the Exchange Ratio in effect at the time of the exchange. Fractional Trust Units will not be delivered on any exchange of Exchangeable Shares. In the event that the Exchange Ratio in effect at the time of an exchange would otherwise entitle a holder of Exchangeable Shares to a fractional Trust Unit, the number of Trust Units to be delivered will be rounded to the nearest whole number of Trust Units. Holders of Exchangeable Shares do not receive cash distributions from the Trust or True Energy in respect of distributions on Trust Units. As at December 31, 2005, the Exchange Ratio was 0.57686. On each Distribution Payment Date, the Exchange Ratio increases, on a cumulative basis, in respect of the Distribution on such date by an amount which assumes the reinvestment of such Distribution in Trust Units at the then prevailing Current Market Price of a Trust Unit. The Exchange Ratio will be decreased in respect of any dividends paid on the Exchangeable Shares by an amount of such dividend by the then-prevailing Current Market Price of a Trust Unit.

Ranking

The Exchangeable Shares rank rateably with shares of any other series of exchangeable shares of True Energy and are entitled to a preference over the common shares and any other shares ranking junior to the exchangeable shares with respect to the payment of dividends and the distribution of assets in the event of the liquidation, dissolution or winding-up of True Energy, whether voluntary or involuntary, or any other distribution of the assets of True Energy among its shareholders for the purpose of winding up its affairs.

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Dividends

Holders of Exchangeable Shares rank in priority to the common shares and any class of shares of True Energy ranking junior to the Exchangeable Shares with respect to the payment of dividends, shall be entitled to receive and True Energy shall pay on each Exchangeable Share dividends if, as and when declared by the board of directors of True Energy. Such cash dividends shall be paid out of money of True Energy properly applicable to the payment of dividends. Holders of Exchangeable Shares are not entitled to receive dividends paid by the distribution of assets, shares or property of True Energy, other than cash.

Certain Restrictions

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

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

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

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

(d)amend the Articles or By-laws of True Energy in any manner that would effect the rights or privileges of the holders of Exchangeable Shares.

The above restrictions in (a), (b) and (c) shall not apply if all declared dividends on the outstanding Exchangeable Shares have been paid in full.

Liquidation or Insolvency of True Energy

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

Upon the occurrence of such an event, the Trust and any subsidiary of the Trust will each have the overriding right to purchase all but not less than all of the Exchangeable Shares then outstanding (other than Exchangeable Shares held by the Trust or any subsidiary of the Trust) at a purchase price per Exchangeable Share to be satisfied by the issuance or delivery, as the case may be, of that number of Trust Units equal to the Exchange Ratio as at the last business day prior to the date of such event and, upon the exercise of this right, the holders thereof will be obligated to sell such Exchangeable Shares to the Trust or any subsidiary of the Trust, as applicable. This right may be exercised by either the Trust or such subsidiary of the Trust.

Upon the occurrence of an Insolvency Event (as defined in the Voting and Exchange Trust Agreement) (an “Insolvency Event”), or in circumstances where Call Rights (as defined in the Exchangeable Share Provisions) (“Call Rights”) arise, but neither the Trust or any subsidiary of the Trust elect to exercise such call right, the Voting and Exchange Trust Agreement Trustee on behalf of the holders of the Exchangeable Shares will have the right to require the Trust or any subsidiary of the Trust to purchase any or all of the Exchangeable Shares then outstanding and held by such holders at a purchase price per Exchangeable Share to be satisfied by the issuance or delivery, as the case may be, of that number of Trust Units equal to the exchange ratio as at the last business day prior to the date of such event.

Automatic Exchange Right on Liquidation of the Trust

The Voting and Exchange Trust Agreement provides that in the event of liquidation of the Trust, as described below, the Trust or any subsidiary of the Trust will be deemed to have purchased all outstanding

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Exchangeable Shares and each holder of Exchangeable Shares will be deemed to have sold their Exchangeable Shares immediately prior to such liquidation event at a purchase price per Exchangeable Share to be satisfied by the issuance or delivery, as the case may be, of that number of Trust Units equal to the exchange ratio as at the last business day prior to the closing of such purchase and sale. For the purposes hereof, “trust liquidation event” means:

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

•the earlier of the Trust receiving notice of and the Trust otherwise becoming aware of any threatened or instituted claim, suit, petition or other proceedings with respect to the involuntary liquidation, dissolution or winding up of the Trust or to effect any other distribution of assets of the Trust among the Unitholders for the purpose of winding up its affairs in each case where the Trust has failed to contest in good faith such proceeding within 30 days of becoming aware thereof.

Retraction of Exchangeable Shares by Holders and Retraction Call Right

Subject to the Retraction Call Right of the Trust and any subsidiary of the Trust described below, a holder of Exchangeable Shares will be entitled at any time upon compliance with the provisions governing such retraction to require the Corporation to redeem any or all of the Exchangeable Shares held by such holder for a retraction price (the “Retraction Price”) per Exchangeable Share held equal to the value of that number of Trust Units equal to the exchange ratio as at the date of retraction (the “Retraction Date”), to be satisfied by the delivery of such number of Trust Units. Fractional Trust Units will not be delivered. Any amount payable on account of the Retraction Price that includes a fractional Trust Unit will be rounded to the nearest whole number of Trust Units. Holders of the Exchangeable Shares may request redemption by presenting and surrendering to the Corporation or the transfer agent for the Exchangeable Shares a certificate or certificates representing the number of Exchangeable Shares the holder desires to have redeemed, together with a duly executed retraction request and such other documents as may be reasonably required to effect the redemption of the Exchangeable Shares. Subject to extension as described below, the redemption will become effective on the Retraction Date unless such date would occur between any Distribution Record Date and the Distribution Payment Date that corresponds to such Distribution Record Date. In this case, the Retraction Date will occur on such Distribution Payment Date to ensure that the exchange ratio used in connection with such redemption is increased to account for the Distribution.

When a holder requests the Corporation to redeem the Exchangeable Shares, the Trust and any subsidiary of the Trust will have an overriding right (the “Retraction Call Right”) to purchase on the Retraction Date all but not less than all of the Exchangeable Shares that the holder has requested the Corporation to redeem at a purchase price per Exchangeable Share equal to the Retraction Price, to be satisfied by the delivery of that number of Trust Units equal to the exchange ratio as at the last business day prior to the retraction date. At the time of a retraction request by a holder of Exchangeable Shares, the Corporation will immediately notify the Trust and any subsidiary of the Trust as applicable. The Trust or subsidiary of the Trust must then advise the Corporation within two business days as to whether the Retraction Call Right will be exercised. A holder may revoke his or her retraction request at any time prior to the close of business on the last business day immediately preceding the Retraction Date, in which case the holder’s Exchangeable Shares will neither be purchased by the Trust or subsidiary of the Trust nor be redeemed by the Corporation. If the holder does not revoke his or her retraction request, the Exchangeable Shares that the holder has requested the Corporation to redeem will on the Retraction Date be purchased by the Trust or any subsidiary of the Trust or redeemed by the Corporation, as the case may be, in each case at a purchase price per Exchangeable Share equal to the Retraction Price.

In addition, a holder of Exchangeable Shares may elect to instruct the Voting and Exchange Trust Agreement Trustee to exercise the optional exchange right (the “Exchange Right”) to require the Trust or any subsidiary of the Trust to acquire such holder’s Exchangeable Shares in circumstances where neither the Trust nor any subsidiary of the Trust have exercised the Retraction Call Right. See “Additional Information Respecting the Corporation - Voting and Exchange Trust Agreement – Exchange Right”.

The Retraction Call Right may be exercised by either the Trust or any subsidiary of the Trust. If, as a result of solvency provisions of applicable law, the Corporation is not permitted to redeem all Exchangeable Shares tendered by a retracting holder, the Corporation will redeem only those Exchangeable Shares tendered by the holder as would not be contrary to such provisions of applicable law. The holder of any Exchangeable Shares not

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redeemed by the Corporation will be deemed to have required the Trust or subsidiary of the Trust to purchase such unretracted Exchangeable Shares in exchange for Trust Units on the Retraction Date pursuant to the Exchange Right. See “Exchangeable Shares - Voting and Exchange Trust Agreement – Exchange Right”.

Redemption of Exchangeable Shares

Subject to applicable law and the Redemption call right of the Trust and any subsidiary of the Trust, the Corporation:

(a)will, on January 15, 2010, subject to extension of such date by the board of directors of True Energy (the “Automatic Redemption Date”), redeem all but not less than all of the then outstanding Exchangeable Shares for a redemption price per Exchangeable Share equal to the value of that number of Trust Units equal to the exchange ratio as at the last Business Day prior to that Redemption Date (as that term is defined below) (the “Redemption Price”), to be satisfied by the delivery of such number of Trust Units; and

(b)may, at any time when the aggregate number of issued and outstanding Exchangeable Shares is less than 10% of those originally issued (other than Exchangeable Shares held by the Trust and subsidiary of the Trust and as such shares may be adjusted from time to time) (the “De Minimus Redemption Date” and, collectively with the Automatic Redemption Date, a “Redemption Date”), redeem all but not less than all of the then outstanding Exchangeable Shares for the Redemption Price per Exchangeable Share.

The Corporation will, at least 45 days prior to any Redemption Date, provide the registered holders of the Exchangeable Shares with written notice of the prospective redemption of the Exchangeable Shares by the Corporation.

