Primewest Energy Trust 40F 2006 Annual report | PWI Filing

Certain statements contained in this Annual Information Form, and in certain documents incorporated by reference into this Annual Information Form, constitute forward-looking statements. The use of any of the words "anticipate", "continue", "estimate", "expect", "forecast", "may", "will", "project", "should", "believe", "outlook" and similar expressions are intended to identify forward-looking statements. In addition, statements relating to "reserves" or "resources" are deemed to be forward-looking statements, as they involve implied assessment, based on certain estimates and assumptions, that the resources and reserves described can be profitably produced in the future. These statements involve known and unknown risks, uncertainties and other fact ors that may cause actual results or events to differ materially from those anticipated in our forward-looking statements.

We believe the expectations reflected in those forward-looking statements are reasonable. However, we cannot assure you that these expectations will prove to be correct. You should not unduly rely on forward-looking statements included in, or incorporated by reference into, this Annual Information Form. These statements speak only as of the date of this Annual Information Form or as of the date specified in the documents incorporated by reference into this Annual Information Form, as the case may be.

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

The quantity and recoverability of our reserves:

The timing and amount of future production

Prices for oil, natural gas and natural gas liquids produced;

Operating and other costs;

Business strategies and plans of management;

Supply and demand for oil and natural gas;

Expectations regarding our ability to raise capital and to add to our reserves through acquisitions and exploration and development;

Our treatment under governmental regulatory regimes;

The focus of capital expenditures on development activity rather than exploration;

The sale, farming in, farming out or development of certain exploration properties using third-party resources;

The objective to achieve a predictable level of monthly cash distributions;

The use of development activity and acquisitions to replace and add to reserves;

The impact of changes in oil and natural gas prices on cash flow after hedging;

Drilling plans;

The existence, operations and strategy of the commodity price risk management program;

The approximate and maximum amount of forward sales and hedging to be employed;

Our acquisition strategy, the criteria to be considered in connection therewith and the benefits to be derived therefrom;

The impact of the Canadian federal and provincial governmental regulations on us relative to other oil and natural gas issuers of similar size;

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

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ANNUAL INFORMATION FORM 2005

The emergence of accretive growth opportunities; and

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

With respect to forward-looking statements contained in this Annual Information Form, including the documents incorporated herein by reference, we have made assumptions regarding, among other things:

Future oil and natural gas prices and differentials between light, medium and heavy oil prices;

The cost of expanding our property holdings;

Our ability to obtain equipment in a timely manner to carry out development activities;

Our ability to market our oil and natural gas successfully to current and new customers;

The impact of increasing competition;

Our ability to obtain financing on acceptable terms; and

Our ability to add production and reserves through our development and exploitation activities.

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

Volatility in market prices for oil and natural gas;

The impact of weather conditions on seasonal demand;

Risks inherent in our oil and natural gas operations;

Uncertainties associated with estimating reserves;

Competition for, among other things: capital, acquisitions of reserves, undeveloped lands and skilled personnel;

Incorrect assessments of the value of acquisitions;

Geological, technical, drilling and processing problems;

General economic conditions in Canada, the United States and globally;

Industry conditions, including fluctuations in the price of oil and natural gas;

Royalties payable in respect of our oil and natural gas production;

Government regulation of the oil and natural gas industry, including environmental regulation;

Fluctuation in foreign exchange or interest rates;

Unanticipated operating events that can reduce production or cause production to be shut-in or delayed;

Failure to obtain industry partner and other third-party consents and approvals, when required;

Stock market volatility and market valuations;

OPEC's ability to control production and balance global supply and demand of crude oil at desired price levels;

Political uncertainty, including the risks of hostilities, in the petroleum producing regions of the world;

The need to obtain required approvals from regulatory authorities; and

The other factors discussed under "Risk Factors" contained this Annual Information Form.

These factors should not be construed as exhaustive. The forward-looking statements contained in this Annual Information Form and the documents incorporated by reference herein are expressly qualified by this cautionary statement. We undertake no obligation to publicly update or revise any forward-looking statements.

PRIME WEST ENERGY TRUST
ANNUAL INFORMATION FORM 2005

PrimeWest does not endorse any of the analyst or consultant sourced material contained herein.

All figures reported in Canadian dollars unless otherwise stated.

Production figures stated are Company Interest before the deduction of royalties.

PRIMEWEST ENERGY TRUST

ANNUAL INFORMATION FORM 2005

ITEM 1: ORGANIZATION

PrimeWest Energy Trust (the “Trust”) is an open-end investment trust created under the laws of Alberta pursuant to the Declaration of Trust. The undertaking of the Trust is to issue Trust Units to the public and to invest the Trust's funds, directly or indirectly, in Oil and Natural Gas Properties and assets related thereto. The sole beneficiaries of the Trust are the holders of Trust Units. Computershare Trust Company of Canada (“Computershare”) or its successor is the trustee of the Trust (the “Trustee”). The head office of PrimeWest is 5100, 150 – 6th Ave SW, Calgary, Alberta, T2P 3Y7. The registered office of PrimeWest is 4300 888 3rd Street SW, Calgary, Alberta, T2P 5C5.

PrimeWest Energy Inc. (“PrimeWest” or the “Operating Company”) was incorporated under the Business Corporations Act (Alberta) on March 4, 1996 and was amalgamated with PrimeWest Oil and Gas Corp., PrimeWest Royalty Corp. and PrimeWest Resources Ltd. on January 1, 2002 and continued as PrimeWest Energy Inc. PrimeWest was amalgamated with PrimeWest Management Inc. (the “Manager”) and Delgrae Energy Corporation on November 6, 2002 and continued as PrimeWest Energy Inc.

PrimeWest is wholly owned by the Trust. PrimeWest’s business is the acquisition, development, exploitation, Production and marketing of Oil and Natural Gas and granting the Royalty to the Trust.

PrimeWest Gas Corp. (“PrimeWest Gas”) was amalgamated under the Business Corporations Act (Alberta) on January 24, 2003 in connection with the acquisition by PrimeWest of two privately held Canadian corporations. PrimeWest Gas is wholly owned by PrimeWest and is an operating subsidiary of PrimeWest and the Trust. PrimeWest Gas was amalgamated with the Operating Company on January 1, 2006 and continued as PrimeWest.

The principal undertaking of the Trust is to acquire and hold, directly and indirectly, interests in Oil and Natural Gas Properties. One of the Trust's primary assets is the Royalty granted by PrimeWest pursuant to the Royalty Agreements. The Royalty entitles the Trust to receive 99% of the net cash flow generated by the Oil and Natural Gas interests held from time to time by PrimeWest, after certain costs and deductions. The balance of such net cash flow may be retained by PrimeWest to fund its working capital and other business and operating requirements, or may be passed on to the Trust to support distributions to Unitholders. The Distributable Income resulting from the Royalty and other amounts received by the Trust is then distributed monthly to Unitholders.

TRUST STRUCTURE

The following diagram represents the current structure of the Trust and shows the flow of funds from the Oil and Natural Gas Properties owned, directly or indirectly, by PrimeWest and the gross overriding royalties owned directly by the Trust, as well as the flow of funds to PrimeWest, and from the Trust to Unitholders:

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Notes:

(1)

The Trust also directly owns certain gross overriding royalty interests.

(2)

PrimeWest, directly and indirectly through its subsidiaries, actively manages its Oil and Natural Gas Properties to maximize cash flow and Reserve value.

(3)

In conjunction with the amalgamation, the royalty payable by PrimeWest Gas to the Trust became the obligation of PrimeWest, as successor to PrimeWest Gas.

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ANNUAL INFORMATION FORM 2005

THE DECLARATION OF TRUST

The Declaration of Trust, among other things, provides for the calling of meetings of Unitholders, the conduct of business at those meetings, notice provisions, the appointment, resignation and removal of the Trustee and the form of Trust Unit certificates. The Declaration of Trust may be amended from time to time. Substantive amendments to the Declaration of Trust, including extension or early termination of the Trust and the sale or transfer of the property of the Trust as an entirety, or substantially as an entirety, require approval by special resolution of the Unitholders.

The following is a summary of certain provisions of the Declaration of Trust. Complete copies of the Declaration of Trust, may be viewed at the offices of, or obtained from the Trustee.

TRUST UNITS

An unlimited number of Trust Units may be issued pursuant to the Declaration of Trust, each of which represents an equal fractional undivided beneficial interest in the Trust entitling the holder to receive monthly distributions of Distributable Income.

All Trust Units share equally in all distributions from the Trust, carry equal voting rights at meetings of Unitholders, and have a right of redemption on terms set out in the Declaration of Trust. No Unitholder is liable to pay any further calls or assessments in respect of the Trust Units.

The Trust Units are not "deposits" within the meaning of theCanada Deposit Insurance Corporation Act (Canada) and are not insured under the provisions of that, 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.

EXCHANGEABLE SHARES OF PRIMEWEST

An unlimited number of Exchangeable Shares may be issued by the Operating Company, each of which entitles the holder to exchange such Exchangeable Share at any time into a number of Trust Units based on an exchange ratio then in effect. The exchange ratio is determined by reference to the distributions paid on Trust Units in a given month and the current market price of the Trust Units. On December 31, 2005, each Exchangeable Share was exchangeable for 0.56399 Trust Units.

PrimeWest issued Exchangeable Shares in connection with the acquisitions of the Manager in November 2002, Cypress in March 2001 and Venator in April 2000. Shareholders of the Manager, Cypress and Venator who received Exchangeable Shares could in certain circumstances defer the tax consequences of that exchange. PrimeWest may issue additional Exchangeable Shares in connection with future acquisitions or to address other capital requirements.

The Exchangeable Shares provide holders with economic terms and voting rights, which are, as nearly as practicable, equivalent to those of Trust Units. The Exchangeable Shares are maintained economically equivalent to the Trust Units by the progressive increase in the exchange ratio, incorporating the distributions provided to Unitholders and reflecting the right to acquire an ever-increasing number of Trust Units per Exchangeable Share. The Exchangeable Shares are provided voting rights equivalent to those of Unitholders through a voting trust agreement pursuant to which the holders of Exchangeable Shares can direct Computershare, in its capacity as the voting and exchange trustee, to vote at meetings of Unitholders. The Exchangeable Shares are listed and posted for trading on the TSX under the symbol “PWX”.

TRUSTEE

Computershare is the current Trustee of the Trust and also acts as the transfer agent for the Trust Units, the Exchangeable Shares, the Series I Debentures and the Series II Debentures. The Trustee is responsible for, among other things: (a) accepting subscriptions for Trust Units and issuing Trust Units pursuant thereto; (b) maintaining the books and records of the Trust and providing timely reports to holders of Trust Units; and (c) paying cash distributions to Unitholders.

The Declaration of Trust provides that the Trustee is to 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, must exercise that degree of care, diligence and skill that a reasonably prudent trustee would exercise in comparable circumstances.

The current term of the Trustee's appointment expires at the conclusion of the 2007 annual meeting of Unitholders that takes place in 2008. Thereafter, the Trustee will be reappointed or changed every third annual meeting as may be determined by a majority of the votes cast at a meeting of the Unitholders. The Trustee may also be removed by a

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ANNUAL INFORMATION FORM 2005

majority vote of the Unitholders in that regard. The Trustee may resign on 60 days' notice to PrimeWest. That resignation or removal becomes effective on the appointment of a successor trustee along with the acceptance of that appointment and the assumption of the obligations of the Trustee by that successor trustee.

CASH DISTRIBUTIONS

Cash distributions of Distributable Income are made on a monthly basis on the Cash Distribution Date following the end of each month, to Unitholders of record on the Record Date in that month. Since August 2003, PrimeWest has followed a strategy of maintaining distributions within approximately 70% to 90% of cash flow from operations, calculated on an annual basis. The strength in commodity prices experienced in 2005 increased the Trust’s cash flow available for distribution. On December 7, 2005, the Trust announced a 20% increase to distribution payments to $0.36 per Trust Unit from $0.30 per Trust Unit effective on the January 13, 2006 Cash Distribution Date.

PrimeWest recognizes that, during periods of volatile commodity prices, the payout ratio may move outside of the targeted 70% to 90% payout range. The Board of Directors considers a variety of factors in establishing the monthly distribution level, including, but not limited to: commodity price outlook, cash flow forecast, capital development plans, debt levels, taxability considerations and competitive industry distribution practices.

The following table sets forth the per Trust Unit amount of monthly cash distributions since 2003.


Record Date⁽¹⁾	Payable Date	Cdn$ Amount	US/Cdn$ Exchange Rate⁽²⁾	US$ Amount
Dec. 31, 2002	Jan. 15, 2003	0.400	1.5368	0.2603
Jan. 31, 2003	Feb. 14, 2003	0.400	1.5231	0.2626
Feb. 28, 2003	Mar. 14, 2003	0.400	1.4732	0.2715
Mar. 31, 2003	Apr. 15, 2003	0.400	1.4498	0.2759
Apr. 30, 2003	May. 15, 2003	0.400	1.3825	0.2893
May. 30, 2003	Jun. 13, 2003	0.400	1.3350	0.2996
Jun. 30, 2003	Jul. 15, 2003	0.400	1.3921	0.2873
Jul. 31, 2003	Aug. 15, 2003	0.320	1.3934	0.2297
Aug. 29, 2003	Sep. 15, 2003	0.320	1.3638	0.2346
Sep. 30, 2003	Oct. 15, 2003	0.320	1.3262	0.2413
Oct. 31, 2003	Nov. 14, 2003	0.320	1.3023	0.2457
Nov. 28, 2003	Dec. 15, 2003	0.320	1.3134	0.2436
2003 Total		$ 4.40		$ 3.1414
Dec. 22, 2003	Jan. 15, 2004	0.320	1.2979	0.2465
Jan. 22, 2004	Feb. 13, 2004	0.320	1.3163	0.2431
Feb. 20, 2004	Mar. 15, 2004	0.250	1.3340	0.1874
Mar. 22, 2004	Apr. 15, 2004	0.250	1.3432	0.1861
Apr. 22, 2004	May. 14, 2004	0.250	1.3902	0.1798
May. 21, 2004	Jun. 15, 2004	0.250	1.3688	0.1826
Jun. 22, 2004	Jul. 15, 2004	0.250	1.3246	0.1887
Jul. 22, 2004	Aug. 13, 2004	0.250	1.3089	0.1910
Aug. 23, 2004	Sep. 15, 2004	0.275	1.2972	0.2120
Sep. 22, 2004	Oct. 15, 2004	0.300	1.2526	0.2395
Oct. 22, 2004	Nov. 15, 2004	0.300	1.2005	0.2499
Nov. 23, 2004	Dec. 15, 2004	0.300	1.2247	0.2450
Dec. 22, 2004	Jan. 14, 2005	0.300	1.2156	0.2468
2004 Total		$ 3.615		$ 2.7984
Record Date⁽¹⁾	Payable Date	Cdn$ Amount	US/Cdn$ Exchange Rate⁽²⁾	US$ Amount
Jan. 20, 2005	Feb. 15, 2005	0.300	1.2306	0.2438

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Feb. 22, 2005	Mar. 15, 2005	0.300	1.2069	0.2486
Mar. 22, 2005	Apr. 15, 2005	0.300	1.2467	0.2406
Apr. 22, 2005	May 13, 2005	0.300	1.2653	0.2370
May 20, 2005	Jun. 15, 2005	0.300	1.2374	0.2424
Jun. 22, 2005	Jul. 15, 2005	0.300	1.2207	0.2458
Jul. 26, 2005	Aug. 15, 2005	0.300	1.1993	0.2501
Aug. 23, 2005	Sep. 15, 2005	0.300	1.1848	0.2532
Sep. 22, 2005	Oct. 14, 2005	0.300	1.1854	0.2531
Oct. 24, 2005	Nov. 15, 2005	0.300	1.1922	0.2516
Nov. 23, 2005	Dec. 15, 2005	0.300	1.1598	0.2587
Dec. 22, 2005	Jan. 13, 2006	0.360	1.1604	0.3102
2005 Total		$ 3.660		$3.035

⁽¹⁾

Monthly information refers to the month in which the Record Date for the relevant distribution occurs with payment being made on the Cash Distribution Date in the following month.

⁽²⁾

Exchange rate information is based on the exchange rate in effect on the date of payment.