The Trust and any subsidiary of the Trust will have the overriding right (the “Redemption call right”), notwithstanding a proposed redemption of the Exchangeable Shares by the Corporation on the applicable Redemption Date, pursuant to the Exchangeable Share Provisions, to purchase on any Redemption Date all but not less than all of the Exchangeable Shares then outstanding (other than Exchangeable Shares held by the Trust or a subsidiary of the Trust) in exchange for the Redemption Price per Exchangeable Share and, upon the exercise of the Redemption call right, the holders of all of the then outstanding Exchangeable Shares will be obliged to sell all such shares to the Trust or any subsidiary of the Trust, as applicable. If either the Trust or any subsidiary of the Trust exercises the Redemption call right, then the Corporation’s right to redeem the Exchangeable Shares on the applicable Redemption Date will terminate. The Redemption call right may be exercised by either the Trust or any subsidiary of the Trust.

Voting Rights

Except as required by applicable law, the holders of the Exchangeable Shares are not entitled as such to receive notice of or attend any meeting of the shareholders of the Corporation or to vote at any such meeting. In accordance with the Voting and Exchange Trust Agreement, the Trust has issued a Special Voting Right to the Voting and Exchange Trust Agreement Trustee, for the benefit of the holders (other than the Trust and any subsidiary of the Trust) of the Exchangeable Shares. The Special Voting Unit carries a number of votes, exercisable at any meeting at which Unitholders are entitled to vote, equal to the number of Trust Units into which the Exchangeable Shares are then exchangeable multiplied by the number of votes to which the holder of one Trust Unit is then entitled. Each holder of an Exchangeable Share on the record date for any meeting at which Unitholders are entitled to vote will be entitled to instruct the Voting and Exchange Trust Agreement Trustee to exercise that number of votes attached to the Special Voting Right which relate to the Exchangeable Shares held by such holder. The Voting and Exchange Trust Agreement Trustee will exercise each vote attached to the Special Voting Unit only as directed by the relevant holder and, in the absence of instructions from a holder as to voting, will not exercise such votes.

Amendment and Approval

The rights, privileges, restrictions and conditions attaching to the Exchangeable Shares may be changed only with the approval of the holders thereof. Any such approval or any other approval or consent to be given by the

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holders of the Exchangeable Shares will be sufficiently given if given in accordance with applicable law subject to a minimum requirement that such approval or consent be evidenced by a resolution passed by not less than two-thirds of the votes cast thereon (other than shares held by the Trust, or any of its subsidiaries and other affiliates) at a meeting of the holders of the Exchangeable Shares duly called and held at which holders of at least 5 percent of the then outstanding Exchangeable Shares are present in person or represented by proxy. In the event that no such quorum is present at such meeting within one-half hour after the time appointed therefor, then the meeting will be adjourned to such place and time (not less than ten days later) as may be determined at the original meeting by the Chairman of such meeting and the holders of Exchangeable Shares present in person or represented by proxy at the adjourned meeting will constitute a quorum thereat and may transact the business for which the meeting was originally called. At the adjourned meeting, a resolution passed by the affirmative vote of not less than two-thirds of the votes cast thereon (other than shares beneficially owned by the Trust or any of its subsidiaries and other affiliates) will constitute the approval or consent of the holders of the Exchangeable Shares.

Non-Resident Holders

Notwithstanding anything contained in the Exchangeable Share Provisions, the obligation of the Trust or any subsidiary thereof to pay the retraction price, redemption price, a purchase price or amount payable on liquidation in respect of the Exchangeable Shares which are held by a resident of any foreign country may be satisfied by delivering the Trust Units which would have been received by the affected holder to the transfer agent of the Exchangeable Shares who shall sell such Trust Units on a stock exchange on which the Trust Units are listed, deliver the proceeds of the sale to the holder. The rights of the affected holder shall be limited to receiving the net proceeds of such sale (net of applicable taxes).

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

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

Support Agreement and Voting and Exchange Trust Agreement

The Support Agreement and the Voting and Exchange Trust Agreement have been filed on SEDAR at www.sedar.com.

BORROWINGS

In conjunction with the 2005 Arrangement, True Energy entered into new credit facilities. At December 31, 2005 the Trust had a $115 million demand revolving credit facility syndicated between two Canadian chartered banks and a $10 million operating facility provided by one of the banks. Interest is payable at the lenders’ prime rate, subject to adjustment depending on the Trust’s debt to cash flow ratio. Security is provided by a first charge demand debenture. The credit facility is guaranteed by the Trust and all material subsidiaries and is secured against all the assets of True Energy Inc., the Trust and all material subsidiaries. True has provided a negative pledge and undertaking to provide fixed charges over major petroleum and natural gas reserves in certain circumstances. A standby fee is charged of one eighth of one percent (0.125%) on the undrawn portion of the credit facility. The availability under the facility was subject to an interim review date of March 1, 2006 and an annual review on or before June 1, 2006. Prior to March 1, 2006, the interim review date was extended to May 31, 2006 and the working capital covenant was waived.

Subsequently, the facility was replaced by a $135 million demand revolving credit facility and a $15 million operating facility both provided by one Canadian chartered bank, subject to an annual review by June 1, 2006. No other terms or conditions were modified.

Pursuant to the credit facilities and a subordination agreement related thereto, any present and future indebtedness of True Energy, or any of its subsidiaries, to the Trust, including under the Notes and NPI, is made subordinate to the repayment of amounts owing under our credit facilities. Further, under our credit facilities and the subordination agreement, the Trust is restricted from making distributions to the Unitholders in the following circumstances: (i) after the Trustee has received notice that a demand has been made under the credit facilities, (ii)

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after the Trustee has received notice of a default or event of default under the credit facilities or of the borrowings thereunder exceeding the borrowing base established from time to time by the lender, and (iii) if such distribution would result in a default or event of default under the credit facilities or would impair the ability of the corporation to satisfy its obligations under the credit facilities.

The terms of our credit facilities and the subordination agreement ensure our lenders have priority over our Unitholders with respect to the assets and income of the Trust and its subsidiaries. Amounts due and owing to our lenders under our credit facilities must be paid before any distribution can be made to Unitholders. This could result in an interruption of distributions to our Unitholders. See “Risk Factors – Debt Service”.

As at March 1, 2006, a total of $94.7 million was outstanding under our credit facilities, including cash balances to be applied.

NOTES

The following summary of the material attributes and characteristics of the Notes does not purport to be complete and is qualified in its entirety by reference to the provisions of the Note Indenture, a copy of which is filed on SEDAR at www.sedar.com.

Terms and Issue of Notes

The Notes were issued to the Trust under the Note Indenture pursuant to the 2004 Arrangement and the 2005 Arrangement. The Notes are unsecured and currently bear interest at a rate of 13% per annum in the case of series 1 Notes (“Series 1 Notes”) and 10% per annum in the case of series 2 Notes (“Series 2 Notes”).

The outstanding principal and interest outstanding on the Series 1 Notes is due and payable on December 31, 2034, and on the Series 2 Notes is due and payable on December 31, 2020, subject to the provisions of the Note Indenture and the Notes. The Notes are subject to prepayment by True Energy Inc., in whole or in part, at any time without notice or bonus.

Notwithstanding anything in the Note Indenture or any Note to the contrary, the indebtedness evidenced by the Notes is subordinate and junior to indebtedness and the liability represented by Senior Debt now or hereafter outstanding or incurred except that True Energy is not precluded from paying principal and regularly scheduled interest on the Notes as long as at the relevant interest payment date and immediately after the making of such payment no Senior Debt Default has occurred and is continuing.

For these purposes, “Senior Debt” means (a) all indebtedness, obligations and liabilities of True Energy in respect of borrowed money excluding (i) the indebtedness, obligations or liability created under or evidenced by the Notes; and (ii) any indebtedness that by its terms or by the terms of the instrument evidencing or creating it ranks or in respect of which the holders thereof have agreed that it shall rank pari passu with or subordinate to the Notes; and (b) from and after the commencement of, and during the continuance of, any creditor proceedings (including bankruptcy, liquidation, winding-up, dissolution, restructuring or arrangement proceedings), all indebtedness, obligations and liabilities of True Energy other than indebtedness obligations and liabilities to the holders of Notes; and “Senior Debt Default” means and includes: (i) any event of default under any Senior Debt; and (ii) any demand for repayment of any Senior Debt which is due and payable on demand.

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

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Principal and interest on the Notes will be payable in lawful money of Canada directly to the holders of Notes at their address set forth in the register of holders of Notes. The Trust is currently the holder of all of the issued and outstanding Notes.

Events of Default

The Note Indenture provides that any of the following shall constitute an Event of Default: (i) default in payment of the principal of the Notes when required; (ii) the failure to pay all of the interest obligations on the Notes for a period of three months; (iii) if True Energy has defaulted and a demand for payment has been made under any material instrument, indenture or document evidencing indebtedness of more than $5 million and True Energy has failed to remedy such default within applicable curative periods; (iv) certain events of winding-up, liquidation, bankruptcy, insolvency, receivership or seizure; (v) default in the observance or performance of any other covenant or condition of the Note Indenture and continuance of such default for a period of 30 days after notice in writing has been given by the Note Trustee to True Energy specifying such default and requiring True Energy to rectify the same; (vi) True Energy ceasing to carry on its business; and (vii) material default by True Energy under material agreements or covenants in any material lease, licence or other agreement whereby any material property or rights of True Energy may become liable to forfeiture or where any such lease, licence or other agreement would be subject to termination if not remedied in accordance within any curative period provided therein, in each case where such non-compliance could result in a material adverse effect on the business or financial condition of True Energy.

CORPORATE GOVERNANCE

General

In general, True Energy has been delegated substantially all of our management decisions. Unitholders are entitled to elect the board of directors of True Energy pursuant to the terms of the Trust Indenture.

Additional information in respect of corporate governance matters will be contained in our 2005 information circular and proxy statement which will be filed on SEDAR at www.sedar.com.

Trust Indenture

Pursuant to the Trust Indenture, Unitholders are entitled to direct the manner in which we will vote our Common Shares in True Energy at all meetings in respect of matters relating to the election of the directors of True Energy, approving its financial statements and appointing auditors of True Energy who shall be the same as our auditors. Prior to us voting our Common Shares in True Energy, in respect of such matters, each Unitholder is entitled to vote in respect of the matter on the basis of one vote per Trust Unit held, and we are required to vote our Common Shares in True Energy in accordance with the result of the vote of Unitholders.

Decision Making

True Energy and the Trust have entered into the Administration Agreement pursuant to which the board of directors of True Energy is delegated the significant management decisions of the Trust. In particular, the Trustee has delegated to True Energy responsibility for any and all matters relating to the following: (i) calculating or causing the calculating of any amounts to be paid by the Trustee to Unitholders in accordance with the Trust Indenture; (ii) ensuring compliance by the Trust with its legal obligations, including its continuous disclosure obligations under all applicable securities legislation; (iii) preparing and furnishing to Unitholders all reports, financial statements, all necessary tax information and other information required to be sent to Unitholders; (iv) calling, holding or distributing material in respect of any meeting of Unitholders as required pursuant to the Trust Indenture; and (v) certain matters relating to the specific powers and authorities as set forth in the Trust Indenture.

In addition, pursuant to the Trust Indenture, the board of directors of True Energy shall exercise all rights, powers, responsibilities and privileges of the Trustee in relation to a response to an offer for Trust Units or for all or substantially all of the property and assets of the Trust or True Energy or any subsidiary of True Energy or the Trust including entering into any Unitholder rights protection plan either prior to or during the course of any offer, any defensive action in the course of any offer, the preparation of any directors’ circular in response to an offer and consideration on behalf of Unitholders and a recommendation to Unitholders in respect of any offer and any regulatory or court action in respect thereof.

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Directors and Officers of True Energy

The following table sets forth the names, municipalities of residence, positions held and principal occupations for the prior five years, of each of the directors and officers of True Energy:

Name and Municipality of Residence	Position with True Energy	Date First Elected or Appointed as Director	Principal Occupation
Paul R. Baay Calgary, Alberta	President, Chief Executive Officer and Director	August 31, 2000	President and Chief Executive Officer of True Energy since its formation on August 31, 2000
Clinton T. Broughton Calgary, Alberta	Executive Vice-President	N/A	Chief Operating Officer of True Energy since April 25, 2005 and Vice-President of True Energy since its formation on August 31, 2000
Wayne B. Jessee Calgary, Alberta	Vice-President and Chief Operating Officer	N/A	Vice President and Chief Operating Officer of True Energy since November 2, 2005; prior thereto Vice President, Corporate Development of TKE Energy Trust and TUSK Energy Corporation from November 2, 2004; prior thereto Vice President of TUSK Energy Inc. from May 2000.
Joan E. Dunne Calgary, Alberta	Vice-President, Finance and Chief Financial Officer	N/A	Vice-President, Finance and Chief Financial Officer of True Energy since November 25, 2002; prior thereto, from December, 2000 to November, 2002, consulted for various petroleum companies in areas of finance, tax and investor relations; prior thereto, from January 1998 to November 2000, Vice-President, Finance and Chief Financial Officer of Ionic Energy Inc.
Ian C. Ross Calgary, Alberta	Vice-President, Land	N/A	Vice-President, Land of True Energy since January 10, 2005 after joining True Energy in August, 2001; prior thereto, Landman at Crestar Energy Inc. from 1997.
Case (David) Caulfield	Vice-President, Exploration	N/A	Vice-President, Exploration of True Energy since November 2, 2005 after joining True Energy in August 2003; prior thereto, Senior Geophysicist with Marathon Canada from February 1999.
W.C. (Mickey) Dunn(1)(3) Edmonton, Alberta	Director	August 31, 2000	Chairman of True Energy Trust, Director of Precision Drilling Trust, Director of Vero Energy Inc., Director of Rentcash Inc., previously President and Chief Executive Officer of Cardium Service and Supply Ltd., Cardium Tool Services Inc. and Colorado Silica Sand Inc.

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Name and Municipality of Residence	Position with True Energy	Date First Elected or Appointed as Director	Principal Occupation
Norman W. Holton(2)(3) Calgary, Alberta	Director	November 2, 2005	Chairman and Chief Executive Officer of TUSK Energy Corporation since November 2, 2005; Chairman of TUSK Energy Corporation and Chairman and Chief Executive Officer of TKE Energy Trust from November 2, 2004 to November 2, 2005; prior thereto President and Chief Executive Officer of TUSK Energy Inc. since 1987
Murray B. Todd(1)(2) Calgary, Alberta	Director	November 2, 2005	President of Canada Hibernia Holding Company (an oil and gas production company)
Raymond G. Smith(2)(4) Calgary, Alberta	Director	April 25, 2005	Chairman, Cork Exploration Inc. since April 1, 2005; prior thereto President and Chief Executive Officer of Meridian since September 2002. On January 1, 2004 Mr. Smith was appointed Chairman of Meridian; prior thereto, Mr. Smith was President and Chief Executive Officer of Corsair Exploration Ltd. from July 1999 to June 2002
Garth Wiggins(1)(2) Calgary, Alberta	Director	November 5, 2005	Mr. Wiggins is currently a Principal at Kenway, Mack Slusarchuk, Stewart Chartered Accountants. Previously he was Vice-President, Finance and Chief Financial Officer of Tri Link Resources Ltd. from 1980 to 1993 and a partner of Farvolden, Wiggins, Balderston Chartered Accountants. He has been a Director of Precision Drilling since 1997.
John H. Cuthbertson(3)(4) Calgary, Alberta	Director	August 31, 2000	Partner, Burnet, Duckworth & Palmer LLP (barristers and solicitors)

Notes:

(1)           Member of Audit Committee

(2)           Member of Reserves, Safety and Environment Committee.

(3)           Member of Compensation Committee.

(4)           Member of Corporate Governance Committee.

As at March 21, 2006, the directors and officers of True Energy, as a group, beneficially owned, directly or indirectly, or exercise control or direction over 2,079,551 Trust Units, representing approximately 6% of the issued and outstanding Trust Units, and 125,580 Exchangeable Shares, representing approximately 22% of the issued and outstanding Exchangeable Shares, resulting in an approximate total average ownership of 6%.

Conflicts of Interest

There are potential conflicts of interest to which the directors and officers of True Energy will be subject to in connection with the operations of the Trust. In particular, certain of the directors and officers of True Energy are involved in managerial or director positions with other oil and gas companies whose operations may, from time to time, be in direct competition with us or with entities which may, from time to time, provide financing to, or make equity investments in, our competitors. In accordance with the ABCA, directors who have a material interest or any person who is a party to a material contract or a proposed material contract with us are required, subject to certain exceptions, to disclose that interest and generally abstain from voting on any resolution to approve the contract.

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AUDIT COMMITTEE INFORMATION

Committee Mandate and Terms of Reference

The Mandate of the Audit Committee of the board of directors of True Energy is attached hereto as Schedule “C”.

Composition of the Audit Committee

The following table sets forth the names of each current member of the Audit Committee, whether such member is independent, whether such member is financially literate and the relevant education and experience of such member:

Name and municipality of residence	Independent	Financially literate	Relevant education and experience
Garth Wiggins Calgary, Alberta	Yes	Yes	Mr. Wiggins is a Chartered Accountant. From 1980 to 1993 he was Chief Financial Officer for TriLink Resources Ltd., a junior oil company which traded on the TSX. From 1997 to present, Mr. Wiggins has been a director of Precision Drilling and a member of its audit committee.
Murray B. Todd Calgary, Alberta	Yes	Yes	Mr. Todd has worked in the oil industry for 51 years, including 35 years at the executive level. Much of the work has involved reading and dealing with financial reports and internal controls. Mr. Todd’s formal education includes university courses in business management and in-house courses in accounting and financial management, including a Harvard University mini-MBA course focused on financial management and accounting statements. Mr. Todd has extensive training in the analysis of oil and gas reserves through his professional degree in Petroleum Engineering. He has worked with reserves and reserve reports for 40 years.
W.C. (Mickey) Dunn Edmonton, Alberta	Yes	Yes	Mr. Dunn has worked in the oil industry since 1981 at the executive level. His work has involved extensive reading and dealing with financial reports and internal controls. Mr. Dunn’s formal education has included numerous courses at numerous universities in business management and financial management, including attending York University Executive Program, Wharton School of Business Executive Program and the NAIT Business Program. In addition to his role with True, Mr. Dunn has served on the Audit Committees of three other public companies and one private company in addition to being a director of two other private companies and one other public company, of which all but one were in the oil and gas industry.