As of January 2004, Canadian securities law states that the taxability for distributions are on an accrual basis, based on the month the Record Date falls in (i.e. the December record date with a January distribution payment is taxable in the previous year). US securities law states that the taxability for distributions are on an actual basis (i.e. only the payments made in the current tax year are considered taxable).

REDEMPTION RIGHT

Trust Units are redeemable at any time on demand by the holder thereof upon delivery to the Trust of the certificates representing such Trust Units accompanied by a duly completed and properly executed notice requesting redemption. Upon the receipt of the redemption request, all of the Unitholder's rights to and under the Trust Units tendered for redemption are surrendered and the Unitholder becomes entitled to receive a price per Trust Unit as determined by a market price formula, subject to a monthly aggregate cash cap of $100,000. The redemption price payable by the Trust may be satisfied by way of a cash payment, or in certain circumstances, such as a payment that would cause the monthly cash cap to be exceeded, by way of an in specie distribution.

MEETINGS AND VOTING

Annual meetings of the Unitholders commenced in 1997. Special meetings of Unitholders may be called at any time by the Trustee and will be called by the Trustee on the written request of Unitholders holding in aggregate not less than 20% of the outstanding Trust Units. Notice of all meetings of Unitholders will be given to Unitholders at least 21 days and not more than 50 days prior to the meeting.

Unitholders may attend and vote at all meetings of such Unitholders either in person or by proxy and a proxy holder need not be a holder of Trust Units. At least two 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 constitute a quorum for the transaction of business at all of those meetings. Unitholders are entitled to one vote per Trust Unit.

LIMITATION ON NON-RESIDENT OWNERSHIP AND TAXATION

As a result of the process commenced by Ralph Goodale, the Minister of Finance of Canada, through a Notice of Ways and Means Motion introduced in December 2004, legislation took effect on January 1, 2005, providing for a 15% withholding tax on the entire distribution paid to non-resident Unitholders, including that portion deemed a return of capital. Distributions paid into tax-exempt and tax-deferred accounts in the United States are included in this provision. Under the new legislation, such amounts are now subject to a 15% non-resident withholding tax, and it is no longer possible for a non-resident Unitholder to obtain a refund of such withheld amounts (except in certain limited circumstances, where the non-resident Unitholder disposes of Trust Units at a loss). PrimeWest continues to recommend that non-resident Unitholders contact their tax advisors in order to obtain de tails of the implications arising from the implementation of this new withholding tax.

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ANNUAL INFORMATION FORM 2005

On November 23, 2005, the Minister of Finance concluded the consultation process regarding income trust sector taxation that was initiated in September 2005, confirming that there will be no additional taxation of Income Trusts. At the same time, the Minister proposed a reduction in the personal income tax on dividend income, reducing the “double taxation” of corporate dividends, providing additional certainty and stability to the trust sector. This change better aligns the dividend tax treatment with the tax treatment of income trust distribution payments. The government also announced that it would resume providing advance tax rulings on flow-through entity structures.

Following the outcome of the consultation process, PrimeWest continues not to be subject to any restrictions on non-resident ownership of its Trust Units, and there is no specified date on or before which it will become subject to any such restrictions. In the event that the Department of Finance determines to limit the extent to which non-residents are permitted to invest in units of royalty trusts (including PrimeWest), or PrimeWest otherwise becomes subject to the existing limitations in paragraph 132(7)(a) of the Tax Act that apply to other mutual fund trusts, the Declaration of Trust as amended at the last annual meeting held on May 6, 2004, provides:

If at any time the Board of Directors of PrimeWest determines, in its sole discretion, or becomes aware, that the Trust’s ability to continue to rely on paragraph 132(7)(a) of the Tax Act for purposes of qualifying as a “mutual fund trust” thereunder is in jeopardy, then the Trust shall not be maintained primarily for the benefit of non-residents of Canada and it shall be the sole responsibility of PrimeWest to monitor the holdings by non-residents of Canada and take such steps as are necessary or desirable to ensure that the Trust is not maintained primarily for the benefit of non-residents of Canada;

PrimeWest may request that the Trustee make reasonable efforts, as practicable in the circumstances, to obtain declarations as to beneficial ownership, perform residency searches of Unitholder and beneficial Unitholder mailing address lists and take such other steps specified by PrimeWest to determine or estimate as best possible the residence of the beneficial owners of Trust Units; and

If at any time the Board of Directors of PrimeWest, in its sole discretion, determines that it is in the best interest of the Trust, PrimeWest may, notwithstanding the ability of the Trust to continue to rely on paragraph 132(7)(a) of the Tax Act:

(i)

Require the Trustee to refuse to accept a subscription for Trust Units from, or issue or register a transfer of Trust Units to, a person unless the person provides a declaration to PrimeWest that the Trust Units to be issued or transferred to such person will not when issued or transferred be beneficially owned by a non-resident of Canada;

(ii)

To the extent practicable in the circumstances, send a notice to registered holders of Trust Units which are beneficially owned by non-residents of Canada, chosen in inverse order to the order of acquisition or registration of such Trust Units beneficially owned by non-residents of Canada or in such other manner as PrimeWest may consider equitable and practicable, requiring them to sell their Trust Units which are beneficially owned by non-residents of Canada or a specified portion thereof within a specified period of not less than 60 days. If the Unitholders receiving such notice have not sold the specified number of such Trust Units or provided PrimeWest with satisfactory evidence that such Trust Units are not beneficially owned by non-residents within such period, PrimeWest may, on behalf of such registered Unitholder, sell such Trust Units and, in the inter im, suspend the voting and distribution rights attached to such Trust Units and make any distribution in respect of such Trust Units by depositing such amount in a separate bank account in a Canadian chartered bank (net of any applicable taxes). Any sale shall be made on any stock exchange on which the Trust Units are then listed and, upon such sale, the affected holders shall cease to be holders of Trust Units so disposed of and their rights shall be limited to receiving the net proceeds of sale, and any distribution in respect thereof deposited as aforesaid, net of applicable taxes and costs of sale, upon surrender of the certificates representing such Trust Units;

(iii)

De-list the Trust Units from any non-Canadian stock exchange; and

(iv)

Take such other actions as the Board of Directors of PrimeWest determines, in its sole discretion, are appropriate in the circumstances that will reduce or limit the number of Trust Units held by non-resident Unitholders to ensure that the Trust is not maintained primarily for the benefit of non-residents of Canada.

COMPULSORY ACQUISITION

The Declaration of Trust provides that if a person, within either 120 days of making an offer to purchase all outstanding Trust Units or the time for acceptance provided in that offer (provided that such offer is open for acceptance for a period of not less than 45 days), whichever period is the shorter, acquires not less than 90% of the outstanding Trust Units (other than those held by that person and its affiliates), that person may acquire the Trust Units of the Unitholders who did not accept the offer on the same terms as those offered to those Unitholders who accepted the offer.

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ANNUAL INFORMATION FORM 2005

TERMINATION OF THE TRUST

The Unitholders may vote to terminate the Trust at any meeting of the Unitholders, provided that the termination must be approved by special resolution of the Unitholders.

Unless the Trust is terminated or extended by vote of the Unitholders earlier, the Trustee will commence to wind-up the affairs of the Trust on December 31, 2095. In the event that the Trust is wound-up, the Trustee will liquidate all the assets of the Trust, pay, retire, discharge or make provision for some or all obligations of the Trust and then distribute the remaining proceeds of the liquidation to Unitholders.

UNITHOLDER RIGHTS PLAN

On March 31, 1999, PrimeWest announced that it had adopted a Unitholder Rights Plan (the “Rights Plan”). Unitholders approved the Rights Plan at the annual meeting of the Unitholders held on May 18, 1999. The Unitholders reconfirmed the Rights Plan at the annual meeting of the Unitholders held on May 21, 2002. At the annual meeting of Unitholders held on May 5, 2005, the Unitholders approved the amendment and restatement of the Rights Plan to provide that Unitholder approval must be sought for the continuance of the Rights Plan at every annual meeting of Unitholders and the Unitholders reconfirmed the Rights Plan for an initial period of one year. The Rights Plan will now expire on the date of PrimeWest’s annual meeting in 2006, unless Unitholders reconfirm the Rights Plan for a further term of one year at that time.

Under the terms of the Rights Plan, a prospective bidder would be encouraged to negotiate the terms of a bid with the Board of Directors of PrimeWest, or to make a "permitted bid", a take-over bid not requiring the approval of the Board of Directors of PrimeWest but having terms and conditions designed to provide the Board of Directors with sufficient time to properly evaluate the bid and its effects, and to seek alternative bidders or to explore other ways of maximizing Unitholder value.

If a Person acquires more than 20% of the Trust Units other than by way of a permitted bid, other Unitholders may, at the discretion of the Board of Directors of PrimeWest, acquire a number of Trust Units at 50% of the then prevailing market price, so as to cause significant dilution to the acquiring Person.

The Rights Plan provides that a permitted bid is a take-over bid meeting the following requirements:

The bid must be made to all Unitholders;

The bid must be open for a minimum of 45 days following the date of the bid, and no Trust Units may be taken up prior to such time;

Take-up and payment of Trust Units may not occur unless the bid is accepted by Unitholders holding more than 50% of the outstanding Trust Units, excluding Trust Units held by the bidder and its associates;

Trust Units may be deposited to or withdrawn from the bid at any time prior to the take-up date; and

If the bid is accepted by Unitholders holding the requisite percentage of Trust Units, the bidder must extend the bid for an additional ten business days to permit other Unitholders to tender into the bid, should they so wish.

The Board of Directors has now determined that the Rights Plan is no longer necessary or in the best interests of the Trust and its Unitholders for the following reasons:

(a)

Canadian securities legislation has been amended to provide for a minimum bid period of 35 days, which should be a sufficient period of time for the Board of Directors to consider a Take over Bid and seek alternatives in order to maximize value for Unitholders;

(b)

PrimeWest has grown to a sufficient size and has a sufficiently broad Unitholder base to make it less likely that it will be subjected to a hostile take-over bid and less likely that any such take-over bid that is made would succeed;

(c)

While not designed to do so, rights plans may discourage potential bidders from making attractive offers for issuers;

(d)

There is a trend towards the discontinuation of rights plans by existing issuers and many new issuers are not implementing rights plans; and

(e)

Corporate governance laws and practices are evolving to the extent that rights plans are viewed as inconsistent with an open and transparent corporate governance system.

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ANNUAL INFORMATION FORM 2005

As a result of the foregoing, PrimeWest will not be requesting the Unitholders to approve the continuance of the Rights Plan for a further term. Therefore, as of the conclusion of the Meeting, the Rights Plan will terminate and be of no further force and effect.

DECISION MAKING

Unitholders are entitled to direct the election of the Board of Directors of PrimeWest, the approval of the financial statements of PrimeWest, the appointment of its auditors and other matters relating to the business and affairs of PrimeWest and the Trust.

The Board of Directors of PrimeWest is responsible for making significant decisions with respect to PrimeWest, including all decisions relating to, among other things: (a) the acquisition and disposition of significant Oil and Natural Gas Properties; (b) the approval of capital expenditure budgets; (c) the approval of risk management activities; and (d) the establishment of credit facilities. In addition, the Trustee has delegated certain matters regarding the Trust to PrimeWest, including all decisions relating to (a) issuances of Trust Units, (b) the determination of the amount of distributions to be made by the Trust, (c) approvals required with regard to any proposed amendment to the Declaration of Trust or the Royalty Agreements and other aspects respecting the relationship between the Trust and PrimeWest, and (d) responding to unsolicited take-over or merger propo sals. The Board of Directors of PrimeWest holds regularly scheduled meetings to review the business and affairs of PrimeWest and the Trust.

ITEM 2: GENERAL DEVELOPMENT OF THE BUSINESS

On October 16, 1996, the Trust completed an initial public offering of 24,900,000 Trust Units (before giving effect to the Consolidation) on an instalment receipt basis of $6.00 payable on October 16, 1996 and $4.00 payable one year later, for total gross proceeds of $249,000,000. The Trust used the net proceeds of that offering, plus the assignment of the right to be paid the final instalment of $4.00 per Trust Unit, to purchase the Royalty from PrimeWest. PrimeWest used the net proceeds from the sale of the Royalty to the Trust and debt to acquire certain Oil and Natural Gas Properties.

Since its inception, PrimeWest has been an active acquirer of Oil and Natural Gas Properties in the Western Canada Sedimentary Basin. Many of those acquisitions were financed, directly or indirectly, through the issuance of Trust Units and Exchangeable Shares. The following tables summarize the more significant acquisitions and financings completed by PrimeWest, directly or indirectly, since January 1, 2003.

ACQUISITIONS


Date	Company/Properties Acquired	Aggregate Purchase Price (currency)	Reserves and Production Acquired
January 2003	Caroline/Peace River Arch	$219.1 million (cash)	15.5 mmBOE⁽¹⁾ 6,800 BOE/day
March 2004	Seventh Energy Ltd.	$34.8 million (cash) plus assumed debt of $9.9 million.	3.3 mmBOE⁽¹⁾ 1,300 BOE/day
September 2004⁽²⁾	Assets of Calpine Canada Natural Gas Partnership	$740 million (cash)	54.8 mmBOE⁽¹⁾ 14,500 BOE/day
September 2004⁽²⁾	6.8 million units of Calpine Natural Gas Trust at $10.89 per unit, representing a 25% equity interest	$72.7 million (cash)	Investment in marketable securities. Market price at December 31, 2004 was $13.45 per share.

Notes:

(1)

Company Interest Proved plus Probable Reserves.

(2)

A Form 51-102F4 – Business Acquisition Report dated November 1, 2004 (the “Business Acquisition Report”) was filed on SEDAR in connection with the Calpine transaction and is specifically incorporated herein by reference.

PRIMEWEST ENERGY TRUST

ANNUAL INFORMATION FORM 2005

PUBLIC OFFERINGS


Date	Number of Securities Issued	Type of Security	Price per Security	Gross Proceeds ($ millions)
February 2003	6,000,000	Trust Units	$ 25.75	$ 154.5
September 2003	3,100,000	Trust Units	$ 25.90	$ 80.3
April 2004	5,400,000	Trust Units	$ 26.30	$ 142.0
September 2004	12,300,000	Trust Units	$ 24.40	$ 300.1
September 2004	150,000	Series I Debentures	$ 1,000.00	$ 150.0
September 2004	100,000	Series II Debentures	$ 1,000.00	$ 100.0

Other significant developments since January 1, 2003 include the following:

On January 8, 2003, PrimeWest announced the appointment of W. Glen Russell as an independent member of the Board of Directors.

On January 23, 2003, PrimeWest closed the purchase of certain Oil and Natural Gas Properties located primarily in the Caroline and Peace River Arch areas of Alberta for a purchase price of $219.1 million. The 2002 exit Production rate for these Properties was approximately 6,800 BOE/day.

On May 7, 2003, PrimeWest announced that it had entered into a private placement debt financing for US$125 million of secured notes with a seven-year term and an effective five and one half year average life at a coupon rate of 4.19%.

On May 26, 2003, PrimeWest announced the appointment of James W. Patek as an independent member of the Board of Directors.

On October 31, 2003, PrimeWest announced that it had received all regulatory approvals for the implementation of a premium distribution component of its existing DRIP. As an alternative to the distribution reinvestment component of the plan, the premium distribution component allows eligible Unitholders to elect to receive a premium cash distribution equal to 102% of the cash that the Unitholder would otherwise have received on the Cash Distribution Date, subject to proration in certain events.

On January 27, 2004 PrimeWest announced that PrimeWest Gas had entered into an agreement to acquire all of the outstanding shares of Seventh Energy Ltd. (“Seventh”) for cash consideration of $34.8 million plus assumed debt of $9.9 million. On February 6, 2004 PrimeWest Gas mailed a formal take-over circular to the shareholders of Seventh, and, following taking up and paying for 92% of the issued and outstanding shares of Seventh pursuant to the take-over on March 16, 2004, completed the compulsory acquisition of the remaining Seventh shares.

In February 2004, the Board of Directors of PrimeWest resolved to establish a new board committee called the Operations and Reserves Committee. In April 2004, as a result of the annual assessment of the Board of Director’s performance, and in order to reflect the establishment of the Operations and Reserves Committee, the Board of Directors resolved to restructure all of the board committees. The effects of this restructuring were to reduce the number of directors sitting on each committee and to transfer the Reserves functions previously handled by the Audit and Reserves Committee to the Operations and Reserves Committee. The names of certain committees were changed to reflect this restructuring such that the current committees of the Board of Directors consist of the Audit and Finance Committee, the Corporate Governance and EH&S Committee, the Operations and Reserves Committee and the Compensation Committee.