Pre-Approval of Policies and Procedures

The Audit Committee has pre-approved the provision of certain non-audit services to the Corporation including assorted income tax services including compliance and routine planning matters and has delegated to the Chairman of the Audit Committee the authority to pre-approve other non-audit services and in such event the Chairman is required to report to the Audit Committee such pre-approval at the next meeting of the Audit Committee. The engagement may commence upon approval of the Chairman of the Audit Committee.

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External Auditor Service Fees

Audit Fees

The aggregate fees billed by our external auditor in each of the last two fiscal years for audit services such as the annual audit, a business acquisition report, a plan of arrangement, reviews of interim consolidated financial statements, and due diligence work in respect to a private placement were $372,000 in 2005 and $90,500 in 2004.

Audit – Related Fees

There were no other fees billed in each of the last two fiscal years for assurance related services by our external auditor that are reasonably related to the performance of the audit or review of our financial statements that are not reported under “Audit Fees” above.

Tax Fees

The aggregate fees billed in each of the last two fiscal years for professional services rendered by our external auditor for tax compliance, tax advice and tax planning were $73,800 in 2005 and $32,300 in 2004.

All Other Fees

No other fees were billed in either of the last two fiscal years for products and services provided by our auditors other than services reported above.

DISTRIBUTIONS TO UNITHOLDERS

An objective of our distribution policy is to provide Unitholders with relatively stable and predictable monthly distributions. An additional objective is to retain a portion of cash flow to fund ongoing development and optimization projects designed to enhance the sustainability of our cash flow.

Although we strive to provide Unitholders with stable and predictable cash flows, the percentage of cash flow from operations paid to Unitholders each month may vary according to a number of factors, including, fluctuations in resource prices, exchange rates and production rates, reserves growth, the size of development drilling programs and the portion thereof funded from cash flow and our overall level of debt.

Since our formation, monthly cash distributions have been declared in the following amounts:

For the Month Ended	Distributions per Unit		Payment Date
December 31, 2004	$	0.12	January 17, 2005
January 31, 2005	$	0.12	February 15, 2005
February 28, 2005	$	0.12	March 25, 2005
March 31, 2005	$	0.12	April 15, 2005
April 30, 2005	$	0.12	May 16, 2005
May 31, 2005	$	0.12	June 15, 2005
June 30, 2005	$	0.12	July 15, 2005
July 31, 2005	$	0.12	August 15, 2005
August 31, 2005	$	0.12	September 15, 2005
September 30, 2005	$	0.12	October 17, 2005
October 31, 2005	$	0.12	November 15, 2005
November 30, 2005(1)	$	0.24	December 15, 2005
December 31, 2005(1)	$	0.24	January 16, 2006
January 31, 2006(1)	$	0.24	February 15, 2006
February 28, 2006(1)	$	0.24	March 15, 2006

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Note:

(1)Reflects the consolidation of the Trust Units on a one for two Trust Unit basis which consolidation occurred in connection with the 2005 Arrangement effective November 2, 2005.

In certain circumstances, distributions may be restricted under our borrowing agreements (see“Borrowings”).

For Canadian tax purposes, 2005 distributions, both prior to and following the 2005 Arrangement, were determined to be 95% taxable as other income and 5% were a tax deferred return of capital in the hands of Canadian unitholders. In Canada, the tax-deferred portion would usually be treated as an adjustment to the cost base of the units.

In consultation with its U.S. tax advisors, True believes that its trust units should be properly classified as equity in a corporation, rather than debt, and that dividends paid to individual U.S. unitholders should be “qualified dividends” for U.S. federal income tax purposes. As such, the portion of the distributions made during 2005 that are considered dividends for U.S. federal income tax purposes should qualify for the reduced rate of tax applicable to long-term capital gains. Unitholders or potential unitholders should consult their own legal or tax advisors as to their particular income tax consequences of holding True units.

MARKET FOR SECURITIES

The Trust Units are listed and traded on the TSX. The trading symbol for the Trust Units is “TUI.UN”.

The following sets forth trading information for our Trust Units since they began trading on the TSX following the 2004 Arrangement:

Period	High		Low		Volume
2004
November (5-30)	$	10.50	$	9.40	2,728,323
December	$	9.90	$	9.17	2,162,796
2005
January	$	9.90	$	9.25	3,760,255
February	$	11.43	$	9.84	4,800,070
March	$	11.38	$	9.50	2,423,104
April	$	10.35	$	9.28	2,269,672
May	$	9.49	$	8.10	2,260,029
June	$	9.95	$	8.96	1,738,425
July	$	10.24	$	9.35	1,662,590
August	$	11.15	$	9.75	3,656,862
September	$	11.96	$	10.25	3,160,058
October	$	11.22	$	9.21	2,472,197
November (1 to 5)	$	10.04	$	9.65	213,657
November(1)	$	19.95	$	18.09	3,482,083
December(1)	$	21.85	$	18.90	6,525,449
2006
January(1)	$	21.30	$	19.50	5,894,062
February(1)	$	19.85	$	14.30	8,419,061
March (1 to 24)(1)	$	16.00	$	12.99	9,287,866

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Note:

(1)Reflects the consolidation of the Trust Units on a one for two Trust Unit basis which consolidation occurred in connection with the 2005 Arrangement effective November 2, 2005. The Trust units started trading post consolidation on November 7, 2005.

INDUSTRY CONDITIONS

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

Pricing and Marketing – Oil, Natural Gas and Associated Products

In the provinces of Alberta, British Columbia and Saskatchewan oil, natural gas and associated products are generally sold at market index based prices. These indices are generated at various sales points depending on the commodity and are reflective of the current value of the commodity adjusted for quality and locational differentials. While these indices tend to track industry reference prices (ie. price of West Texas Intermediate crude oil at Cushing, Oklahoma or price of natural gas at Henry Hub, Louisiana), some variances can occur due to specific supply-demand imbalances. These differentials can change on a monthly or daily basis depending on the supply-demand fundamental at each location as well as other non-related changes such as the value of the Canadian dollar and the cost of transporting the commodity to the pricing point of the particular index.

The producers of oil are entitled to negotiate sales contracts directly with oil purchasers, with the result that the market determines the price of oil. Oil prices are primarily based on worldwide supply and demand. The specific price depends in part on oil quality, prices of competing fuels, distance to market, the value of refined products, the supply/demand balance and other contractual terms. Oil exporters are also entitled to enter into export contracts with terms not exceeding one year in the case of light crude oil and two years in the case of heavy crude oil, provided that an order approving such export has been obtained from the National Energy Board of Canada (the “NEB”). Any oil export to be made pursuant to a contract of longer duration (to a maximum of 25 years) requires an exporter to obtain an export license from the NEB and the issuance of such license requires the approval of the Governor in Council.

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

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

Pipeline Capacity

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

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The North American Free Trade Agreement

The North American Free Trade Agreement (“NAFTA”) among the governments of Canada, United States of America and Mexico became effective on January 1, 1994. NAFTA carries forward most of the material energy terms that are contained in the Canada-United States Free Trade Agreement. In the context of energy resources, Canada continues to remain free to determine whether exports of energy resources to the United States or Mexico will be allowed, provided that any export restrictions do not: (i) reduce the proportion of energy resources exported relative to domestic use (based upon the proportion prevailing in the most recent 36 month period or in such other representative period as the parties may agree); (ii) impose an export price higher than the domestic price subject to an exception with respect to certain measures which only restrict the volume of exports; and (iii) disrupt normal channels of supply. All three countries are prohibited from imposing minimum or maximum export or import price requirements provided, in the case of export price requirements, prohibition in any circumstances in which any other form of quantitative restriction is prohibited, and in the case of import price requirements, such requirements do not apply with respect to enforcement of countervailing and anti dumping orders and undertakings.

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

Provincial Royalties and Incentives

General

In addition to federal regulation, each province has legislation and regulations which govern land tenure, royalties, production rates, environmental protection and other matters. The royalty regime is a significant factor in the profitability of crude oil, natural gas liquids, sulphur and natural gas production. Royalties payable on production from lands other than Crown lands are determined by negotiations between the mineral owner and the lessee, although production from such lands is subject to certain provincial taxes and royalties. Crown royalties are determined by governmental regulation and are generally calculated as a percentage of the value of the gross production. The rate of royalties payable generally depends in part on prescribed reference prices, well productivity, geographical location, field discovery date, method of recovery and the type or quality of the petroleum product produced. Other royalties and royalty-like interests are from time to time carved out of the working interest owner’s interest through non-public transactions. These are often referred to as overriding royalties, gross overriding royalties, net profits interests or net carried interests.

From time to time the governments of the western Canadian provinces create incentive programs for exploration and development. Such programs often provide for royalty rate reductions, royalty holidays and tax credits, and are generally introduced when commodity prices are low. The programs are designed to encourage exploration and development activity by improving earnings and cash flow within the industry. Royalty holidays and reductions would reduce the amount of Crown royalties paid by oil and gas producers to the provincial governments and would increase the net income and funds from operations of such producers. However, the trend in recent years has been for provincial governments to allow such incentive programs to expire without renewal, and consequently few such incentive programs are currently operative.

On March 3, 2003 the Department of Finance (Canada) released a technical paper entitled “Improving the Income Taxation of the Resource Sector in Canada” (the “Technical Paper”). In November, 2003 the Tax Act was amended to provide the following initiatives applicable to the oil and gas industry (to a maximum of $2,000,000) to be phased in over a five year period: (i) a reduction of the federal statutory corporate income tax rate on income earned from resource activities from 28% to 21%, beginning with a one percentage point reduction effective January 1, 2003, and (ii) a deduction for federal income tax purposes of actual provincial and other Crown royalties and mining taxes paid and the elimination of the 25% resource allowance. In addition, the percentage of Alberta royalty tax credit that True will be required to include in federal taxable income will be 12.5% in 2004; 17.5% in 2005;

32.5% in 2006; 50% in 2007; 60% in 2008; 70% in 2009; 80% in 2010; 90% in 2011, and 100% in 2012 and beyond.

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Alberta

Regulations made pursuant to the Mines and Minerals Act (Alberta) provide various incentives for exploring and developing oil reserves in Alberta. Oil produced from horizontal extensions commenced at least 5 years after the well was originally spudded may also qualify for a royalty reduction. A 24 month, 8,000 m3 exemption is available to production from a reactivated well that has not produced for: (i) a 12 month period, if resuming production in October, November or December of 1992 or January, 1993; or (ii) a 24 month period, if resuming production in February 1993 or later. As well, oil production from eligible new field and new pool wildcat wells and deeper pool test wells spudded or deepened after September 30, 1992 is entitled to a 12 month royalty exemption (to a maximum of $1 million). Oil produced from low productivity wells, enhanced recovery schemes (such as injection wells) and experimental projects is also subject to royalty reductions.

Oil royalty rates vary from province to province. In Alberta, oil royalty rates vary between 10% and 35% for oil and 10% and 30% for new oil. New oil is applicable to oil pools discovered after March 31, 1974 and prior to October 1, 1992. The Alberta government introduced the Third Tier Royalty with a base rate of 10% and a rate cap of 25% for oil pools discovered after September 30, 1992.

Effective January 1, 1994, the calculation and payment of natural gas royalties became subject to a simplified process. The royalty reserved to the Crown in respect of natural gas production, subject to various incentives, is between 15% and 30%, in the case of new natural gas, and between 15% and 35%, in the case of old natural gas, depending upon a prescribed or corporate average reference price. Natural gas produced from qualifying exploratory natural gas wells spudded or deepened after July 31, 1985 and before June 1, 1988 continues to be eligible for a royalty exemption for a period of 12 months, or such later time that the value of the exempted royalty quantity equals a prescribed maximum amount. Natural gas produced from qualifying intervals in eligible natural gas wells spudded or deepened to a depth below 2,500 meters is also subject to a royalty exemption, the amount of which depends on the depth of the well.

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

In Alberta, a producer of oil or natural gas is entitled to a credit on qualified oil and natural gas production against the royalties payable to the Crown by virtue of the Alberta royalty tax credit (“ARTC”) program. The ARTC rate is based on a price sensitive formula and the ARTC rate varies between 75% at prices at and below $100 per m3 and 25% at prices at and above $210 per m3. Crude oil and natural gas royalty programs for specific wells and royalty reductions reduce the amount of Crown royalties paid by True to the provincial governments. In general, the ARTC program provides a rebate on Alberta Crown royalties paid in respect of eligible producing properties. The ARTC rate is applied to a maximum of $2,000,000 of Alberta Crown royalties payable for each producer or associated group of producers. Crown royalties on production from producing properties acquired from a corporation claiming maximum entitlement to ARTC will generally not be eligible for ARTC. The rate will be established quarterly based on the average “par price”, as determined by the Alberta Department of Energy for the previous quarterly period.

On December 22, 1997, the Alberta government announced that it was conducting a review of the ARTC program with the objective of setting out better targeted objectives for a smaller program and to deal with administrative difficulties. On August 30, 1999, the Alberta government announced that it would not be reducing the size of the program but that it would introduce new rules to reduce the number of persons who qualify for the program. The new rules will preclude companies that pay less than $10,000 in royalties per year and non corporate entities from qualifying for the program. Such rules will not presently preclude True from being eligible for the ARTC program.

British Columbia

Producers of oil and natural gas in the Province of British Columbia are also required to pay annual rental payments in respect of the Crown leases and royalties and freehold production taxes in respect of oil and gas produced from Crown and freehold lands, respectively. The amount payable as a royalty in respect of oil depends on the type of oil, the value of the oil, the quantity of oil produced in a month and the vintage of the oil. Generally, the vintage of oil is based on the determination of whether the oil is produced from a pool discovered before October 31, 1975 (old oil) between October 31, 1975 and June 1, 1998 (new oil) or after June 1, 1998 (third-tier oil). Oil

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produced from newly discovered pools may be exempt from the payment of a royalty for the first 36 months of production. The royalty payable on natural gas is determined by a sliding scale based on a reference price, which is the greater of the amount obtained by the producer, and a prescribed minimum price. As an incentive for the production and marketing of natural gas, which may have been flared, natural gas produced in association with oil has a lower royalty then the royalty payable on non-conservation gas.

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

Some of the financial incentives in the Strategy include:

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

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

Saskatchewan

In Saskatchewan, the amount payable as a royalty in respect of oil depends on the vintage of the oil, the type of oil, the quantity of oil produced in a month and the value of the oil. For Crown royalty and freehold production tax purposes, crude oil is considered “heavy oil”, “southwest designated oil” or “non heavy oil other than southwest designated oil”. The conventional royalty and production tax classifications (“fourth tier oil” introduced October 1, 2002, “third tier oil”, “new oil” or “old oil”) of oil production are applicable to each of the three crude oil types. The Crown royalty and freehold production tax structure for crude oil is price sensitive and varies between the base royalty rates of 5% for all “fourth tier oil” to 20% for “old oil”. Marginal royalty rates are 30% for all “fourth tier oil” to 45% for “old oil”.

The amount payable as a royalty in respect of natural gas is determined by a sliding scale based on a reference price (which is the greater of the amount obtained by the producer and a prescribed minimum price), the quantity produced in a given month, the type of natural gas and the vintage of the natural gas. As an incentive for the production and marketing of natural gas which may have been flared, the royalty rate on natural gas produced in association with oil is less than on non-associated natural gas. The royalty and production tax classifications of gas production are “fourth tier gas” introduced October 1, 2002, “third tier gas”, “new gas” and “old gas”. The Crown royalty and freehold production tax for gas is price sensitive and varies between the base royalty rate of 5% for “fourth tier gas” and 20% for “old gas”. The marginal royalty rates are between 30% for “fourth tier gas” and 45% for “old gas”.

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

•A new Crown royalty and freehold production tax regime applicable to associated natural gas (gas produced from oil wells) that is gathered for use or sale. The royalty/ tax will be payable on associated natural gas produced from an oil well that exceeds approximately 65 thousand cubic meters in a month.

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

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

Land Tenure

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

Environmental Regulation

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

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

RISK FACTORS

The following is a summary of certain risk factors relating to our business which prospective investors should carefully consider before deciding whether to purchase Trust Units and/or Exchangeable Shares.

Volatility of Oil and Natural Gas Prices

Our operational results and financial condition of our operating entities, and therefore the amounts we pay to Unitholders, will be dependent on the prices received for oil and natural gas production. Oil and natural gas prices have fluctuated widely during recent years and are determined by economic and in the case of oil prices, political factors. Supply and demand factors, including weather and general economic conditions as well as conditions in other oil and natural gas regions impact prices. Any movement in oil and natural gas prices could have an effect on our financial condition and therefore on the cash available to be distributed to Unitholders. We may manage the risk associated with changes in commodity prices by entering into oil or natural gas price hedges. If we hedge our commodity price exposure, we will forego the benefits we would otherwise experience if commodity prices were to increase. In addition, commodity hedging activities could expose us to losses. To the extent that we engage in risk management activities related to commodity prices, it will be subject to credit risks associated with counterparties with which we contract.

Reserve Estimates

There are numerous uncertainties inherent in estimating quantities of oil, natural gas and NGL reserves and cash flows to be derived therefrom, including many factors beyond our control. The reserve and associated cash flow information set forth in this Annual Information Form represents estimates only. In general, estimates of

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economically recoverable oil and natural gas reserves and the future net cash flows 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 oil and natural gas, royalty rates, the assumed effects of regulation by governmental agencies and future operating costs, all of which may vary from actual results. All such estimates are to some degree speculative, and classifications of reserves are only attempts to define the degree of speculation involved. For those reasons, estimates of the economically recoverable oil and natural gas reserves attributable to any particular group of properties, classification of such reserves based on risk of recovery and estimates of future net revenues expected therefrom prepared by different engineers, or by the same engineers at different times, may vary. Our actual production, revenues and development and operating expenditures with respect to its reserves will vary from estimates thereof and such variations could be material.

Estimates of proved reserves that may be developed and produced in the future are often based upon volumetric calculations and upon analogy to similar types of reserves rather than actual production history. 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.

In accordance with applicable securities laws, GLJ and Chapman has used both constant and forecast price and cost estimates in calculating reserve quantities included in this Annual Information Form. Actual future net cash flows will be affected by other factors such as actual production levels, supply and demand for oil and natural gas, curtailments or increases in consumption by oil and natural gas purchasers, changes in governmental regulation or taxation and the impact of inflation on costs.