On April 15, 2004, PrimeWest announced the appointment of Mr. Peter Valentine as an independent member of the Board of Directors. Mr. Valentine was also appointed as a member of the Audit and Finance Committee of the Board of Directors.

On August 16, 2004, PrimeWest announced that PrimeWest Gas and the Trust had entered into an agreement with Calpine Canada Natural Gas Partnership, Calpine Energy Holdings Limited and Calpine Corporation (“Calpine”) for the purchase of all of the Canadian Oil and Natural Gas Reserves and related assets owned by Calpine Canada Natural Gas Partnership and 6,766,540 trust units of Calpine Natural Gas Trust, owned by Calpine Energy Holdings Limited, for a total consideration of $814.7 million, including closing costs (collectively the “Calpine Acquisition”). The Calpine Acquisition was financed, in part, through a public offering of Trust

PRIMEWEST ENERGY TRUST

ANNUAL INFORMATION FORM 2005

Units and the Series I Debentures and the Series II Debentures, as discussed in greater detail below. The acquisition closed on September 2, 2004.

The Calpine Acquisition included approximately 14,500 BOE/day of high quality, predominantly liquids rich Natural Gas Production in west central and southern Alberta, weighted 83% to Natural Gas, 11% to Natural Gas Liquids and 6% to Crude Oil. Current Production from the Calpine Acquisition is approximately 14,406 BOE/day. Based upon an independent engineering determination as of July 1, 2004, conducted in accordance with NI 51-101, approximately 54.8 mmBOE of Proved plus Probable Reserves, including gross overriding royalty interests, were acquired through this transaction. The Proved plus Probable Reserve Life Index of the Calpine Properties is 10.5 years. The Properties are 73% operated; with an average working interest of approximately 60% and more than one half of the Production is concentrated in three key areas that are in proximity to PrimeWest’s existing core operations. Undeveloped land holdings of 627,306 Net acres and a seismic database, including all interpreted data, were included with the acquired assets. Full tax pools, up to the purchase price of the assets, were also acquired, reducing the taxability of distributions.

In conjunction with the Calpine Acquisition, PrimeWest issued 12,300,000 Units at $24.40 per unit, for gross proceeds of $300.1 million, pursuant to a bought deal financing. In addition, PrimeWest issued $150 million of Series I Debentures and $100 million of Series II Debentures. Total net proceeds from both the Trust Unit offering and the Series I Debentures and Series II Debentures were approximately $525 million.

During the second quarter of 2004, the Alberta Energy and Utilities Board (“EUB”) ruled on the Natural Gas over bitumen issue, which resulted in approximately 330 BOE/day of Production at Ells being permanently shut-in effective July 1, 2004. In October 2004, the Government of Alberta enacted amendments to the Natural Gas Royalty Regulations of 2002 specifically with respect to Gas Production in the affected area. This amendment provides for a technical change to the royalty calculation for Gas producers adversely affected by the EUB shut-in orders. This technical change to the calculation of royalties represents a reduction in royalties paid by PrimeWest to the Province of Alberta.

During 2004, PrimeWest acquired additional Properties in its core areas of Crossfield and at Princess, which forms part of its Southern Alberta Shallow Gas play. Total consideration paid for both Properties was approximately $32 million.

During 2004 and early 2005, PrimeWest closed sales of assets in the areas of Dawson, northern Alberta, southeast Alberta, southwest Saskatchewan and other miscellaneous non-core areas. The divestitures represented Production of approximately 3,000 BOE/day, for proceeds of $104.9 million.

On January 26, 2005, Standard & Poor’s announced the inclusion of income trusts in the S&P/TSX Composite Index, Canada’s benchmark stock index.

On January 27, 2005 the unitholders of Calpine Natural Gas Trust approved the business combination with Viking Energy Royalty Trust. As a result, PrimeWest’s 25% unit ownership of Calpine Natural Gas Trust was converted into an 8.3% unit ownership of Viking Energy Royalty Trust. As of February 24, 2005, PrimeWest sold its 8.3% ownership of Viking Energy Royalty Trust for gross proceeds of $95.8 million, representing a gain of $27.1 million.

On May 5, 2005, Mr. Valentine was appointed as Chair of the Audit and Finance Committee of the Board of Directors.

On May 5, 2005, the Board of Directors approved, subject to regulatory approval, offering the conventional portion of the DRIP to U.S. resident Unitholders. The offering to U.S. resident Unitholders was officially launched on September 8, 2005. This allows both U.S. resident and Canadian resident Unitholders the option of either reinvesting their monthly distributions in Trust Units or continuing to receive cash payments.

On December 16, 2005, Standard & Poor’s included trusts in the S&P/TSX Composite Index at 50% of each respective trusts’ full float. The remaining 50% of the float will be included at the quarterly rebalancing in March 2006. PrimeWest’s weighting in the index is approximately 0.116% at December 31, 2005.

Effective January 1, 2006, PrimeWest Gas was amalgamated into PrimeWest.

Effective February 23, 2006, Mr. Brian Lynam, B.A. Sc., P.Eng. joined the executive team of the Trust in the position of Vice-President, Operations.

PRIMEWEST ENERGY TRUST

ANNUAL INFORMATION FORM 2005

Effective February 23, 2006, Mr. Gordon D. Haun, B.A., LLB, was appointed an officer and General Counsel and Corporate Secretary of the Trust.

ITEM 3: NARRATIVE DESCRIPTION OF THE BUSINESS

THE BUSINESS OF THE TRUST

The undertakings of the Trust are to acquire and hold Oil and Natural Gas Properties, to produce, market and sell Oil, Natural Gas and Natural Gas Liquids from such Properties and to distribute the Distributable Income generated therefrom to Unitholders. It is therefore the mandate of PrimeWest to continue to source and acquire Oil and Natural Gas Properties both for and on behalf of itself and the Trust, and to enhance the Production from both acquired and existing Properties in order to increase the amount of Distributable Income distributed to Unitholders.

OPERATORSHIP

While operatorship of the Properties generally involves higher General and Administrative Costs than would be required for non-operated Properties, PrimeWest believes that those higher costs will generally result in more opportunities to enhance value to Unitholders through Production enhancement, control of facilities, control of costs and increased access to acquisition opportunities in core areas.

Currently, PrimeWest operates Properties representing approximately 80% of the aggregate daily Production.

ACQUISITIONS

Unless PrimeWest and the Trust are able to acquire additional Oil and Natural Gas Reserves or increase Reserves through development activities, Production from the currently held Properties will continue to decline. PrimeWest continually reviews opportunities for the acquisition of producing Oil and Natural Gas Properties. When considering the acquisition of any Oil and Natural Gas producing Property, PrimeWest focuses on longer-life Reserves, with lower reservoir risk, that may be operated by either PrimeWest or other acceptable operators and that have the potential to increase Distributable Income and enhance the Trust's value through exploitation of those Properties.

RISK MANAGEMENT & MARKETING

Prices received for Production are impacted in varying degrees by factors outside of the Trust’s control. These factors include but are not limited to the following:

Political uncertainty, including the risk of hostilities, in the petroleum producing regions of the world;

OPEC’s ability to control Production to balance global supply and demand at desired price levels;

Global economic growth and the resultant impact on energy demand;

The effect of energy conservation and government regulations;

The impact of weather conditions on supply and seasonal demand;

The price levels and availability of competing alternative fuels;

Increases or decreases in the price differential between light and Heavy Oil;

The impact of US/Canadian currency exchange on the Canadian prices realized by the Trust.

The above factors are outside the control of PrimeWest and can significantly affect the level of cash available for distribution to Unitholders. To mitigate the impact of some of these risks, through its commodity risk management program, PrimeWest actively uses financial hedging instruments to reduce the impact of the volatility of commodity prices. The Audit and Finance Committee, under guidelines approved by the Board of Directors, oversees the commodity risk management program. The effect of hedging activities is reviewed regularly by the Board of Directors and is fully disclosed externally through filings on SEDAR, EDGAR, quarterly releases and our website (www.primewestenergy.com).

As part of PrimeWest's risk-management strategy in 2005, 60% of full-year Crude Oil Production (2004 – 58%) and 55% of full-year Natural Gas Production (2004 – 54%) was hedged, net of royalties. Hedging strategies included the utilization of financial instruments with the primary objective of enhancing the stability of cash distributions. PrimeWest also utilized an electrical power hedge during 2005. The power hedge consisted of an electricity swap comprised of 5 megawatts, representing approximately 25% of PrimeWest’s total electrical power requirements. For the year ended December 31,

PRIMEWEST ENERGY TRUST

ANNUAL INFORMATION FORM 2005

2005, the cash impact of contracts settling was a $43.5 million loss comprised of a $23.6 million loss in Crude Oil, a $20.7 million loss in Natural Gas and a $0.8 million gain on electrical power.

The Gas hedging instruments consist of swaps, costless collars and 3-way deals. Costless collars involve the simultaneous purchase of a put option and sale of a call option at no cost. 3-way deals consist of the simultaneous purchase of a near the money put option and the sale of both an out of the money put and an out of the money call, all at no cost. The Oil hedging instruments also consist of swaps, costless collars and 3-way deals.

As at March 9, 2006:

PrimeWest has employed hedging structures using option-based instruments on approximately 55% of anticipated base Crude Oil Production, net of royalties, for 2006 and on 12% of its anticipated base Crude Oil Production, net of royalties, for 2007;

PrimeWest has employed hedging structures using option-based instruments on approximately 50% of anticipated base Natural Gas Production, net of royalties, for 2006 and on approximately 7% of anticipated base Natural Gas Production, net of royalties, for 2007;

PrimeWest has employed hedging structures using swaps on approximately 25% of anticipated electrical power requirements for 2006 and on none of the anticipated electrical power requirements for 2007;

The intrinsic mark-to-market positions of all hedging contracts in place for the 2006 and 2007 Production years represent a net gain of $11.2 million, as compared to a net loss of $4.5 million when measured as at December 31, 2005. The intrinsic mark-to-market value is the aggregate amount of gains or losses that would be realized over time if all hedge positions were settled when they mature at the forward prices at December 31, 2005 and March 9, 2006, respectively; and

The intrinsic plus extrinsic mark-to-market positions of all hedging contracts in place for the 2006 and 2007 Production years represent a net gain of $17.7 million as compared to a net loss of $11.5 million when measured as at December 31, 2005. The intrinsic plus extrinsic mark-to-market value is the amount of gains or losses that would be realized if all hedge positions were closed out on December 31, 2005 and March 9, 2006, respectively.

Beyond the hedging strategy, PrimeWest also mitigates risk by having a well-diversified marketing portfolio for Natural Gas and by transacting with a number of counterparties to limit exposure to any individual counterparty. Approximately 25% of Natural Gas Production is sold to aggregators and approximately 75% of Production is sold into the Alberta short-and long-term markets. The contracts that PrimeWest has in place with aggregators vary in length and represent a blend of domestic and US markets, with fixed and floating prices, which provide price diversification to our revenue stream.

In addition to the foregoing risk-management practices, while PrimeWest’s portfolio of assets is weighted to Natural Gas, a significant portion of the portfolio consists of Crude Oil and NGL Reserves. Because Oil and Gas price cycles do not necessarily coincide, such a balance often provides a natural mitigation of price risk.

For 2005, PrimeWest's commodity mix was approximately 26% Oil and NGLs and 74% Natural Gas, compared to approximately 32% Oil and NGLs and 68% Natural Gas in 2004. PrimeWest realized hedge losses of $44.3 million in 2005 and losses of $28.2 million in 2004.

IMPACT OF ENVIRONMENTAL PROTECTION REQUIREMENTS

PrimeWest carries out its activities and operations in compliance with all relevant and applicable environmental regulations and good industry practice. PrimeWest has also created a segregated fund devoted to funding future costs for well abandonment and site cleanup. In 2005, PrimeWest contributed $0.50/BOE of Production, totaling $7.6 million, including interest and other investment income, while approximately $8.7 million was paid out for active projects completed. The cash balance in the reclamation fund was $9.2 million at the end of 2005. The 2006 contribution rate remains $0.50/BOE. Expenditures for environmental matters and site restoration are not reported as part of development capital. Since the environmental standards and regulations to which PrimeWest is subject apply to all participants in the Oil and Gas industry, it is not anticipated that PrimeWest’s com petitive position within the industry will be adversely affected.

PRIMEWEST ENERGY TRUST

ANNUAL INFORMATION FORM 2005

ITEM 4: STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION

The statement of Reserves data and other Oil and Gas information set forth below is dated January 23, 2006. The effective date of the statement is December 31, 2005 and the preparation date of the statement is January 13, 2006. The Report on Reserves Data by GLJ in Form 51-101F2 and the Report of Management and Directors on Reserves Data in Form 51-101F3 are attached as Schedules A and B to this Annual Information Form, respectively.

PRESENTATION OF OUR RESERVE INFORMATION

The SEC generally permits oil and gas companies, in their filings with the SEC, to disclose only Proved Reserves after the deduction of royalties and interests of others which are those Reserves that a company has demonstrated by actual Production or conclusive formation tests to be economically producible under existing economic and operating conditions. In 2003, the securities regulatory authorities in Canada (other than Quebec) adopted NI 51-101 -- Standards of Disclosure for Oil and Gas Activities, which imposes oil and gas disclosure standards for Canadian public issuers engaged in oil and gas activities. NI 51-101 permits oil and gas issuers, in their filings with Canadian securities regulators, to disclose not only Proved Reserves but also Probable Reserves, and to disclose Reserves and Production on a gross basis before deducting royalties. Probable Reserves are of a higher risk and are less likely to be accurately estimated or recovered than Proved Reserves. Because we are permitted to prepare this Annual Information Form in accordance with Canadian disclosure requirements, we have disclosed in this Annual Information Form and in the documents incorporated by reference Reserves designated as “Probable”. If this Annual Information Form were required to be prepared in accordance with U.S. disclosure requirements, the SEC’s guidelines would prohibit Reserves in these categories from being included. Moreover, in accordance with Canadian practice, we have determined and disclosed estimated future net cash flow from our Reserves using both escalated and constant prices and costs; for the constant prices and costs case, prices and costs in effect as of December 31, 2004 were held constant for the economic life of the Reserves. The SEC does not permit the disclosure of estimated future net cash flow from Reserves based on escalating prices and costs and generally requires that prices and costs be held constant at levels in effect at the date of the reserve report. Additional information prepared in accordance with United States Statement of Financial Accounting Standards No. 69 “Disclosures About Oil and Gas Producing Activities” relating to our oil and gas Reserves is set forth in our Form 40-F which is available through EDGAR at the SEC’s website at www.sec.gov.

Unless otherwise stated, all of the Reserves information contained in this Annual Information Form has been calculated and reported in accordance with NI 51-101.

EXPLORATION AND DEVELOPMENT

The primary focus of PrimeWest is to create value through accretive depletion strategies on existing assets and acquisition of new assets where accretive. High-risk exploration plays will continue to be farmed out, sold or exchanged for producing Properties with upside potential. Development efforts will be concentrated on optimizing Production from existing and new Reserves, and developing new Properties in a cost effective manner. PrimeWest will continue its ongoing Property rationalization program and any Property disposition sale proceeds may be used to acquire interests in core areas or new prospects with exploitation opportunities.

ATTRIBUTES OF THE PROPERTIES

The Properties of PrimeWest and the Trust include interests in both non-unitized and unitized Oil and Natural Gas Production from several major Oil and Natural Gas fields. The following characteristics generally describe the attributes of the Properties:

Reserve Life: The Properties include a mix of long life, lower decline rate Reserves and short life, higher decline rate Reserves all of which have an average Reserve Life Index (RLI) of approximately 11.0 years based on Company Interest Proved plus Probable Reserves as at December 31, 2005 calculated in accordance with NI 51-101;

Operated Properties: PrimeWest operates approximately 80% of the total production from the Properties. In respect of these operated Properties, PrimeWest is able to exercise management and operating influence to maximize value for the benefit of the Trust;

Natural Gas Weighted Portfolio: For the year ended December 31, 2005 production from the Properties is approximately 26% crude oil and natural gas liquids and 74% natural gas, on a barrel-of-oil-equivalent basis. As

PRIMEWEST ENERGY TRUST

ANNUAL INFORMATION FORM 2005

at December 31, 2005, Proved plus Probable Reserves for the Properties are approximately 27% crude oil and natural gas liquids and 73% natural gas on a barrel-of-oil-equivalent basis;

Diversified Portfolio: While the Trust’s Properties are diversified from a geographic perspective, they have geological similarities across several core Properties, of which PrimeWest generally has the largest working interest in such core Properties; and

Upside Potential: Additional opportunities to enhance the value of the Properties have been identified by PrimeWest. These opportunities may not have been included in the valuations provided in the GLJ Report.