Actual production and cash flows derived therefrom will vary from the estimates contained in the engineering reports summarized in this Annual Information Form, and such variations could be material. The GLJ Chapman Report is based in part on the assumed success of activities we intend to undertake in future years. The reserves and estimated cash flows to be derived therefrom contained in the engineering reports summarized in this Annual Information Form will be reduced to the extent that such activities do not achieve the level of success assumed in the engineering reports summarized in this Annual Information Form.

Variations in Interest Rates and Foreign Exchange 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, as well as 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. A material increase in the value of the Canadian dollar may negatively impact our operating entities net production revenue.

In addition, the exchange rate for the Canadian dollar versus the U.S. dollar has increased significantly over the last 12 months, resulting in the receipt by our operating entities of fewer Canadian dollars for its production which may affect future distributions. To the extent that we engage in risk management activities related to foreign exchange rates, it will be subject to credit risk associated with counterparties with which it contracts. 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.

Changes in Legislation

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

We intend 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

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may arise for us and Unitholders. Some of the significant consequences of losing mutual fund trust status are as follows:

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

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

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

•Trust Units would not constitute qualified investments for registered retirement savings plans (“RRSPs”), registered retirement income funds (“RRIFs”), registered education savings plans (“RESPs”) or deferred profit sharing plans (“DPSPs”). If, at the end of any month, one of these exempt plans holds Trust Units that are not qualified investments, the plan must pay a tax equal to 1 per cent of the fair market value of the Trust Units at the time the Trust Units were acquired by the exempt plan. An RRSP or RRIF holding nonqualified Trust Units would be subject to taxation on income attributable to the Trust Units. If an RESP holds non-qualified Trust Units, it may have its registration revoked by the Canada Revenue Agency.

In addition, we may take certain measures in the future to the extent we believe necessary to ensure that we maintain the 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 “Risk Factors – Non-Resident Ownership of Trust Units”.

Maintenance of Distributions

We conduct limited exploration activities for oil and natural gas reserves. Instead, we add to our oil and natural gas reserves primarily through development and acquisitions. As a result, future oil and natural gas reserves are highly dependent on our operating entities success in exploiting existing properties and acquiring additional reserves. We also distribute the majority of our net cash flow to Unitholders rather than reinvesting it in reserve additions. Accordingly, if external sources of capital, including the issuance of additional Trust Units, become limited or unavailable on commercially reasonable terms, our operating entities ability to make the necessary capital investments to maintain or expand its oil and natural gas reserves will be impaired. To the extent that our operating entities are required to use cash flow to finance capital expenditures or property acquisitions, the level of cash flow available for distribution to Unitholders will be reduced. Additionally, we cannot guarantee that we will be successful in developing additional reserves or acquiring additional reserves on terms that meet our investment objectives. Without these reserve additions, our reserves will deplete and as a consequence, either production from, or the average reserve life of, our properties will decline. Either decline may result in a reduction in the value of Trust Units and in a reduction in cash available for distributions to Unitholders.

Operational Matters

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. Operating costs on most properties have increased steadily over recent years. To the extent the operator fails to perform these functions properly, revenue may be reduced. Payments from production generally flow through the operator and there is a risk of delay and additional expense in receiving such revenues if the operator becomes insolvent. Although satisfactory title reviews are generally conducted in accordance with industry standards, such reviews do not guarantee or certify that a defect in the chain of title may not arise to defeat the claim of ours to certain of its oil and gas properties. A reduction of the income available for distributions could result in such circumstances.

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Depletion of Reserves

Distributions of income from our properties, absent commodity price increases or cost effective acquisition and development activities, will decline over time in a manner consistent with declining production from typical oil, natural gas and natural gas liquids reserves. We will not be reinvesting cash flow in the same manner as other industry participants as we conduct only minimal exploratory activities; nor to the same extent as other industry participants as one of our main objectives is to maximize long-term distributions. Accordingly, absent capital injections, our initial production levels and reserves will decline and the level of income available for distributions will be reduced.

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

To the extent that external sources of capital, including the issuance of additional Trust Units become limited or unavailable, our ability to make the necessary capital investments to maintain or expand our oil and natural gas reserves will be impaired. To the extent that we are required to use cash flow to finance capital expenditures or property acquisitions, the level of income available for distributions 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.

Accounting Write-Downs as a Result of GAAP

Canadian Generally Accepted Accounting Principles (“GAAP”) require 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. Three of the more significant ones are the depletion, depreciation and amortization (DD&A) expense, impairment of oil and natural gas properties and the asset retirement obligation associated with oil and gas properties. These estimates use reserve estimates as prepared by independent reservoir engineers and future cost estimates. In the case of the impairment, the fair values of the oil and natural gas assets are considered in determining the impairment, if any, of the net book value. The estimated future net cash flow from proved and probable reserves is discounted at the risk free rate of return to determine the fair value of the oil and gas assets. By their nature, the reserve estimates, cost estimates and the assessment of future cash flows used to assess impairment are subject to measurement uncertainty and the impact on the financial statements of future period could be material. Such non-cash charges and write-downs may be viewed unfavourably by the market and result in an inability to borrow funds and/or may result in a decline in the Trust Unit price. The net value of oil and gas properties are highly dependent upon the prices of oil and natural gas. See “Risk Factors – Volatility of Oil and Natural Gas Prices”.

GAAP requires that goodwill balances be assessed at least annually for impairment and that any permanent impairment be charged to net income. A permanent reduction in reserves, decline in commodity prices, and/or reduction in the Trust Unit price may indicate a goodwill impairment. An impairment would result in a write-down of the goodwill value and a non-cash charge against net income. The calculation of impairment value is subject to management estimates and assumptions. The Trust completed the annual impairment test for the goodwill balance at December 31, 2005, and no impairment of goodwill was indicated.

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

Non-Resident Ownership of Trust Units

In order for us to maintain our status as a mutual fund trust under the Tax Act, we must not be established or maintained primarily for the benefit of non-residents of Canada (“non-residents”) within the meaning of the

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Income Tax Act (Canada). The Trust Indenture provides that if at any time we become aware that the beneficial owners of 40% or more of the Trust Units then outstanding are or may be non-residents or that such a situation is imminent, certain actions may be taken as may be necessary to carry out the foregoing intention. See “Information Relating to Us – Trust Indenture – Limitations on Non-Resident Ownership”.

Environmental

All phases of the oil and natural gas business present environmental risks and hazards and 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 and prohibitions on 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. Compliance with such legislation can require significant expenditures and a breach may result in the imposition of fines and penalties, some of which may be material. Environmental legislation is evolving in a manner expected to result in stricter standards and enforcement, larger fines and liability and potentially increased capital expenditures and operating costs. The discharge of oil, natural gas or other pollutants into the air, soil or water may give rise to liabilities to governments and third parties and may require our operating entities to incur costs to remedy such discharge. 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 or a material increase in the costs of production, development or exploration activities or otherwise adversely affect our financial condition, results of operations or prospects. See “Industry Conditions – Environmental Regulation”.

Kyoto Protocol

In December 2002, the Government of Canada ratified the Kyoto Protocol (“Protocol”). The Protocol calls for Canada to reduce its greenhouse gas emissions to 6% below 1990 “business-as-usual” levels between 2008 and 2012. Given revised estimates of Canada’s normal emissions levels, this target translates into an approximately 40% gross reduction in Canada’s current emissions. In April 2005, Environment Canada released “Project Green”, a working paper giving early indications of how implementation was to be achieved. Large Final Emitters (“LFEs”), being 700 of Canada’s largest emitters, will receive a specific reduction target of 45 mt, and will have the opportunity to purchase domestic offset and technology credits. The exact mechanism for operating in the domestic credit market has yet to be revealed, and the prospect of non-LFE enterprise participating in that market to any great extent is uncertain. Various incentive funds have also been established to provide seed funding for the purchase of experimental technologies, encourage investment in alternative energy sources, and acquire credits from the domestic and international markets for re-sale to Canadian enterprise.

Environment Canada, in August 2005, released consultation papers for the management of a system of greenhouse gas offsets in the form of tradable and bankable credits. The credits are created by enterprise, individuals, or municipal government through the implementation of projects registered with the to-be-created offset authority. Standards for quantifying greenhouse gas reductions were also proposed in the consultation paper.

Debt Service

True Energy may, from time to time, finance a significant portion of its operations through debt. Amounts paid in respect of interest and principal on debt incurred by True Energy may impair True Energy’s ability to satisfy its obligations under the Notes. 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 by True Energy of its obligations under the Notes. Ultimately, this may result in lower levels of Distributable Cash for the Trust.

Pursuant to credit facilities established by True Energy, True Energy is restricted from making distributions to the Trust, including payments of principal and interest under the Notes in various circumstances which include, but are not limited to, the following: (i) after a demand has been made under the credit facilities; (ii) after a default or event of default has occurred under the credit facilities or if the borrowings thereunder exceed the borrowing base established from time to time by the lender; and (iii) if such distribution would result in a default or event of default under the credit facilities. This may restrict the ability of True Energy to pay interest or principal on any indebtedness to the Trust, including the Notes, and therefore may limit or eliminate cash available for distribution.