RESERVES DATA

In accordance with NI 51-101, GLJ has prepared the GLJ Report dated January 23, 2006 evaluating, as at December 31, 2005, the Reserves of Crude Oil, Natural Gas and associated products attributed to the Properties prior to provision for interest costs and General and Administrative Costs, but after providing for estimated royalties, Production Costs, Development Costs, other income, future capital expenditures, and Well Abandonment Costs for only those wells assigned Reserves by GLJ. It should not be assumed that either the undiscounted or the discounted Future Net Revenue estimated by GLJ represent the fair market value of these Reserves. Other assumptions and qualifications relating to costs, prices for future Production and other matters are summarized in the notes following these tables.

CONSTANT PRICES AND COSTS

The following tables provide Reserves data and a breakdown of Future Net Revenue by component and Production group using Constant Prices and Costs, on a Company Interest, Gross and Net basis.

Summary of Oil and Natural Gas Reserves

and Net Present Values of Future Net Revenue

as of December 31, 2005

Constant Prices and Costs


	Light And Medium Crude Oil (mbbl)			Heavy Oil (mbbl)
Reserves Category	Company Interest	Gross	Net	Company Interest	Gross	Net
Proved
Developed Producing	15,704	14,148	14,271	2,650	2,640	2,438
Developed Non-Producing	349	349	303	79	79	70
Undeveloped	357	339	314	0	0	0
Total Proved	16,410	14,836	14,888	2,729	2,719	2,508
Probable	4,136	3,827	3,594	697	695	630
Total Proved Plus Probable	20,547	18,663	18,482	3,426	3,414	3,138

Columns may not add due to rounding.


	Natural Gas (Bcf)			Natural Gas Liquids (mbbl)
Reserves Category	Company Interest	Gross	Net	Company Interest	Gross	Net
Proved
Developed Producing	424.2	414.7	338.9	10,919	10,690	7,685
Developed Non-Producing	36.7	36.5	29.2	1,129	1,126	819
Undeveloped	52.5	52.5	41.9	1,440	1,440	1,004
Total Proved	513.3	503.6	410.0	13,487	13,256	9,508
Probable	167.3	165.3	132.9	4,649	4,598	3,233
Total Proved Plus Probable	680.7	668.9	543.0	18,136	17,854	12,742

Columns may not add due to rounding.


	Total (mBOE)
Reserves Category	Company Interest	Gross	Net

PRIMEWEST ENERGY TRUST

ANNUAL INFORMATION FORM 2005


Proved
Developed Producing	99,974		96,587	80,884
Developed Non-Producing	7,668		7,641	6,057
Undeveloped	10,540		10,522	8,298
Total Proved		118,183	114,750	95,239
Probable		37,372	36,666	29,616
Total Proved Plus Probable		155,554	151,416	124,855

Columns may not add due to rounding.


	Net Present Values of Future Net Revenue ($ millions)
	Before Future Income Tax Expenses		After Future Income Tax Expenses
Reserves Category	Discounted at 0%/year	Discounted at 10%/year	Discounted at 0%/year	Discounted at 10%/year
Proved
Developed Producing	3,885.5	2,214.4	3,885.5	2,214.4
Developed Non- Producing	299.9	157.2	299.9	157.2
Undeveloped	351.5	166.2	351.5	166.2
Total Proved	4,536.9	2,537.8	4,536.9	2,537.8
Probable	1,466.5	576.0	1,466.5	576.0
Total Proved Plus Probable	6,003.4	3,113.8	6,003.4	3,113.8

Columns may not add due to rounding.

Total Future Net Revenue

(Undiscounted)

as of December 31, 2005

Constant Prices and Costs


	($ millions)
Reserves Category	Revenue	Royalties	Operating Costs	Development Costs	Well Abandonment Costs	Future Net Revenue Before Future Income Tax Expenses	Future Income Tax Expenses	Future Net Revenue After Future Income Tax Expenses
Proved Reserves	7,364.0	1,292.0	1,371.4	123.1	40.7	4,536.9	0	4,536.9
Proved Plus Probable Reserves	9,708.3	1,744.4	1,719.5	197.5	43.5	6,003.4	0	6,003.4

Future Net Revenue

By Production Group

as of December 31, 2005

Constant Prices and Costs


Reserves Category	Production Group	Future Net Revenue Before Future Income Tax Expenses (discounted at 10%/year) ($ millions)⁽³⁾
Proved Reserves	Light and Medium Crude Oil⁽¹⁾ Heavy Oil⁽¹⁾ Natural Gas⁽²⁾ Non-conventional Other revenue	362.7 52.5 2,149.4 19.5 (46.2)
Proved Plus Probable Reserves

PRIMEWEST ENERGY TRUST

ANNUAL INFORMATION FORM 2005

Light and Medium Crude Oil⁽¹⁾

Heavy Oil⁽¹⁾

Natural Gas⁽²⁾

Non-conventional⁽⁴⁾

Other revenue⁽⁵⁾

403.5

66.2

2,669.0

20.7

(45.6)

Notes:

(1)

Including Solution Gas and other by-products.

(2)

Including by-products but excluding Solution Gas from Oil wells.

(3)

Future Net Revenue values do not represent fair market value.

(4)

Non-conventional oil and gas activities include coalbed methane development activities.

Other company revenue/costs category is incremental operating costs that were not included in the properties, but were included at the corporate level to more closely match total operating costs from revenue statements.

FORECAST PRICES AND COSTS

The following tables provide Reserves data and a breakdown of Future Net Revenue by component and Production group using Forecast Prices and Costs on a Company Interest, Gross and Net basis.

Summary of Oil and Natural Gas Reserves

and Net Present Values of Future Net Revenue

as of December 31, 2005

Forecast Prices and Costs


	Light And Medium Crude Oil (mbbl)			Heavy Oil (mbbl)
Reserve Category	Company Interest	Gross	Net	Company Interest	Gross	Net
Proved
Developed Producing	15,512	13,959	14,098	2,561	2,550	2,355
Developed Non-Producing	351	351	304	90	90	81
Undeveloped	350	331	307	0	0	0
Total Proved	16,212	14,641	14,709	2,652	2,640	2,436
Probable	4,085	3,777	3,545	697	696	630
Total Proved Plus Probable	20,297	18,417	18,253	3,349	3,335	3,066

Columns may not add due to rounding.


	Natural Gas (Bcf)			Natural Gas Liquids (mbbl)
Reserve Category	Company Interest	Gross	Net	Company Interest	Gross	Net
Proved
Developed Producing	421.4	411.8	336.6	10,864	10,635	7,668
Developed Non-Producing	36.9	36.8	29.4	1,128	1,125	820
Undeveloped	52.5	52.5	41.9	1,442	1,442	1,008
Total Proved	510.7	501.1	407.8	13,434	13,203	9,495
Probable	166.6	164.5	132.3	4,634	4,583	3,233
Total Proved Plus Probable	677.3	665.6	540.1	18,068	17,786	12,729

Columns may not add due to rounding.


	Total (mBOE)
Reserve Category	Company Interest	Gross	Net
Proved
Developed Producing	99,162	95,778	80,214
Developed Non-Producing	7,724	7,697	6,106

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ANNUAL INFORMATION FORM 2005


Undeveloped	10,535	10,517	8,292
Total Proved	117,422	113,993	94,612
Probable	37,181	36,474	29,450
Total Proved Plus Probable	154,603	150,466	124,062

Columns may not add due to rounding.

Forecast Prices and Costs


	Net Present Values of Future Net Revenue ($ millions)
	Before Future Income Tax Expenses Discounted at (%/year)					After Future Income Tax Expenses Discounted at (%/year)
Reserve Category	0%	5%	10%	15%	20%	0%	5%	10%	15%	20%
Proved
Developed Producing	3,241.2	2,387.1	1,935.7	1,656.2	1,464.1	3,241.2	2,387.1	1,935.7	1,656.2	1,464.1
Developed Non-Producing	265.0	178.6	140.3	118.2	103.5	265.0	178.6	140.3	118.2	103.5
Undeveloped	277.7	179.8	128.9	97.9	76.9	277.7	179.8	128.9	97.9	76.9
Total Proved	3,783.8	2,745.5	2,204.9	1,872.3	1,644.7	3,783.8	2,745.5	2,204.9	1,872.3	1,644.7
Probable	1,259.7	701.0	479.0	365.0	295.7	1,259.7	701.0	479.0	365.0	295.7
Total Proved Plus Probable	5,043.6	3,446.6	2,684.0	2,237.2	1,940.4	5,043.6	3,446.6	2,684.0	2,237.2	1,940.4

Columns may not add due to rounding.

Total Future Net Revenue

(Undiscounted)

as of December 31, 2005

Forecast Prices and Costs


	($ millions)
Reserve Category	Revenue	Royalties	Operating Costs	Development Costs	Well Abandonment Costs	Future Net Revenue Before Future Income Tax Expenses	Future Income Tax Expenses	Future Net Revenue After Future Income Tax Expenses
Proved Reserves	6,788.6	1,153.1	1,667.7	127.5	56.6	3,783.8	0	3,783.8
Proved Plus Probable Reserves	9,031.1	1,563.8	2,154.0	204.6	65.2	5,043.6	0	5,043.6

Future Net Revenue

By Production Group

as of December 31, 2005

Forecast Prices and Costs

Reserve Category

Production Group

Future Net Revenue Before Future Income Tax Expenses (discounted at 10%/year)

($ millions)⁽³⁾

Proved Reserves

Light and Medium Crude Oil⁽¹⁾

Heavy Oil⁽¹⁾

Natural Gas⁽²⁾

Non-conventional

Other revenue

308.6

56.8

1,868.5

19.7

(48.8)

PRIMEWEST ENERGY TRUST

ANNUAL INFORMATION FORM 2005

Proved Plus Probable Reserves

Light and Medium Crude Oil⁽¹⁾

Heavy Oil⁽¹⁾

Natural Gas⁽²⁾

Non-conventional⁽⁴⁾

Other revenue⁽⁵⁾

341.9

71.1

2,298.6

20.7

(48.3)

Notes:

(1)

Including solution gas and other by-products.

(2)

Including by-products but excluding solution gas from Oil wells.

(3)

Future Net Revenue values do not represent fair market value.

(4)

Non-conventional oil and gas activities include Coalbed methane development activities.

The following tables summarize the pricing assumptions (and in the case of Forecast Prices and Costs only, the inflation assumptions) made in preparing the preceding tables pertaining to PrimeWest’s Reserves and Future Net Revenue utilizing either Constant Prices and Costs or Forecast Prices and Costs.

Summary of Pricing Assumptions

as of December 31, 2005

Constant Prices and Costs


	Oil				Natural Gas	Edmonton Liquids Prices
	WTI Cushing Oklahoma US$/bbl	Edmonton Par Price 40^oAPI Cdn$/ bbl	Hardisty Heavy 12^o API Cdn$/bbl	Cromer Medium 29^o API Cdn$/bbl	AECO Gas Price Cdn$ Per mmbtu	Propane Cdn$/bbl	Butane Cdn$/bbl	Pentanes Plus Cdn$/bbl	Inflation Rates % / year	Exchange Rate US$/Cdn$
1999	19.29	27.69	22.14	25.42	2.92	15.89	18.70	27.71	1.7	0.6750
2000	30.22	44.56	32.61	39.91	5.08	32.18	35.60	46.31	2.7	0.6740
2001	25.97	39.40	23.48	31.56	6.21	31.85	31.17	42.48	2.6	0.6448
2002	26.08	40.33	30.60	35.48	4.04	21.39	27.08	40.73	2.2	0.6376
2003	31.07	43.66	31.18	37.55	6.66	32.14	34.36	44.23	2.8	0.7213
2004	41.38	52.96	35.64	45.75	6.88	34.70	39.97	54.07	1.8	0.7680
2005	61.04	68.27	39.20	51.84	9.71	43.69	50.52	71.67	0	0.8577

Summary of Pricing and Inflation Rate Assumptions

as of December 31, 2005

Forecast Prices and Costs


	Oil				Natural Gas	Edmonton Liquids Prices
Year	WTI Cushing Oklahoma US$/bbl	Edmonton Par Price 40^o API Cdn$/ bbl	Hardisty Heavy 12^o API Cdn$/bbl	Cromer Medium 29^oAPI Cdn$/bbl	AECO Gas Price Cdn$/ mmbtu	Propane Cdn$/bbl	Butane Cdn$/bbl	Pentanes Plus Cdn$/bbl	Inflation Rates % / yr	Exchange Rate US$/Cdn$
2006	58.44	67.64	35.27	57.96	10.93	42.62	48.27	68.96	2.33	0.8500
2007	57.34	66.40	35.38	57.31	9.88	41.25	47.29	67.89	2.33	0.8500
2008	52.70	60.89	34.24	52.68	8.48	37.55	43.44	62.35	2.33	0.8500
2009	49.23	56.83	33.19	49.21	7.59	34.62	40.58	58.16	2.00	0.8500
2010	47.05	54.25	32.18	47.00	7.23	32.94	38.75	55.59	2.00	0.8500

PRIMEWEST ENERGY TRUST

ANNUAL INFORMATION FORM 2005


2011	47.19	54.41	33.21	47.16	7.24	33.06	38.89	55.75	2.00	0.8500
2012	47.83	55.12	33.78	47.83	7.34	33.51	39.37	56.47	2.00	0.8500
2013	48.81	56.20	34.49	48.76	7.48	34.10	40.15	57.60	2.00	0.8500
2014	49.75	57.32	35.35	49.80	7.65	34.82	40.96	58.72	2.00	0.8500
2015	50.77	58.53	36.09	50.85	7.83	35.56	41.77	59.97	2.00	0.8500
2016	51.79	59.66	36.93	51.82	7.98	36.28	42.58	61.19	2.00	0.8500
2017	52.85	60.91	37.69	52.99	8.14	37.06	43.52	62.48	2.00	0.8500
2018	53.92	62.16	38.54	54.05	8.30	37.81	44.45	63.74	2.00	0.8500
2019	54.99	63.45	39.31	55.12	8.48	38.54	45.31	65.07	2.00	0.8500
2020	56.09	64.75	40.11	56.31	8.65	39.29	46.29	66.38	2.00	0.8500
2021	57.20	66.06	41.00	57.42	8.83	40.16	47.26	67.71	2.00	0.8500
2022	58.33	67.39	41.72	58.55	9.00	40.96	48.16	69.07	2.00	0.8500
2023	59.48	68.74	42.63	59.78	9.19	41.77	49.15	70.44	2.00	0.8500
There-after	2.00%	2.00%	2.00%	2.00%	2.00%	2.00%	2.00%	2.00%	2.00%	0.8500

Weighted Average Realized Sales Prices (Cdn$)


	2005
Natural Gas ($/mcf)	$ 8.43
Crude Oil ($/bbl)	$ 49.05
Natural Gas Liquids ($/bbl)	$ 55.92

FUTURE DEVELOPMENT COSTS

The table below sets out the Development Costs deducted in the estimation of Future Net Revenue attributable to Proved Reserves (using both Constant Prices and Costs and Forecast Prices and Costs) and Proved plus Probable Reserves (using Forecast Prices and Costs only).


	Constant Prices and Costs		Forecast Prices and Costs
	($ millions)		($ millions)
Year	Proved	Proved plus Probable	Proved	Proved plus Probable
2006	59.3	110.7	59.3	110.7
2007	25.3	39.3	25.9	40.2
2008	22.5	26.5	23.6	27.8
2009	0.4	0.5	0.4	0.5
2010	3.6	5.9	3.9	6.5
Total: Undiscounted	123.1	197.5	127.5	204.6
Total: Discounted at 10%/year	103.9	169.6	106.3	172.9

Columns may not add due to rounding.

PRIMEWEST ENERGY TRUST

ANNUAL INFORMATION FORM 2005

The Future Development Costs are capital expenditures required in the future for PrimeWest to convert Proved Undeveloped Reserves and Probable Undeveloped Reserves into Proved Developed Producing Reserves. Over the estimated life of the Reserves, it is anticipated that expenditures of $127.5 million would be incurred for the Proved Reserves and $204.6 million for the Proved plus Probable Reserves categories, based on Forecast Prices and Costs. PrimeWest anticipates using a combination of internally generated cash flow, debt and equity financing to fund these Future Development Costs. Based on the commodity price and cost assumptions adopted for both the Constant Prices and Costs case and the Forecast Prices and Costs case, all of the expenditures included in the future Development Costs are economic as they enhance the net present values of the Proved Developed Reserves.

RECONCILIATION OF CHANGES IN RESERVES AND FUTURE NET REVENUE

Reserves Reconciliation

The following table sets forth the reconciliation of PrimeWest’s Net Reserves for the year ended December 31, 2005 using Forecast Price and Cost estimates derived from the GLJ Report as required under NI 51-101 guidelines and format, reconciled to December 31, 2004.


	Light and Medium Crude Oil (mbbls)				Heavy Oil (mbbls)
	Proved Producing	Total Proved	Probable	Proved Plus Probable	Proved Producing	Total Proved	Probable	Proved Plus Probable
Dec. 31, 2004	14,767	15,296	3,098	18,394	2,541	2,623	503	3,126
Capital Additions⁽¹⁾	178	251	321	572	85	85	178	263
Improved Recovery⁽²⁾	369	389	146	535	41	49	18	68
Technical Revisions	268	261	(26)	235	104	92	(103)	(11)
Discoveries	0	0	0	0	0	0	0	0
Acquisitions	0	0	0	0	0	0	0	0
Dispositions	(48)	(48)	(12)	(60)	0	0	0	0
Economic Factors	137	133	17	150	149	151	34	185
Production	(1,573)	(1,573)	0	(1,573)	(564)	(564)	0	(564)
Dec. 31, 2005	14,098	14,709	3,544	18,253	2,355	2,436	630	3,066

Columns may not add due to rounding.


	Associated and Non-Associated Gas (Natural Gas) (Bcf)				Natural Gas Liquids (mbbls)
	Proved Producing	Total Proved	Probable	Proved Plus Probable	Proved Producing	Total Proved	Probable	Proved Plus Probable
Dec. 31, 2004	358.2	420.4	117.6	538.0	8,308	9,911	3,008	12,919
Capital Additions⁽¹⁾	14.0	17.9	14.6	32.6	306	416	374	790
Improved Recovery⁽²⁾	8.2	18.5	1.4	19.9	219	528	36	563
Technical Revisions	5.8	(0.2)	(2.4)	(2.7)	(152)	(381)	(196)	(577)
Discoveries	0.1	0.9	0.3	1.2	0	45	18	63
Acquisitions	0.1	0.1	0.0	0.2	0	0	0	0
Dispositions	(1.9)	(1.9)	(0.3)	(2.2)	(24)	(24)	(3)	(27)
Economic Factors	1.3	1.1	0.5	1.5	(12)	(22)	(3)	(25)
Production	(49.5)	(49.5)	0	(49.5)	(977)	(977)	0	(977)
Dec. 31, 2005	336.4	407.2	131.7	539.0	7,668	9,495	3,234	12,729

Columns may not add due to rounding.


	Natural Gas from Coal (mmcf)				Total (mBOE)
	Proved Producing	Total Proved	Probable	Proved Plus Probable	Proved Producing	Total Proved	Probable	Proved Plus Probable
Dec. 31, 2004	0	0	0	0	85.3	97.9	26.2	124.1
Capital Additions⁽¹⁾	0	226	395	621	2.9	3.8	3.4	7.2

PRIMEWEST ENERGY TRUST

ANNUAL INFORMATION FORM 2005


Improved Recovery⁽²⁾	177	386	113	499	2.0	4.1	0.5	4.6
Technical Revisions	37	38	11	48	1.2	(0.1)	(0.7)	(0.8)
Discoveries	0	0	0	0	0.0	0.2	0.1	0.3
Acquisitions	0	0	0	0	0.0	0.0	0.0	0.0
Dispositions	0	0	0	0	(0.4)	(0.4)	(0.1)	(0.5)
Economic Factors	0	0	0	0	0.5	0.4	0.1	0.6
Production	(44)	(44)	0	(44)	(11.4)	(11.4)	0.0	(11.4)
Dec. 31, 2005	171	606	518	1,124	80.2	94.6	29.5	124.1

Columns may not add due to rounding.

(1)

Capital additions include exploration discoveries and drilling extensions.

(2)

Improved recovery includes infill drilling and improved recovery.

The following table sets forth a reconciliation of the Company Interest Reserves of PrimeWest for the year ended December 31, 2005 derived from the GLJ Report using Forecast Price and Cost estimates, and reconciled to December 31, 2004. PrimeWest’s Company Interest Reserves include working interest and royalties receivable by PrimeWest and the Trust, with no deduction of royalties payable. This definition is consistent with the basis on which Reserves were reported in years prior to the implementation of NI 51-101.


	Light, Medium and Heavy Crude Oil (mbbls)				Natural Gas (Bcf)
	Proved Producing	Total Proved	Probable	Proved Plus Probable	Proved Producing	Total Proved	Probable	Proved Plus Probable
Dec. 31, 2004	19,052	19,765	4,138	23,903	450.2	529.2	148.7	677.9
Capital Additions⁽¹⁾	303.0	399.2	620.1	1,019.3	17.9	23.9	19.8	43.7
Improved Recovery⁽²⁾	474.2	501.2	188.7	689.9	10.6	23.7	2.0	25.7
Technical Revisions	805.7	759.8	(149.1)	610.7	10.1	1.3	(3.5)	(2.2)
Acquisitions	0	0	0	0	0.2	0.2	0	0.2
Dispositions	(57.4)	(57.4)	(14.9)	(72.3)	(2.6)	(2.6)	(0.4)	(3.0)
Economic Factors	0	0	0	0	0	0	0	0
Production	(2,504.3)	(2,504.3)	0	(2,504.3)	(65.0)	(65.0)	0	(65.0)
Dec. 31, 2005	18,073.3	18,863.6	4,782.7	23,646.3	421.4	510.7	166.6	677.3


	Natural Gas Liquids (mbbls)				Total (mmBOE)
	Proved Producing	Total Proved	Probable	Proved Plus Probable	Proved Producing	Total Proved	Probable	Proved Plus Probable
Dec. 31, 2004	11,739.0	13,988.0	4,282.0	18,270.0	105.8	121.9	33.3	155.2
Capital Additions⁽¹⁾	462.0	675.0	563.5	1,238.5	3.7	5.1	4.4	9.5
Improved Recovery⁽²⁾	326.7	741.3	59.2	800.5	2.6	5.2	0.6	5.8
Technical Revisions	(242.5)	(548.8)	(266.9)	(815.7)	2.2	0.4	(1.0)	(0.6)
Acquisitions	0	0	0	0	0	0	0	0
Dispositions	(35.5)	(35.5)	(4.1)	(39.6)	(0.5)	(0.5)	(0.1)	(0.6)
Economic Factors	0	0	0	0	0	0	0	0
Production	(1,385.9)	(1,385.9)	0	(1,385.9)	(14.7)	(14.7)	0	(14.7)
Dec. 31, 2005	10,863.9	13,434.1	4,633.8	18,067.9	99.2	117.4	37.2	154.6

Columns may not add due to rounding.

(1)

Capital additions include exploration discoveries & drilling extensions.

(2)

Improved recovery includes infill drilling and improved recovery.

FUTURE NET REVENUE RECONCILIATION

The following table sets forth the reconciliation of estimated Future Net Revenues attributable to the Net Proved Reserves of PrimeWest for the year ended December 31, 2005, using Constant Price and Cost estimates derived from the GLJ Report and calculated using a discount rate of 10%.

PRIMEWEST ENERGY TRUST

ANNUAL INFORMATION FORM 2005

Reconciliation of Changes in

Net Present Values of Future Net Revenue

Discounted at 10%


Period and Factor	Before Tax 2005 ($ millions)
Estimated Net Present Value of Future Net Revenue at December 31, 2004	1,648.7
Oil and Gas Sales During the Period Net of Production Costs and Royalties⁽¹⁾	(459.8)
Changes due to Prices, Production Costs and Royalties Related to Forecast Production⁽²⁾	987.1
Development Costs During the Period⁽³⁾	157.4
Changes In Forecast Development Costs⁽⁴⁾	(202.2)
Changes Resulting from Extensions and Improved Recovery⁽⁵⁾	216.1
Changes Resulting from Discoveries⁽⁵⁾	6.9
Changes Resulting from Acquisitions of Reserves⁽⁵⁾	0.5
Changes Resulting from Dispositions of Reserves⁽⁵⁾	(10.3)
Accretion of Discount⁽⁶⁾	164.9
Net Change in Income Taxes⁽⁷⁾	-
Changes Resulting from Technical Reserves Revisions	(3.6)
All Other Changes	32.2
Estimated Net Present Value at End of Period Dec. 31, 2005	2,537.8

Notes:

(1)

Company actual before income taxes, excluding general and administrative expense.

(2)

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

(3)

Actual capital expenditures relating to the exploration, development and production of Oil and Gas Reserves.

(4)

The change in forecast development costs for the Properties evaluated at the beginning of the period.

(5)

End of period net present value of the related Reserves.

(6)

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

(7)

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.

UNDEVELOPED RESERVES

The following discussion generally describes the basis on which PrimeWest attributes Proved and Probable Undeveloped Reserves and its plans for developing those Undeveloped Reserves.

PROVED AND PROBABLE UNDEVELOPED RESERVES

According to the GLJ Report using Forecast Prices and Costs, PrimeWest had Net Proved Undeveloped Reserves of 8.3 mmBOE as of December 31, 2005, consisting of 307 mbbls Oil, 0 mbbls Heavy Oil, 41.9 Bcf Natural Gas and 1,008 mbbls Natural Gas Liquids. Net Probable Undeveloped Reserves were 10.1 mmBOE, consisting of 845 mbbls Oil, 157 mbbls Heavy Oil, 47.1 Bcf Natural Gas and 1,261 mbbls Natural Gas Liquids. PrimeWest invests capital into development work, which moves its Proved Undeveloped Reserves and Probable Undeveloped Reserves into the Proved Developed Producing category. In 2005, $185.6 million was invested on capital development, and $275 million has been budgeted for development capital in 2006. Allocating capital to Properties and timing of development is based on economics and performance of the asset. PrimeWest’s 2006 development focus will be in its key develo pment plays of Tight Gas (including the core areas of Caroline, Columbia), Shallow Gas (including the core areas of Brant Farrow, Princess/Dinosaur, Bindloss, Medicine Hat) and the Conventional Development Area (including core areas of Wilson Creek, Valhalla, Laprise and Crossfield/Lone Pine Creek).

Of PrimeWest’s Net Proved Undeveloped Reserves, 22% are located in Wilson Creek, a core area in which PrimeWest plans to invest development capital (for specific details on the capital budgets, plans and timing for 2006 development in this area, see “Other Oil and Natural Gas Information”). Other areas with notable Net Proved Undeveloped Reserves include Shallow Gas with 20% and Caroline, Columbia and BC Gas, each with 12%.

For other Properties which have Proved Undeveloped Reserves or Probable Undeveloped Reserves attributed to them, PrimeWest plans to continue pursuing development opportunities such as drilling, completions, and facilities upgrades in order to move those Proved Undeveloped Reserves and Probable Undeveloped Reserves to Proved Developed Producing Reserves.

PRIMEWEST ENERGY TRUST

ANNUAL INFORMATION FORM 2005

SIGNIFICANT FACTORS OR UNCERTAINTIES

Our evaluated Oil and Natural Gas Properties have no material extraordinary risks beyond those which are inherent in an oil and gas producing company as described under the heading “Management’s Discussion and Analysis” in our 2005 Annual Report. See also “Risk Factors” below.

OTHER OIL AND NATURAL GAS INFORMATION

The following discussion provides an overview of selected core Properties, including a discussion of important plants and facilities.

North

BC Gas - Laprise

The BC Gas – Laprise area is comprised of several Properties that produced an average of 2,165 BOE/day in 2005, the largest of which is the Laprise property. Laprise is a winter-access only area located about 160 kilometres north west of Fort St. John, British Columbia, with Production of marginally sour Natural Gas from the Baldonnel formation. PrimeWest has a 75.6% working interest in the Laprise Creek Baldonnel Unit No. 1, which overlies about 25% of the Laprise Creek Baldonnel “A” Pool, one of the largest Natural Gas pools in the province. PrimeWest also has a 100% interest in one producing non-unit Gas well. Facilities consist of two Natural Gas compressors with a separator and a dehydrator. Late in 2005, an infill drilling program was commenced and in 2006 additional field compression will be installed offering the Trust very low-risk Production additions .

Boundary Lake

Boundary Lake is a year-round access area located on the border of British Columbia and Alberta, about 40 kilometres north east of Fort St. John, British Columbia. The Boundary Lake area comprises 26,966 Gross (7,845 Net) acres of land. PrimeWest has a 100% working interest in Boundary Lake Project No. 1 North and South and Project No. 2, plus smaller working interests in several adjoining wells and a Production unit. Infrastructure consists of two Oil batteries and Solution Gas compression. In 2005, the average daily Production was 1,068 BOE/day of primarily light (33 degree API) Oil from the Boundary Lake Member of the Charlie Lake formation.

Arch – Cecil

The Arch Properties produced an average of 1,552 BOE/day in 2005. The largest property of the group is the Cecil Charlie Lake Oil pool, located 520 kilometres north west of Edmonton, in which PrimeWest holds an average 36% working interest. PrimeWest is currently in unitization discussions with the other working interest owners in the pool to implement a secondary waterflood recovery scheme. The pool is under maximum rate limitation Production restrictions imposed by the EUB. However, due to the hurricane activity in the Gulf of Mexico in the summer of 2005, the EUB lifted the maximum rate limitations for the Cecil pool for the period from September to December 2005. Those restrictions are back in effect in 2006.

Valhalla

The Valhalla area is located 500 kilometres north west of Edmonton with primarily sour Natural Gas Production from the Montney and Halfway formations, as well as some sweet Natural Gas Production from the uphole Baldonnel and Gething formations. There is also some Doig Oil Production at Valhalla. The Valhalla area comprises 60,000 Gross (34,204 Net) acres of land. PrimeWest has 100% ownership in two Natural Gas processing facilities consisting of two sour Gas compressors and one sweet Gas compressor. In 2004, the Gas plant was upgraded using biological desulphurisation technology, which will be decommissioned in 2006 and the volumes redirected to a third party processing facility in the area. PrimeWest’s working interest averages 82% in the Production from the area and in 2005 the average daily Production was 1,653 BOE/day. PrimeWest has budgeted up to $16 million to con tinue to downspace and infill drill this multi-zone area in 2006.

Central

Thorsby

Thorsby is located approximately 30 kilometres south west of Edmonton with Production primarily from the Ellerslie and Glauconitic sandstones. The Thorsby area comprises 174,696 Gross (106,480 Net) acres of land with an average 54% working interest in the Production from the area. In 2005, the average daily Production was 3,056 BOE/day consisting of

PRIMEWEST ENERGY TRUST

ANNUAL INFORMATION FORM 2005

a mix of Natural Gas and Crude Oil. PrimeWest owns and controls its infrastructure in Thorsby with two 100% owned Gas plants and an extensive gathering system. In 2006, PrimeWest has budgeted up to $5 million for production optimization and to investigate the potential for coalbed methane Production at Thorsby.

Wilson Creek (includes Gilby/Willesden Green)

Wilson Creek is located in west central Alberta approximately 200 kilometres northwest of Calgary with Production from the Belly River, Viking, Glauconitic, Rock Creek and Pekisko formations. The area comprises 187,261 Gross (111,223 Net) acres of land with an average 51% working interest in the Production from the area. In 2005, the average daily Production was 4,323 BOE/day of Natural Gas. Production in the Wilson Creek, Gilby and Willesden Green areas is processed though third party facilities and the Wilson Creek Unit facilities. In 2006, a budget of up to $32 million is planned to drill up to 17 operated gross wells and 20 non-operated gross wells.