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Lenders have been provided with security over all of the assets of True Energy. If True Energy becomes unable to pay its debt service charges or otherwise commits an event of default such as bankruptcy, a lender may foreclose on or sell the assets of True Energy.

Maintenance of Distributions

We conduct limited exploration activities for oil and natural gas reserves. Instead, we add to our oil and natural gas reserves primarily through development and acquisitions. As a result, future oil and natural gas reserves are highly dependent on our operating entities success in exploiting existing properties and acquiring additional reserves. We also distribute a significant portion of our net cash flow to Unitholders rather than reinvesting it in reserve additions. Accordingly, if external sources of capital, including the issuance of additional Trust Units, become limited or unavailable on commercially reasonable terms, our operating entities ability to make the necessary capital investments to maintain or expand its oil and natural gas reserves may be impaired. To the extent that our operating entities are required to use cash flow in excess of the amount we customarily retain to finance capital expenditures or property acquisitions, the level of cash flow available for distribution to Unitholders may be reduced. Additionally, we cannot guarantee that we will be successful in developing additional reserves or acquiring additional reserves on terms that meet our investment objectives. Without these reserve additions, our reserves will deplete and as a consequence, either production from, or the average reserve life of, our properties will decline. Either decline may result in a reduction in the value of Trust Units and in a reduction in cash available for distributions to Unitholders.

Insurance

Our involvement in the exploration for and development of oil and natural gas properties may result in us becoming subject to liability for pollution, blow outs, property damage, personal injury or other hazards. Although prior to drilling our operating entities will obtain insurance in accordance with industry standards to address certain of these risks, such insurance has limitations on liability that may not be sufficient to cover the full extent of such liabilities. In addition, such risks may not in all circumstances be insurable or, in certain circumstances, our operating entities may elect not to obtain insurance to deal with specific risks due to the high premiums associated with such insurance or other reasons. The payment of such uninsured liabilities would reduce the funds available to us. The occurrence of a significant event that we are not fully insured against, or the insolvency of the insurer of such event, could have a material adverse effect on our operating subsidiaries financial position, results of operations or prospects and will reduce income otherwise distributable to us.

Regulatory

Oil and natural gas operations (exploration, production, pricing, marketing and transportation) are subject to extensive controls and regulations imposed by various levels of government that may be amended from time to time. See “Industry Conditions”. Our operations may require licenses from various governmental authorities. There can be no assurance that we will be able to obtain all necessary licenses and permits that may be required to carry out exploration and development at our projects.

Competition

There is strong competition relating to all aspects of the oil and gas industry. There are numerous trusts in the oil and gas industry, who are competing for the acquisitions of properties with longer life reserves and properties with exploitation and development opportunities. As a result of such increasing competition, it will be more difficult to acquire reserves on beneficial terms. We also compete for reserve acquisitions and skilled industry personnel with a substantial number of other oil and gas companies and trusts, many of which have significantly greater financial and other resources than we do.

Delay in Cash Distributions

In addition to the usual delays in payment by purchasers of oil and natural gas to the operators of the properties, and by the operator to 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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Reliance on Management

Unitholders will be dependent on the management of True Energy in respect of the administration and management of all matters relating to our operations. True Energy, as of December 31, 2005, operated approximately 80% of our total daily production. Investors who are not willing to rely on the management of True Energy should not invest in the Trust Units or Exchangeable Shares.

Expansion of Operations

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

Net Asset Value

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

Additional Financing

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

Return of Capital

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

Unitholders have a limited right to require us to repurchase 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 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. In addition, there may be resale restrictions imposed by law upon the recipients of the securities pursuant to the redemption right.

Nature of Trust Units

The Trust Units do not represent a traditional investment in the oil and natural gas sector and should not be viewed by investors as shares in True Energy. The Trust Units represent a fractional interest in our assets. As holders of Trust Units, Unitholders will not have the statutory rights normally associated with ownership of shares of a corporation including, for example, the right to bring “oppression” or “derivative” actions. Our sole assets will be the Notes and other investments in securities of our operating entities. The price per Trust Unit is a function of anticipated income available for distributions, the oil and gas assets acquired by us and our ability to effect long-

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term growth in the value of our assets. 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, is not registered under any trust and loan company legislation as it does not carry on or intend to carry on the business of a trust company.

Unitholder Limited Liability

The Trust Indenture provides that no Unitholder will be subject to any liability in connection with 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, except as provided in the Trust Indenture, all written instruments signed by or on our behalf must contain a provision to the effect that such obligation will not be binding upon Unitholders personally. Personal liability may also arise in respect of claims against 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 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. For additional information see “Risk Factors – Unitholder Limited Liability”.

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 the Unitholders for claims against us.

Stability Rating

The Trust does not have a stability rating.

HUMAN RESOURCES

General

We currently employ 57 full-time employees (53 are located in the head office and 4 are field employees), 17 consultants (8 full time and 9 part-time consultants), and one co-op student. We intend to add additional professional and administrative staff as the need arises.

INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS

There were no material interests, direct or indirect, of directors and senior officers of True Energy, any holder of Trust Units or Exchangeable Shares who beneficially owns more than 10% of the outstanding Trust Units or Exchangeable Shares respectively, or any known associate or affiliate of such persons, in any transaction within the three most recently completed financial years or during the current financial year which has materially affected or would materially affect us other than as follows:

Certain directors and executive officers, or former directors or executive officers, of True Energy Inc. received certain consideration in connection with the True Arrangement completed effective November 2, 2005. Please see “Interests of Certain Persons or Companies in the Matters to be Acted Upon” contained in the Information Circular – Proxy Statement of True Energy dated September 30, 2005 provided to shareholders of True Energy in connection with the True Arrangement, which section is hereby incorporated by reference.

In connection with the True Arrangement completed effective November 2, 2005, all outstanding Incentive Rights held by certain former directors and executive officers of TKE Energy Inc. were accelerated in connection with the

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completion of the True Arrangement and were exercised either for cash or on an intrinsic value basis prior to completion of the True Arrangement. Certain former executive officers of TKE Energy Inc. also received certain termination payments in accordance with the terms of their employment agreements with TKE Energy Inc. for an aggregate of approximately $1.9 million.

Certain executive officers, directors and former executive officers and directors of True Energy Inc. participated in the initial private placement of Vero Energy Inc. (“Vero”), the junior exploration and development company which was formed in conjunction with the True Arrangement. These executive officers, directors and former executive officers and former directors of True Energy subscribed for an aggregate of 1,846,845 common shares of Vero at a price of $2.22 per share.

Raymond G. Smith, a director of True and a former officer and director of Meridian received $278,389 in accordance with the terms of his employment agreement with Meridian in connection with the acquisition by True Energy Inc. of Meridian which was completed effective March 15, 2005.

INTERESTS OF EXPERTS

There is no person or company whose profession or business gives authority to a statement made by such person or company and who is named as having prepared or certified a statement, report or valuation described or included in a filing, or referred to in a filing, made under NI 51-102 by us during, or related to, our most recently completed financial year other than GLJ or Chapman, our independent engineering evaluators and KPMG LLP. None of the principals of GLJ or Chapman had any registered or beneficial interests, direct or indirect, in any of our securities or other property or of our associates or affiliates either at the time they prepared the statement, report or valuation prepared by it, at any time thereafter or to be received by them. KPMG LLP, our auditors, are independent in accordance with the auditors’ rules of professional conduct in Canada.

LEGAL PROCEEDINGS

There are no outstanding legal proceedings material to us or to which we are a party or of which any of our properties is the subject matter nor are there any such proceedings known to be contemplated.

MATERIAL CONTRACTS

The only material contracts entered into by us since our formation and which are presently material, other than during the ordinary course of business, are as follows:

1.the Trust Indenture;

2.the Administration Agreement;

3.the NPI Agreement;

4.the Note Indenture;

5.the Support Agreement; and

6.the Voting and Exchange Trust Agreement.

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

AUDITORS, TRANSFER AGENT AND REGISTRAR

The auditors of the Trust are KPMG LLP, Chartered Accountants, Suite 1200, 205 - 5th Avenue S.W., Calgary, Alberta, T2P 4B9.

Computershare Trust Company of Canada, at its principal offices in Calgary, Alberta and Toronto, Ontario is the transfer agent and registrar of the Trust Units and the Exchangeable Shares.

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ADDITIONAL INFORMATION

Additional information including information relating to remuneration and indebtedness of directors and officers of True, principal holders of the Trust Units, Exchangeable Shares and securities authorized for issuance under our equity compensation plans, will be contained in the information circular relating to our annual meeting of Unitholders to be held on April 24, 2006. Additional financial information is provided in our comparative consolidated financial statements and management discussion and analysis of financial results for the year ended December 31, 2005 which can be found in the Trust’s 2005 Financial Report to Unitholders. Alternatively, additional information relating to us is available on SEDAR at www.sedar.com.

For copies of our information circular, our comparative consolidated financial statements, including any interim consolidated comparative financial statements and additional copies of the Annual Information Form please contact:

True Energy Trust

c/o True Energy Inc.

Suite 2300, 530 - 8th Avenue S.W.