South

Crossfield / Lone Pine Creek / Irricana

The Crossfield / Lone Pine Creek area is located approximately 30 kilometres north west of Calgary and produces both Natural Gas and light to medium Crude Oil from the Wabamun (Crossfield), Leduc and Nisku formations. In 2005, the average daily Production was 1,844 BOE/day. PrimeWest’s operatorship of the 142 mmcf/day East Crossfield Gas processing facility (55.5% working interest) is a key success factor for PrimeWest in this area, allowing PrimeWest to implement efficiency measures and modernization, significantly reducing unit operating costs, improving operating netbacks, generating third-party processing fees and extending the plant’s economic life by at least 10 years. PrimeWest has a very small interest in the plant’s sulphur block. In 2006, PrimeWest budgeted approximately $30 million to drill up to 9 gross wells and to conduct a one-time turndown of th e gas plant to facilitate major plant modifications required to enhance the long-term plant efficiencies due to the changing composition of the gas inlet stream. An additional $5-6 million is budgeted to drill up to 10 wells to investigate the potential for coalbed methane Production at Crossfield.

Irricana is located in central Alberta approximately 50 kilometres north east of Calgary and adjacent to PrimeWest’s Crossfield / Lone Pine Creek property with Production from the Pekisko, Wabamun and Mannville formations. The Irricana area comprises 59,679 Gross (37,555 Net) acres of land with an average 69% working interest in the Production from the area. In 2005, the average daily Production was 2,146 BOE/day, primarily consisting of Natural Gas processed primarily through PrimeWest’s East Crossfield Gas processing facility and some third party Gas processing facilities.

Grand Forks (includes Hays, Taber, Alderson)

Grand Forks is located approximately 70 kilometres west of Medicine Hat, with Production primarily from the Sawtooth and Arcs formations. Average Production in 2005 totaled approximately 2,209 BOE/day, primarily consisting of Crude Oil of approximately 25 degrees API. The Grand Forks area comprises 49,310 Gross (25,865 Net) acres of land with an average 81% working interest in the Production from the area, and PrimeWest operates most of the property.

Jumping Pound /Whiskey Creek

PrimeWest has a 14.6% working interest in the non-operated, low decline Jumping Pound Unit No. 2, located approximately 50 kilometres west of Calgary. Production from the unitized zone in the Rundle formation commenced in 1972 and in 2005 averaged 332 BOE/day of Natural Gas and Natural Gas Liquids from 11 producing wells. Production is processed at the adjacent Jumping Pound Unit No. 1 plant facilities on a custom-processing fee basis. The Jumping Pound/Whiskey Creek property comprises 3,851 Gross (1,646 Net) acres of land with an average 36% working interest in the Production from the area. In 2005, the shut-in of approximately 500 BOE/day at PrimeWest’s non-operated Whiskey Creek property was due to the operator increasing the amount of owner Production that displaced PrimeWest’s non-owner Production volumes. With no alternate facilities in the area, PrimeWest 6;s Production remained behind-pipe for most of the year until late in 2005, when the operator provided some additional capacity at the facility.

Shallow Gas

PrimeWest’s Shallow Gas plays in south east Alberta at Brant Farrow, Princess / Dinosaur, Bindloss and Medicine Hat offer stable and a long Reserve Life Index Production with low operating costs, and low risk development infill drilling opportunities.

Brant Farrow is located about 65 kilometres south east of Calgary, with Production from the shallow gas Belly River and Medicine Hat formations and the deeper Mississippian, Basal Quartz and Glauconitic formations. The Brant Farrow area

PRIMEWEST ENERGY TRUST

ANNUAL INFORMATION FORM 2005

comprises 186,420 Gross (106,206 Net) acres of land with an average 76% working interest in the Production from the area. Major infrastructure at Brant Farrow includes a 65% ownership of two Processing plants with a combined capacity of 15 mmcf/day. In 2005, the average daily Production of primarily sweet, dry Natural Gas was 1,928 BOE/day, mostly processed through owned and operated facilities. In 2006, a budget of up to $16 million is planned to drill up to 20 operated gross wells and 6 non-operated gross wells.

Princess / Dinosaur is located in east central Alberta approximately 175 kilometres southeast of Calgary, with Production from the Milk River, Medicine Hat and Second White Specs formations. At Dinosaur, PrimeWest owns a 51% operated interest in the Patricia Gas Unit No. 1 and the Dinosaur Gas Unit No. 1. The Princess / Dinosaur area comprises 58,262 Gross (40,479 Net) acres of land with an average 69% working interest in the Production from the area. In 2005, the average daily Production was 2,368 BOE/day, consisting of Natural Gas with approximately 900 BOE/day being processed through owned and operated facilities, including compression and Gas processing facilities and the balance being processed at third-party facilities. A 15 well infill-drilling program is planned for 2006.

Bindloss is located in eastern Alberta approximately 230 kilometres east of Calgary, with the majority of Production from the Viking sands in Bindloss Unit No. 1 and with potential Natural Gas production from the Milk River, Medicine Hat and Second White Specs zones. The Bindloss area comprises 85,520 Gross (71,970 Net) acres of land with an average 85% working interest in the Production from the area. In 2005, the average daily Production was 652 BOE/day, consisting of Natural Gas processed through owned and operated facilities. The 2006 budget includes plans for downspacing and infill drilling at Bindloss.

The Medicine Hat Properties are located 40 kilometres north east of Medicine Hat. PrimeWest is a 50% working interest owner and operator of the Medicine Hat Consolidated Unit No. 2. Average Production in 2005 totaled approximately 420 BOE/day, consisting primarily of sweet dry Natural Gas processed through owned and operated field infrastructure, including compression and Gas processing facilities.

Tight Gas

Caroline

PrimeWest’s key Tight Gas Property is at Caroline, located approximately 100 kilometres northwest of Calgary. This liquids rich Gas-prospective area offers multi-zone gas drilling prospects, with current Production from the Cardium, Viking, Elkton, Belly River and Mannville formations. The Caroline area comprises 230,130 Gross (176,392 Net) acres of land. Average Production in 2005 totaled 5,659 BOE/day, consisting primarily of Natural Gas, a slight increase over 2004 volumes. Through significant land and farm-in acquisitions, infrastructure modifications and an active development drilling program, PrimeWest has strengthened its position in this core property, allowing it to control key infrastructure, generate third party processing revenues, realize operating cost reductions and continue to develop low-risk development drilling opportunities for growth. PrimeWest’ s average working interest in the Caroline area wells and facilities is approximately 85%. Capital expenditures are budgeted at $30 million for 2006 and will include drilling up to 16 new gross development wells.

Columbia (includes Minehead / Harlech / Brazeau)

The Columbia Properties are located in west-central Alberta approximately 175 kilometres southwest of Edmonton with Production from primarily low permeability Viking, Cardium and Belly River sands. The Columbia area comprises 86,560 Gross (48,234 Net) acres of land with an average 78% working interest in the Production from the area. In 2005, the average daily Production was 1,967 BOE/day, consisting primarily of Natural Gas. In 2006, PrimeWest has budgeted up to $38 million to drill up to 13 gross wells, install additional gathering facilities for future development and acquire additional seismic and land.

Edson

The Edson area is located in northwest Alberta approximately 200 kilometres west of Edmonton with Production from the Bluesky, Gething and Cardium formations. The Edson area comprises 58,407 Gross (26,996 Net) acres of land with an average 93% working interest in the Production from the area. In 2005, the average daily Production was 1,021 BOE/day, consisting primarily of Natural Gas, all processed through a third party facility. Primarily a non-operated asset, PrimeWest plans to invest $7 million to participate in the drilling of up to 7 gross partner-operated wells in 2006.

Ferrier

PRIMEWEST ENERGY TRUST

ANNUAL INFORMATION FORM 2005

The Ferrier area is located in west central Alberta approximately 200 kilometres southwest of Edmonton with Production primarily from the Cardium formation. The Ferrier area comprises 58,560 Gross (26,554 Net) acres of land with an average 82% working interest in the Production from the area. In 2005, the average daily Production was 1,130 BOE/day, consisting primarily of Natural Gas, all processed through a third party facility, with some volumes compressed at PrimeWest facilities before ultimately being processed at a third party facility.

Gross Overriding Royalty (GORR) Interests

These interests entitle PrimeWest to a share of the gross sales revenue on Production from underlying Properties held and operated by others, generally without deduction for Crown royalties and operating expenses. PrimeWest’s GORR interests were principally acquired through the acquisition of Reserve Royalty Corp. in July 2000, as well as under farm-out agreements at various operated Properties, under which drilling of higher-risk exploration prospects is funded and undertaken by others in order to minimize the risk to the Unitholders. In 2005, the average daily volume was 1,338 BOE/day.

Under GORR arrangements, PrimeWest is not generally responsible for capital costs or abandonment and restoration costs associated with exploration or development activities undertaken by the working interest owner on the lands in question. Under some of the farm-out agreements, PrimeWest is alternatively entitled to convert its GORR to a working interest if successful exploration results, including development drilling, once the original working interest owners have recovered their capital investments.

OIL AND NATURAL GAS PROPERTIES AND WELLS

The following table summarizes, as at December 31, 2005, PrimeWest’s interests in producing and non-producing wells.


	Producing Wells				Non-Producing Wells
	Oil		Natural Gas		Oil		Natural Gas
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Alberta	2,061	376	2,028	919	811	307	964	531
British Columbia	354	8	46	31	118	52	10	4
Saskatchewan	984	13	2	2	246	13	0	0
Total	3,399	398	2,076	952	1,175	372	974	535

PROPERTIES WITH NO ATTRIBUTED RESERVES

The following table summarizes the Gross and Net acres of Unproved Properties in which PrimeWest has an interest and also the number of Net acres for which PrimeWest’s rights to explore, develop or exploit will, in the absence of any further action, expire in 2006.


Area	Gross Unproved Acres	Net Unproved Acres	Net Acres Expiring in 2006
North
Arch - Cecil	227,147	84,243	35,830
BC Gas – Laprise	32,370	11,356	0
Boundary Lake	7,305	3,678	0
Fox Creek	99,053	78,027	6,640
NW Alberta Gas	70,558	27,913	9,920
Valhalla	19,207	13,061	800
North Other	111,437	50,916	16,500
Central
Barrhead	52,960	29,086	8,320
Thorsby	65,370	46,906	17,110
Wilson Creek	85,257	59,130	23,351
Central Other	9,420	5,142	0

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ANNUAL INFORMATION FORM 2005


South
Crossfield/Lone Pine Creek/Irricana	52,596	36,111	12,032
Grand Forks	31,128	18,571	2,836
Jumping Pound/Whiskey Creek	1,120	412	0
Shallow Gas:
Brant Farrow	93,636	65,899	19,477
Princess/Dinosaur, Bindloss, Medicine Hat	35,104	28,618	8,815
South Other	24,535	21,654	395
Tight Gas
Caroline	128,356	107,605	24,211
Columbia	56,288	31,518	864
Edson	25,282	15,247	6,400
Ferrier	23,040	12,942	3,530
GORRs	109,478	109,478	0
TOTAL	1,360,647	857,513	197,031

ADDITIONAL INFORMATION CONCERNING ABANDONMENT AND RECLAMATION COSTS

The following table discloses the abandonment and reclamation costs PrimeWest anticipates incurring as at December 31, 2005, calculated both undiscounted and at a discount rate of 10%, and the portion thereof anticipated to be paid in each of the next three years. PrimeWest anticipates incurring abandonment costs in respect of approximately 50 Net wells during 2006. PrimeWest currently has approximately 695 reclamation projects underway, in varying stages of completion. Due to weather conditions, project unknowns, landowner issues and changing regulations, it is difficult to accurately determine the number of reclamation projects that will be completed in a given year.

Since the inception of the Trust, PrimeWest has maintained an environmental fund to pay for future costs related to well abandonment and site cleanup. The fund is used to pay for such costs as they are incurred. Funding is provided out of cash flow into a segregated cash account. The funding level is reviewed and approved by the Board of Directors annually based on estimated future liabilities and the applicable spending profile. In 2005, PrimeWest contributed $0.50/BOE of production, totaling $7.6 million, which includes interest, into this fund. As of December 31, 2005, there was an unused cash balance of $9.2 million in the fund.

The 2006 contribution rate for the environmental fund has been set at $0.50/BOE.

PRIMEWEST ENERGY TRUST

ANNUAL INFORMATION FORM 2005


Period	Abandonment and Reclamation Costs Net of Salvage Value Undiscounted ($M)	Abandonment and Reclamation Costs Net of Salvage Value Discounted at 10% ($M)
Total as at December 31, 2005	8,103	7,366
Anticipated to be incurred in 2006	14,500	13,181
Anticipated to be incurred in 2007	8,700	7,190
Anticipated to be incurred in 2008	7,500	5,634

TAX HORIZON

As a result of PrimeWest’s tax efficient structure, annual taxable income is transferred from its operating entity to PrimeWest Energy Trust, and from the Trust to its Unitholders. This is primarily accomplished through the Royalty granted to the Trust, on underlying Oil and Gas Properties held by its operating subsidiaries.

COSTS INCURRED

The following table discloses material Property Acquisition Costs, Exploration Costs and Development Costs for PrimeWest for the year ended December 31, 2005.


	Property Acquisition Costs
	Proved Properties	Unproved Properties	Exploration Costs	Development Costs
Total ($ millions)	2.7	17.6	7.6	160.4

EXPLORATION AND DEVELOPMENT ACTIVITIES

The following table discloses the number of Exploratory Wells and Development Wells, both Gross and Net, completed by PrimeWest for the year ended December 31, 2005 and which of those were completed as Oil wells, Natural Gas wells, Service Wells and dry holes.


	Exploratory Wells		Development Wells
	Gross	Net		Gross	Net
North
Oil	0	0		4	0.6
Natural Gas	0	0		19	10.0
Service Wells	0	0		0	0.0
Dry Holes	0	0		1	0.3
North Sub-Total	0	0		24	10.9
Central	0	0
Oil	0	0		4	2.3
Natural Gas	0	0		39	13.1
Service Wells	0	0		0	0.0
Dry Holes	0	0		0	0.0
Central Sub-Total	0	0		43	15.5
South	0	0
Oil	0	0		9	5.4
Natural Gas	0	0		26	13.9
Service Wells	0	0		0	0.0
Dry Holes	0	0		0	0.0
South Sub-Total	0	0		35	19.3
Tight Gas	0	0
Oil	0	0		3	0.5
Natural Gas	0	0		26	16.4
Service Wells	0	0		0	0.0
Dry Holes	0	0		1	0.3
Tight Gas Sub-Total	0	0		30	17.1

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ANNUAL INFORMATION FORM 2005


Total	0	0		132	62.8

PrimeWest does not actively pursue high-risk exploration and therefore did not drill any Exploratory Wells in 2005. PrimeWest engages in development drilling along with acquisitions to offset natural Production decline and add to Reserves. Specific details on development plans and 2006 capital budgets for PrimeWest’s core Properties are described under “Other Oil and Natural Gas Information”.

ESTIMATED PRODUCTION

The following table discloses for each product type the total volume of Company Interest Proved plus Probable Production estimated by GLJ for 2006 using Forecast Prices and Costs.


	Light and Medium Crude Oil (mbbl)	Heavy Oil (mbbl)	Natural Gas (mmcf)	Natural Gas Liquids (mbbl)	Total (mBOE)
2006 Estimated Total Production by GLJ	1,974	575	70,788	1,822	16,169

At December 31, 2005, PrimeWest estimates its 2006 Production will average 38,000–39,000 BOE/day, reflecting the natural decline of the assets, the Production additions from the 2006 capital development program, the impact of planned plant turnarounds at Caroline and Crossfield, expected to be 600 BOE/day annualized and the reinstatement of the maximum rate limitations at Cecil and other areas by the EUB effective January 1, 2006.

PRODUCTION HISTORY

The following table discloses, on a quarterly basis for the year ended December 31, 2005, PrimeWest’s share of average daily Production volume, prior to royalties, and the prices received, royalties paid, Production Costs incurred and netbacks on a per unit of volume basis for each product type.