Calgary, Alberta T2P 3S8

Tel: (403) 266-8670

Fax: (403) 264-8163

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SCHEDULE “A”
FORM 51-101F3
REPORT OF MANAGEMENT AND DIRECTORS ON OIL AND GAS DISCLOSURE

Management of True Energy Inc. on behalf of True Energy Trust (collectively, “True”) are responsible for the preparation and disclosure of information with respect to True’s oil and gas activities in accordance with securities regulatory requirements. This information includes reserves data, which consist of the following:

(a)	(i)	proved and proved plus probable oil and gas reserves estimated as at December 31, 2005 using forecast prices and costs; and
	(ii)	the related estimated future net revenue; and
(b)	(i)	proved oil and gas reserves estimated as at December 31, 2005 using constant prices and costs; and
	(ii)	the related estimated future net revenue.

Independent qualified reserves evaluators have evaluated True’s reserves data. The report of the independent qualified reserves evaluators is presented below.

The Reserves Committee of the board of directors of True Energy has

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

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

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

The Reserves Committee of the board of directors of True Energy has reviewed True’s procedures for assembling and reporting other information associated with oil and gas activities and has reviewed that information with management. The board of directors has approved

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

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

(c)the content and filing of this report.

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

DATED as of this 27th day of March, 2006.

(signed) “Paul R. Baay”	(signed) “Wayne B. Jessee”
Paul R. Baay	Wayne B. Jessee
President & Chief Executive Officer	Vice-President & Chief Operating Officer
(signed) “W. C. (Mickey) Dunn”	(signed) “Murray B. Todd”
W. C. (Mickey) Dunn	Murray B. Todd
Director & Chairman of the Board of Directors	Director & Chairman of the Reserves
	Committee

SCHEDULE “B”
FORM 51-101F2
REPORT ON RESERVES DATA
BY INDEPENDENT QUALIFIED RESERVES EVALUATORS

To the board of directors of True Energy Inc. (the “Company”):

1.We have prepared an evaluation of the Company’s reserves data as at December 31, 2005. The reserves data consist of the following:

(a)	(i)	proved and proved plus probable oil and gas reserves estimated as at December 31, 2005 using forecast prices and costs; and
	(ii)	the related estimated future net revenue; and
(b)	(i)	proved oil and gas reserves estimated as at December 31, 2005 using constant prices and costs; and
	(ii)	the related estimated future net revenue.

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

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

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

4.The following table sets forth the estimated future net revenue (before deduction of income taxes) attributed to proved plus probable reserves, estimated using forecast prices and costs and calculated using a discount rate of 10 percent, included in the reserves data of the Company evaluated by us for the year ended December 31, 2005, and identifies the respective portions thereof that we have audited, evaluated and reviewed and reported on to the Company’s board of directors:

Independent Qualified Reserves Evaluator	Description and Preparation Date of Evaluation Report	Location of Reserves (County or Foreign Geographic Area)	Net Present Value of Future Net Revenue ($000, before income taxes, 10% discount rate)
			Audited	Evaluated		Reviewed	Total
GLJ Petroleum Consultants	February 10, 2006	Canada	—	$	384,630	—	$	384,630
Chapman Petroleum Engineering Ltd.	February 10, 2006	Canada	—	$	118,170	—	$	118,170
Totals			—	$	502,800	—	$	502,800

5.In our opinion, the reserves data respectively evaluated by us have, in all material respects, been determined and are in accordance with the COGE Handbook.

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

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

EXECUTED as to our report referred to above:

GLJ Petroleum Consultants Ltd., Calgary, Alberta Canada February 27, 2006

Per:	(signed) “Neil I. Dell”
	Neil I. Dell, P.Eng.
Chapman Petroleum Engineering Ltd., Calgary, Alberta Canada February 27, 2006
Per:	(signed) “Charlie Chapman”
	Charlie Chapman, P.Eng.

SCHEDULE “C”

MANDATE

MANDATE AND TERMS OF REFERENCE OF THE AUDIT COMMITTEE

Role and Objective

The Audit Committee (the “Committee”) is a committee of the Board of Directors (the “Board”) of True Energy Inc. (“True”), in its capacity as the administrator of True Energy Trust (the “Trust”), to which the Board has delegated its responsibility for the oversight of the following respecting the Trust:

1.nature and scope of the annual audit;

2.the oversight of management’s reporting on internal accounting standards and practices;

3.the review of financial information, accounting systems and procedures;

4.financial reporting and financial statements,

and has charged the Committee with the responsibility of recommending, for approval of the Board, the audited financial statements, interim financial statements and other mandatory disclosure releases containing financial information.

The primary objectives of the Committee are as follows:

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

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

3.To enhance the external auditor’s independence;

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

5.To strengthen the role of the outside Directors by facilitating in depth discussions between Directors on the Committee, management of True (“Management”) and external auditors.

Membership of Committee

1.The Committee will be comprised of at least three (3) Directors or such greater number as the Board may determine from time to time and all members of the Committee shall be “independent” (as such term is used in Multilateral Instrument 52-110 — Audit Committees (“MI 52-110”) unless the Board determines that the exemption contained in MI 52-110 is available and determines to rely thereon.

2.The Board may from time to time designate one of the members of the Committee to be the Chair of the Committee.

3.All of the members of the Committee must be “financially literate” (as defined in MI 52-110) unless the Board determines that an exemption under MI 52-110 from such requirement in respect of any particular member is available and determines to rely thereon in accordance with the provisions of MI 52-110.

Mandate and Responsibilities of Committee

It is the responsibility of the Committee to:

1.Oversee the work of the external auditors, including the resolution of any disagreements between Management and the external auditors regarding financial reporting.

2.Satisfy itself on behalf of the Board with respect to the Trust’s internal control systems.

3.Review the annual and interim financial statements of the Trust and related management’s discussion and analysis (“MD&A”) prior to their submission to the Board for approval. The process should include but not be limited to:

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

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

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

•ascertaining compliance with covenants under loan agreements;

•reviewing disclosure requirements for commitments and contingencies;

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

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

•obtain explanations of significant variances with comparative reporting periods.

4.Review the financial statements, prospectuses, MD&A, annual information forms (“AIF”) and all public disclosure containing audited or unaudited financial information (including, without limitation, annual and interim press releases and any other press releases disclosing earnings or financial results) before release and prior to Board approval. The Committee must be satisfied that adequate procedures are in place for the review of the Trust’s disclosure of all other financial information and will periodically assess the accuracy of those procedures.

5.With respect to the appointment of external auditors by the Board:

•recommend to the Board the external auditors to be nominated;

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

•on an annual basis, review and discuss with the external auditors all significant relationships such auditors have with the Trust to determine the auditors’ independence;

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

•review and pre-approve any non-audit services to be provided to the Trust or its subsidiaries by the external auditors and consider the impact on the independence of such auditors. The Committee may delegate to one or more independent members the authority to pre–approve non–audit services, provided that the member(s) report to the Committee at the next scheduled meeting such pre-approval and the member(s) comply with such other procedures as may be established by the Committee from time to time.

6.Review with external auditors (and internal auditor if one is appointed by the Trust) their assessment of the internal controls of the Trust, their written reports containing recommendations for improvement, and Management’s response and follow-up to any identified weaknesses. The Committee will also review annually with

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the external auditors their plan for their audit and, upon completion of the audit, their reports upon the financial statements of the Trust and its subsidiaries.

7.Review risk management policies and procedures of the Trust (i.e. hedging, litigation and insurance).

8.Establish a procedure for:

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

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

9.Review and approve the Trust’s and its subsidiary’s hiring policies regarding partners and employees and former partners and employees of the present and former external auditors of the Trust.

The Committee has authority to communicate directly with the internal auditors (if any) and the external auditors of the Trust. The Committee will also have the authority to investigate any financial activity of the Trust. All employees of the Trust are to cooperate as requested by the Committee.

The Committee may also retain persons having special expertise and/or obtain independent professional advice to assist in filling their responsibilities at such compensation as established by the Committee and at the expense of the Trust without any further approval of the Board.

Meetings and Administrative Matters

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

2.The Chair will preside at all meetings of the Committee, unless the Chair is not present, in which case the members of the Committee that are present will designate from among such members the Chair for purposes of the meeting.

3.A quorum for meetings of the Committee will be a majority of its members, and the rules for calling, holding, conducting and adjourning meetings of the Committee will be the same as those governing the Board unless otherwise determined by the Committee or the Board.

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

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

6.Agendas, approved by the Chair, will be circulated to Committee members along with background information on a timely basis prior to the Committee meetings.

7.The Committee may invite such officers, directors and employees of the Trust and its subsidiaries as it sees fit from time to time to attend at meetings of the Committee and assist in the discussion and consideration of the matters being considered by the Committee.

8.Minutes of the Committee will be recorded and maintained and circulated to Directors who are not members of the Committee or otherwise made available at a subsequent meeting of the Board.

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9.The Committee may retain persons having special expertise and may obtain independent professional advice to assist in fulfilling its responsibilities at the expense of the Trust or the Corporation, as determined by the Committee.

10.Any members of the Committee may be removed or replaced at any time by the Board and will cease to be a member of the Committee as soon as such member ceases to be a Director. The Board may fill vacancies on the Committee by appointment from among its members. If and whenever a vacancy exists on the Committee, the remaining members may exercise all its powers so long as a quorum remains. Subject to the foregoing, following appointment as a member of the Committee each member will hold such office until the Committee is reconstituted.

11.Any issues arising from these meetings that bear on the relationship between the Board and Management should be communicated to the Chairman of the Board by the Committee Chair.

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