	Average per unit of volume ($/bbl, $/mcf, $/BOE)
Product Type	PrimeWest’s Share of Average Daily Production Volume⁽¹⁾	Price Received	Royalties Paid	Production Costs	Netbacks⁽²⁾
Light, Medium, Heavy Oil	(bbls/day)
1st Quarter	6,948	$ 50.90	$ 8.11	$ 6.68	$ 27.39
2nd Quarter	6,707	$ 55.38	$ 9.52	$ 7.63	$ 28.46
3rd Quarter	7,037	$ 67.48	$ 11.47	$ 8.56	$ 36.15
4th Quarter	6,752	$ 59.78	$ 10.27	$ 8.88	$ 32.74
Natural Gas	(mcf/day)
1st Quarter	180,631	$ 6.79	$ 1.61	$ 1.11	$ 4.08
2nd Quarter	178,433	$ 7.55	$ 1.58	$ 1.27	$ 4.69
3rd Quarter	176,807	$ 8.66	$ 1.96	$ 1.43	$ 5.04
4th Quarter	176,827	$ 11.99	$ 2.64	$ 1.48	$ 6.89
Natural Gas Liquids	(bbls/day)
1st Quarter	3,563	$ 50.82	$ 14.86	$ 6.68	$ 29.28
2nd Quarter	3,959	$ 53.57	$ 14.71	$ 7.63	$ 31.23
3rd Quarter	3,616	$ 59.83	$ 15.60	$ 8.56	$ 35.67
4th Quarter	4,046	$ 59.07	$ 16.95	$ 8.88	$ 33.24
Total BOE	(BOE/day)
1st Quarter	40,616	$ 41.88	$ 9.85	$ 6.68	$ 25.41
2nd Quarter	40,405	$ 46.03	$ 10.01	$ 7.63	$ 28.50

PRIMEWEST ENERGY TRUST

ANNUAL INFORMATION FORM 2005


3rd Quarter	40,121	$ 52.30	$ 12.04	$ 8.56	$ 31.78
4th Quarter	40,269	$ 50.81	$ 15.00	$ 8.88	$ 39.09

Notes:

(1)

Before deduction of royalties.

(2)

Netbacks are calculated as Revenues less the aggregate of Royalties, Transportation and Operating Costs, on a per BOE (or mcf) basis.

The following table discloses for each of PrimeWest’s core and non-core fields, and in total, the Production volumes for each product type for the year ended December 31, 2005.


Area	Light, Medium & Heavy Crude Oil (mbbls)	Natural Gas (mmcf)	Natural Gas Liquids (mbbls)	Average Daily Production (BOE/day)
North
Arch - Cecil	220	1,972	18	1,552
BC Gas – Laprise	11	4,212	77	2,165
Boundary Lake	340	153	25	1,068
Fox Creek	199	217	13	679
NW Alberta Gas	59	3,152	1	1,601
Valhalla	55	3,054	39	1,653
North Other	15	191	3	139
North Sub-Total	899	12,951	176	8,857
Central
Barrhead	11	1,599	17	808
Thorsby	181	4,615	165	3,056
Wilson Creek	137	7,316	222	4,323
Central Other	0	60	0	29
Central Sub-Total	329	13,590	404	8,216
South
Crossfield/Lone Pine Creek/Irricana	84	7,653	97	3,990
Grand Forks	728	347	20	2,209
Jumping Pound/Whiskey Creek	-	640	24	359
Shallow Gas:
Brant Farrow	95	3,613	6	1,928
Princess/Dinosaur, Bindloss, Medicine Hat	26	7,425	38	3,566
South Other	8	33	0	38
South Sub-Total	941	19,711	185	12,090
Tight Gas
Caroline	123	9,573	347	5,659
Columbia	19	3,462	122	1,967
Edson	5	1,855	59	1,021
Ferrier	14	1,990	67	1,130
Tight Gas Sub-Total	161	16,880	595	9,777
GORRs	163	1,812	23	1,338
Miscellaneous	11	85	2	74
TOTAL	2,504	65,029	1,386	40,351

PrimeWest’s estimate for 2006 production volumes includes 2,200 BOE/day on a company-wide basis that was behind pipe at December 31, 2005.

ITEM 5: INDUSTRY CONDITIONS

PRIMEWEST ENERGY TRUST

ANNUAL INFORMATION FORM 2005

The Oil and Natural Gas industry is subject to extensive controls and regulations, imposed by various levels of government. It is not expected that any of these controls or regulations will affect the operations of PrimeWest in a manner materially different than they would affect other Oil and Gas companies and trusts of similar size. All current legislation is a matter of public record, and PrimeWest is unable to predict what additional legislation or amendments may be enacted.

PRICING AND MARKETING – NATURAL GAS

In Canada, the price of Natural Gas sold intraprovincially, interprovincially or to the United States is determined by negotiation between buyers and sellers. Natural Gas exported from Canada is subject to regulation by the National Energy Board (“NEB”) and the government of Canada. Exporters are free to negotiate prices and other terms with purchasers, provided that the export contracts continue to meet certain criteria prescribed by the NEB and the government of Canada. Natural Gas exports for a term of less than two years requires a general short term export license while terms greater than two years require a specific license for the particular Gas sold (in quantities of not more than 30,000 cubic metres/day). 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 granting of such a license requires the approval of the Governor in Council.

The governments of Alberta, British Columbia and Saskatchewan also regulate the volumes of Natural Gas, which may be removed from those provinces for consumption elsewhere, based on such factors as Reserve availability, transportation arrangements and market considerations.

PRICING AND MARKETING – OIL

In Canada, producers of Oil negotiate sales contracts directly with Oil purchasers. Oil prices are primarily based on worldwide supply and demand. The specific price paid depends in part on Oil quality, prices of competing fuels, distances to market, the value of refined products and the supply/demand balance. Oil exports may be made pursuant to export contracts with terms not exceeding one year in the case of light Crude Oil, and not exceeding two years in the case of Heavy Crude Oil, provided that an order approving any such export has been obtained from the 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 granting of such a license requires the approval of the Governor in Council.

THE NORTH AMERICAN FREE TRADE AGREEMENT

On January 1, 1994, the North American Free Trade Agreement (“NAFTA”) among the governments of Canada, the US and Mexico became effective. The NAFTA carries forward most of the material energy terms contained in the Canada-US Free Trade Agreement. In the context of energy resources, Canada continues to remain free to determine whether exports to the US or Mexico will be allowed provided that any export restrictions do not: (i) reduce the proportion of energy resource exported relative to domestic use (based upon the proportion prevailing in the most recent 36-month period), (ii) impose an export price higher than the domestic price; and (iii) disrupt normal channels of supply. All three countries are prohibited from imposing minimum export or import price requirements.

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

ROYALTIES AND INCENTIVES

In addition to federal regulation, each province has legislation and regulations, which govern land tenure, royalties, Production rates, environmental protection and other matters. In all Canadian jurisdictions, producers of Oil and Natural Gas are required to pay annual rental payments in respect of Crown leases and royalties and freehold Production taxes in respect of Oil and Natural Gas produced from Crown and freehold lands, respectively. The royalty regime is a significant factor in the profitability of Oil 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. Crown royalties are determined by governmental regulation and are generally calculated as a percentage of the value of the Gross Production, and the rate of royalties payable generally depends in part on prescribed reference prices, well productivity, geographical location, field discovery date and the type or quality of the petroleum product produced.

From time to time the governments of Canada, Alberta, British Columbia and Saskatchewan have established incentive programs, which have included royalty-rate reductions, royalty holidays and tax credits for the purpose of encouraging Oil

PRIMEWEST ENERGY TRUST

ANNUAL INFORMATION FORM 2005

and Natural Gas exploration or enhanced recovery projects. These programs reduce the amount of Crown royalties otherwise payable.

ENVIRONMENTAL REGULATION

The Oil and Natural Gas industry is subject to environmental regulation pursuant to local, provincial and federal legislation. Environmental legislation provides for restrictions and prohibitions on releases or emissions of various substances produced in association with certain Oil and Natural Gas industry operations, and can affect the location of wells and facilities and the extent to which exploration and development is permitted. In addition, legislation requires that well and facilities sites be abandoned and reclaimed to the satisfaction of provincial authorities. A breach of that legislation may result in the imposition of fines or the issuance of clean-up orders.

PrimeWest is committed to meeting its responsibilities to protect the environment wherever it operates, and anticipates making increased expenditures of both a capital and expense nature as a result of the increasingly stringent laws relating to the protection of the environment. PrimeWest's internal procedures are designed to ensure that the environmental aspects of new developments are taken into account prior to proceeding. PrimeWest believes that it is in material compliance with applicable environmental laws and regulations.

KYOTO PROTOCOL

In December of 2002, Canada became a signatory to the 1997 Kyoto Protocol to the United Nation’s Framework convention on Climate change, known as the Kyoto Protocol. The implementation of this plan has not been fully defined by the federal government. Until an implementation plan is developed, it is impossible to assess the impact on specific industries and individual businesses within an industry.

ITEM 6: RISK FACTORS

RISKS RELATED TO OUR BUSINESS

Volatility in Oil and Natural Gas prices could have a material adverse effect on results of operations and financial condition, which, in turn, could affect the market price of the Trust Units and the amount of distributions to Unitholders.

Results of operations and financial condition are dependent on the prices received for the Oil and Natural Gas that PrimeWest sells. Historically, the markets for Oil and Natural Gas have been volatile and are likely to continue to be volatile in the future. Oil and Natural Gas prices may fluctuate widely on a daily basis in response to a variety of factors beyond the Trust's control, including:

(6)

Global energy policy, including the ability of OPEC to set and maintain Production levels and prices for Oil;

Political conditions, including the risk of hostilities in the petroleum producing regions of the world;

Global and domestic economic conditions;

Weather conditions, including weather related natural disasters;

The supply and price of imported Oil and liquefied Natural Gas;

The Production and storage levels of North American Natural Gas;

The level of consumer demand;

The price and availability of alternative fuels;

The impact of US/Canadian currency exchange on the Canadian prices realized by the Trust;

The proximity of Reserves to, and capacity of, transportation facilities;

The effect of worldwide energy conservation measures; and

Government regulations.

Any decline in Crude Oil or Natural Gas prices may have a material adverse effect on PrimeWest's operations, financial condition, borrowing ability, Reserves and the level of expenditures for the development of Reserves. Any resulting decline in PrimeWest's cash flow could reduce distributions and the market price of the Trust Units.

PRIMEWEST ENERGY TRUST

ANNUAL INFORMATION FORM 2005

PrimeWest uses financial derivative instruments and other hedging mechanisms to attempt to limit a portion of the adverse effects resulting from changes in Oil and Natural Gas l commodity prices. To the extent PrimeWest hedges its commodity price exposure, it foregoes the benefits it would otherwise receive if commodity prices were to increase. In addition, commodity-hedging activities could expose PrimeWest to losses. Such losses could occur under various circumstances, including those in which the other party to a hedge does not perform its obligations under the applicable agreement, the hedge is imperfect or PrimeWest's hedging policies and procedures are not followed. Furthermore, PrimeWest cannot guarantee that its hedging transactions will fully offset the risks of changes in commodities prices.

An increase in operating costs or a decline in PrimeWest's Production level could have a material adverse effect on our results of operations and financial conditions and, therefore, could reduce distributions to Unitholders and affect the market price of the Trust Units.

Higher operating costs associated with PrimeWest’s Properties will directly decrease the amount of cash flow received by the Trust and, therefore, may reduce distributions to our Unitholders. Electricity, chemicals, supplies, and reclamation, abandonment and labour costs are some of the types of operating costs that are susceptible to material fluctuation.

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

Distributions may be reduced during periods in which PrimeWest makes capital expenditures or debt repayments using cash flow, which could also affect the market price of the Trust Units.

To the extent that PrimeWest uses cash flow to finance acquisitions, Development Costs and other significant expenditures, the net cash flow that the Trust receives from PrimeWest will be reduced, and, as a consequence, the amount of cash available to distribute to Unitholders will decrease. Distributions may be reduced, or even eliminated, at times when significant capital or other expenditures are made.

The Board of Directors of PrimeWest has the discretion to determine the extent to which cash flow from PrimeWest will be allocated to the payment of debt service charges as well as the repayment of outstanding debt, including debt under the Credit Facility. The amount of funds retained by PrimeWest to pay debt services charges or reduce debt will reduce the amount of cash distributed to Unitholders during those periods in which funds are so retained.

A decline in PrimeWest's ability to market its Oil and Natural Gas Production could have a material adverse effect on Production levels or on the price received for Production, which, in turn, could reduce distributions to Unitholders and affect the market price of the Trust Units.

PrimeWest's business depends in part upon the availability, proximity and capacity of Gas gathering systems, pipelines and processing facilities. Canadian federal and provincial, as well as United States federal and state, regulation of Oil and Gas Production, processing and transportation, tax and energy policies, general economic conditions, and changes in supply and demand could adversely affect PrimeWest's ability to produce and market Oil and Natural Gas. If market factors change and inhibit the marketing of PrimeWest's Production, overall Production or realized prices may decline, which could reduce distributions to our Unitholders.

Fluctuations in foreign currency exchange rates could adversely affect PrimeWest's business, and could affect the market price of the Trust Units as well as distributions to Unitholders.

The price that PrimeWest receives for a majority of its Oil and Natural Gas is based on United States dollar denominated benchmarks, and therefore the price that PrimeWest receives in Canadian dollars is affected by the exchange rate between the two currencies. A material increase in the value of the Canadian dollar relative to the United States dollar may negatively impact Net Production revenue by decreasing the Canadian dollars received for a given United States dollar price. PrimeWest could also be subject to unfavourable price changes to the extent that it has engaged, or in the future engages, in risk management activities related to foreign exchange rates, through entry into forward foreign exchange contracts or otherwise.

If PrimeWest is unable to acquire additional Reserves, the value of the Trust Units and distributions to Unitholders may decline.

PrimeWest does not actively explore for Oil and Natural Gas Reserves. Instead, PrimeWest adds to its Reserves primarily through development and acquisitions. As a result, future Oil and Natural Gas Reserves are highly dependent on

PRIMEWEST ENERGY TRUST

ANNUAL INFORMATION FORM 2005

PrimeWest's success in exploiting existing Properties and acquiring additional Properties. PrimeWest also distributes the majority of its 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, PrimeWest's ability to make the necessary capital investments to maintain or expand its Oil and Natural Gas Reserves will be impaired. To the extent that PrimeWest is 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, PrimeWest cannot guarantee that it will be successful in developing additional Reserves or acquiring additional Reserves on terms that meet its investment objectives. Without these Reserve additions, PrimeWest's Reserves will deplete and as a consequence, either Production from, or the average Reserve life of, its 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.

Actual Reserves will vary from Reserve estimates, and those variations could be material, and affecting the market price of the Trust Units and distributions to Unitholders.

The value of the Trust Units depends upon, among other things, the Reserves attributable to PrimeWest's Properties. Estimating Reserves is inherently uncertain. Ultimately, actual Reserves attributable to PrimeWest's Properties will vary from estimates, and those variations may be material. The Reserve figures contained herein are only estimates. A number of factors are considered and a number of assumptions are made when estimating Reserves. These factors and assumptions include, among others:

Historical Production in the areas in which the Properties are located and Production rates from similar producing areas;

Future commodity prices, Production and Development Costs, royalties and capital expenditures;

Initial Production rates;

Production decline rates;

Ultimate recovery of Reserves;

Success of future development activities;

Marketability of Production;

Effects of government regulation; and

Other government levies that may be imposed over the producing life of Reserves.

Reserve estimates are based on the relevant factors, assumptions and prices on the date that such estimates are prepared. Many of these factors are subject to change and are beyond PrimeWest's control. If these factors, assumptions and prices change or prove to be inaccurate, actual results may vary materially from Reserve estimates.

If PrimeWest expands its operations beyond Oil and Natural Gas Production in western Canada, it may face new challenges and risks. If PrimeWest is unsuccessful in managing these challenges and risks, its results of operations and financial condition could be adversely affected, which could affect the market price of the Trust Units and distributions to Unitholders.

PrimeWest's operations and expertise are currently focused on conventional Oil and Gas Production and development in the Western Canada Sedimentary Basin. In the future, it may acquire unconventional Oil and Gas Properties outside this geographic area. In addition, the Declaration of Trust does not limit the activities to Oil and Gas Production and development, and PrimeWest could acquire other energy related assets, such as Oil and Natural Gas processing plants or pipelines. Expansion of PrimeWest's activities may present challenges and risks that it has not faced in the past. If PrimeWest does not manage these challenges and risks successfully, its results of operations and financial condition could be adversely affected.

In determining the purchase price of acquisitions, PrimeWest relies on assessments relating to estimates of Reserves that may prove to be inaccurate, which could affect the market price of the Trust Units and distributions to Unitholders.

The price PrimeWest is willing to pay for an acquisition is based largely on estimates of the Reserves to be acquired. Actual Reserves could vary materially from these estimates. Consequently, the Reserves PrimeWest acquires may be less than expected, which could adversely impact cash flows and distributions to Unitholders.

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An initial assessment of an acquisition may be based on a report by engineers or firms of engineers that have different evaluation methods and approaches than those of PrimeWest's engineers, and these initial assessments may differ significantly from PrimeWest's subsequent assessments.

PrimeWest does not operate some of its Properties and therefore, results of operations may be adversely affected by the failure of third-party operators, which could affect the market price of the Trust Units and distributions to Unitholders.

The continuing Production from a property, and to some extent the marketing of that Production, is dependent upon the ability of the operators of those Properties. At December 31, 2005, approximately 20% of PrimeWest's daily Production came from Properties operated by third parties. To the extent that a third party operator fails to perform its functions efficiently or becomes insolvent, PrimeWest's revenue may be reduced. Third party operations also make estimates of future capital expenditures more difficult.

Further, the operating agreements that govern the Properties not operated by PrimeWest typically require the operator to conduct operations in a good and “workmanlike” manner. These operating agreements generally provide, however, that the operator has no liability to the other non-operating working interest owners, for losses sustained or liabilities incurred, except for liabilities that may result from gross negligence or willful misconduct.

Delays in business operations could adversely affect distributions to Unitholders and the market price of the Trust Units.

In addition to the usual delays in payment by purchasers of Oil and Natural Gas to PrimeWest and to the operators of PrimeWest's non-operated Properties, and the delays of those operators in remitting payment to PrimeWest, payments between any of these parties may also be delayed by:

Restrictions imposed by lenders;

Accounting delays;

Delays in the sale or delivery of products;

Delays in the connection of wells to a gathering system;

Blowouts or other accidents;

Adjustments for prior periods;

Recovery by the operator of expenses incurred in the operation of the Properties; or

The establishment by the operator of reserves for these expenses.

Any of these delays could reduce the amount of cash available for distribution to Unitholders in a given period and expose PrimeWest to additional third party credit risks.

The Trust and PrimeWest's indebtedness may limit the timing or amount of the distributions that are paid to Unitholders, and could affect the market price of the Trust Units.

The payments of interest and principal, and other costs, expenses and disbursements made to the providers of the Credit Facility reduce amounts available for distribution to Unitholders. Variations in interest rates and scheduled principal repayments could result in significant changes to the amount of the cash flow available for payment to the Unitholders in any given period. The agreements governing the Credit Facility provide that if the Trust or PrimeWest are in default under the Credit Facility, exceed certain borrowing thresholds or fail to comply with certain covenants, they must repay the indebtedness at an accelerated rate, and the ability to make distributions to Unitholders may be further restricted.

The lenders under the Credit Facility have been provided with a security interest in substantially all of the Trust and PrimeWest's assets. If the Trust and PrimeWest are unable to pay the debt service charges or otherwise commit an event of default, such as bankruptcy, these lenders may foreclose on and sell the Properties. The proceeds of any sale would be applied to satisfy amounts owed to the creditors. Only after the proceeds of that sale were applied towards the debt would the remainder, if any, be available for distribution to Unitholders.

The current Credit Facility and any replacement credit facility may not provide sufficient liquidity.

The amounts available under the existing Credit Facility may not be sufficient for future operations, or the Trust and PrimeWest may not be able to obtain additional financing on economic terms attractive to them, if at all. A portion of the existing Credit Facility is available on a one-year revolving basis. If the lenders do not extend the facility at the end of the

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annual revolving period, the loan will convert to a term basis with 60% of the aggregate principal amount of the loan repayable on the date which is 366 days after that conversion date and the remaining 40% of the aggregate principal amount outstanding repayable on the date which is 365 days after the initial term repayment date. If this occurs, the Trust and PrimeWest may need to obtain alternate financing. Any failure to obtain suitable replacement financing may have a material adverse effect on the business, and distributions to Unitholders may be materially reduced.

The Trust may be unable to successfully compete with other organizations in the Trust's industry, which could affect the market price of the Trust Units and distributions to Unitholders.

The Oil and Natural Gas industry is highly competitive. PrimeWest competes for capital, acquisitions of Reserves, undeveloped lands, skilled personnel, access to drilling rigs, service rigs and other equipment, access to processing facilities, pipeline and refining capacity and in many other respects with a substantial number of other organizations, many of which may have greater technical and financial resources than PrimeWest. Some of these organizations explore for, develop and produce Oil and Natural Gas but also carry on refining operations and market Oil and other products on a worldwide basis. As a result of these complementary activities, some of PrimeWest’s competitors may have greater and more diverse competitive resources to draw on than PrimeWest does.

The industry in which PrimeWest operates exposes the Trust and PrimeWest to potential liabilities that may not be covered by insurance.

PrimeWest's operations are subject to all of the risks associated with the operation and development of Oil and Natural Gas Properties, including the drilling of Oil and Natural Gas wells, and the Production and transportation of Oil and Natural Gas. These risks and hazards include encountering unexpected formations or pressures, blow outs, craterings and fires, all of which could result in personal injury, loss of life, or environmental and other damage to PrimeWest's property and the property of others. PrimeWest cannot fully protect against all of these risks, nor are all of these risks insurable. While PrimeWest’s insurance broker is responsible for ensuring that insurance underwriters have the financial strength necessary to respond to claims, PrimeWest may become liable for damages arising from events against which PrimeWest cannot insure or against which PrimeWest may elect not to insure because of high premium costs or other reasons. Any costs incurred to repair these damages or pay these liabilities would reduce funds available for distribution to Unitholders.

The operation of Oil and Natural Gas wells could subject PrimeWest to environmental claims and liability.

The Oil and Natural Gas industry is subject to extensive environmental regulation pursuant to local, provincial and federal legislation. A breach of that legislation may result in the imposition of fines or the issuance of “clean up” orders. Legislation regulating the Oil and Natural Gas industry may be changed to impose higher standards and potentially more costly obligations. For example, the Kyoto Protocol will require, among other things, significant reductions in greenhouse gases. The impact of the Kyoto Protocol on PrimeWest is uncertain and may result in significant additional costs (future) for PrimeWest's operations. Although PrimeWest has established a reclamation fund for the purpose of funding the estimated future environmental and reclamation obligations based on current knowledge and expectations, PrimeWest cannot guarantee that it will be able to sati sfy its actual future environmental and reclamation obligations.

PrimeWest is not fully insured against certain environmental risks, either because such insurance is not available or because of high premium costs. In particular, insurance against risks from environmental pollution occurring over time (as opposed to sudden and catastrophic damages) is not available on economically reasonable terms. Accordingly, PrimeWest's Properties may be subject to liability due to hazards that cannot be insured against, or that have not been insured against due to prohibitive premium costs or for other reasons.

Any site reclamation or abandonment costs actually incurred in the ordinary course of business in a specific period will be funded out of cash flow and, therefore, will reduce the amounts available for distribution to Unitholders. Should PrimeWest be unable to fully fund the cost of remedying an environmental problem, PrimeWest might be required to suspend operations or enter into interim compliance measures pending completion of the required remedy.

Lower Oil and Gas prices increase the risk of write-downs of PrimeWest's Oil and Gas Property investments.

Under Canadian accounting rules, the net capitalized cost of Oil and Gas Properties may not exceed a “ceiling limit” that is based, in part, upon estimated future net cash flows from Reserves. If Oil and Natural Gas prices decline, PrimeWest's net capitalized cost may exceed this cost ceiling, ultimately resulting in a charge against PrimeWest's earnings. Under United States GAAP, the cost ceiling is generally lower than under Canadian GAAP because the future net cash flows used in the United States ceiling test are discounted to a present value. Accordingly, PrimeWest would have more risk of

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a ceiling test write-down in a declining price environment if it reported under United States GAAP. While these write-downs would not affect cash flow, the charge against earnings could be viewed unfavourably in the market.

Unforeseen title defects may result in a loss of entitlement to Production and Reserves.

PrimeWest conducts title reviews in accordance with industry practice prior to any purchase of resource assets. However, these reviews do not guarantee that an unforeseen defect in the chain of title will not arise and defeat PrimeWest's title to the purchased assets. If such a defect were to arise, PrimeWest's entitlement to the Production from the affected assets could be jeopardized and, as a result, distributions to Unitholders may be reduced.

The economic impact on PrimeWest of claims of aboriginal title is unknown.

Aboriginal people have claimed aboriginal title and rights to a substantial portion of western Canada. PrimeWest is unable to assess the effect, if any, that any such claim would have on its business and operations.

RISKS RELATED TO THE TRUST STRUCTURE AND THE OWNERSHIP OF TRUST UNITS

Changes in tax and other laws may adversely affect Unitholders.

Income tax laws, other laws or government incentive programs relating to the Oil and Gas industry, such as the treatment of mutual fund trusts and resource allowance, may in the future be changed or interpreted in a manner that adversely affects the Trust and Unitholders. Tax authorities having jurisdiction over the Trust or the Unitholders may disagree with the manner in which the Trust calculates its income for tax purposes or could change their administrative practices to the Trust's detriment or the detriment of its Unitholders.

There would be material adverse tax consequences if the Trust lost its status as a mutual fund trust under Canadian tax laws.

It is intended that the Trust continue to qualify as a mutual fund trust for purposes of the Tax Act. The Trust may not, however, always be able to satisfy any future requirements for the maintenance of mutual fund trust status. Should the status of the Trust as a mutual fund trust be lost or successfully challenged by a relevant tax authority, certain adverse consequences may arise for the Trust and Unitholders. Some of the significant consequences of losing mutual fund trust status are as follows:

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

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.

The Trust Units would not constitute qualified investments for Registered Retirement Savings Plans, or “RRSPs,” Registered Retirement Income Funds, or “RRIFs,” Registered Education Savings Plans, or “RESPs,” or Deferred Profit Sharing Plans, or “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% of the fair market value of the Trust Units at the time the Trust Units were acquired by the exempt plan. An RRSP or RRIF holding non-qualified Trust Units would be subject to taxation on income attributable to the Trust Units, including the full amount of any capital gain realized on a disposition of non-qualified Trust Units by the RRSP or RRIF. If an RESP holds non-qualified Trust Units, it may have its registration revoked by the Canad a Revenue Agency.

The Trust may take certain measures in the future to the extent the Trust believes them necessary to ensure that it maintains its status as a mutual fund trust. These measures could be adverse to certain holders of Trust Units.

Rights as a Unitholder differ from those associated with other types of investments.

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 the Trust or PrimeWest. The Trust Units represent an equal fractional beneficial interest in the Trust and, as such, the ownership of the Trust Units does not provide Unitholders with the statutory rights normally associated with ownership of shares of a corporation, including, for example, the right to bring “oppression” or “derivative” actions. The unavailability of these statutory rights may also reduce the ability of Unitholders to seek legal remedies against other parties on PrimeWest's behalf.

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The Trust Units are also unlike conventional debt instruments in that there is no principal amount owing to Unitholders. The Trust Units will have minimal value when Reserves from PrimeWest's Properties can no longer be economically produced or marketed. Unitholders will only be able to obtain a return of the capital they invested during the period when Reserves may be economically recovered and sold. Accordingly, the distributions received over the life of the investment may not meet or exceed the initial capital investment.

The limited liability of Unitholders is uncertain.

Because of prior uncertainties in the law relating to investment trusts, there is a risk that a Unitholder could be held personally liable for obligations of the Trust in respect of contracts or undertakings which the Trust entered into and for certain liabilities arising otherwise than out of contracts including claims in tort, claims for taxes and possibly certain other statutory liabilities arising prior to July 1, 2004. Although every written contract or commitment of the Trust must contain an express disavowal of liability of the Unitholders and a limitation of liability to Trust Property, such protective provisions may not operate to avoid Unitholder liability for the relevant period. Notwithstanding attempts to limit Unitholder liability, Unitholders may not be protected from such liabilities to the same extent that a shareholder is protected from the liabilities of a corporation. Further, although the Trust has agreed to indemnify and hold harmless each Unitholder from any costs, damages, liabilities, expenses, charges and losses suffered by the Unitholder resulting from or arising out of that Unitholder not having limited liability, the Trust cannot guarantee that any assets would be available in these circumstances to reimburse Unitholders for any such liability.

On July 1, 2004 a new statute entitled theIncome Trusts Liability Act (Alberta) was proclaimed in force, creating a statutory limitation on the liability of unitholders of Alberta income trusts such as the Trust. The legislation provides that a Unitholder is not, as a beneficiary, liable for any act, default, obligation or liability of the Trustee that arises after July 1, 2004.

Changes in market-based factors may adversely affect the trading price of Trust Units.

The market price of the Trust Units is primarily a function of anticipated distributions to Unitholders and the value of the Properties owned by PrimeWest and the Trust. The market price of the Trust Units is therefore sensitive to a variety of market-based factors, including, but not limited to, interest rates and the comparability of the Trust Units to other yield oriented securities. Any changes in these market-based factors may adversely affect the trading price of the Trust Units.

The operation of the Trust is entirely independent from the Unitholders and loss of key management and other personnel could impact the business.

Unitholders are entirely dependent on the management of the Trust with respect to the acquisition of Oil and Gas Properties and assets, the development and acquisition of additional Reserves, the management and administration of all matters relating to the Properties and the administration of the Trust. The loss of the services of key individuals who currently comprise the management team could have a detrimental effect on the Trust. Investors should carefully consider whether they are willing to rely on the existing management before investing in the Trust Units.

There may be future dilution.

One of the Trust's objectives is to continually add to its resource Reserves through acquisitions and through development. Because the Trust does not reinvest the majority of its cash flow, its success is, in part, dependent on its ability to raise capital from time to time by selling Trust Units. Unitholders will suffer dilution as a result of Trust Unit offerings if, for example, the cash flow, Production or Reserves from acquired assets do not reflect the additional number of Trust Units issued to acquire those assets. Dilution may also occur if the deployment of funds raised through the various components of the DRIP does not result in the creation of additional value for Unitholders.

There may not always be an active trading market in the United States and/or Canada for the Trust Units.

While there is currently an active trading market for the Trust Units in both the United States and Canada, the Trust cannot guarantee that an active trading market will be sustained in either country.

The redemption right of Unitholders is limited.

Unitholders have a limited right to require the Trust 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 Trust's ability to pay cash in connection with redemption is subject to limitations. Any securities, which may be distributed in specie to Unitholders in connection with redemption, may not be listed on any stock exchange and a market may not develop for such securities. Also, such securities (or some of them) may not be a qualified investment

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for RRSPs, RRIFs, DPSPs or RESPs. In addition, there may be resale restrictions imposed by law upon the recipients of the securities pursuant to the redemption right.

ITEM 7: MARKET FOR SECURITIES

The outstanding Trust Units of the Trust are listed for trading on the TSX under the symbol PWI.UN and on the NYSE under the symbol PWI. The outstanding Exchangeable Shares of PrimeWest are listed for trading on the TSX under the symbol PWX. The Series I Debentures of PrimeWest trade on the TSX under the symbol “PWI.DB.A” and the Series II Debentures trade under the symbol “PWI.DB.B”.

The following tables summarize monthly trading activity for each of the securities of PrimeWest.

PrimeWest Trust Units TSX: PWI.UN (Cdn$)


2005	High	Low	Close	Average Daily Trading Volume
January	28.25	26.53	28.25	147,472
February	30.68	28.35	30.13	314,034
March	31.84	27.94	28.99	340,553
April	30.25	28.96	29.00	214,683
May	29.79	28.64	29.63	194,843
June	31.37	29.80	30.66	197,380
July	34.75	30.98	34.70	174,546
August	35.12	32.91	33.54	226,315
September	36.40	33.37	36.40	147,083
October	37.29	31.79	33.05	226,685
November	34.19	31.34	33.98	162,352
December	37.30	33.83	35.90	212,386

PrimeWest Trust Units: NYSE: PWI (US$)


2005	High	Low	Close	Average Daily Trading Volume
January	22.82	21.65	22.76	339,600
February	24.90	22.90	24.40	491,142
March	26.57	23.00	23.96	762,909
April	24.69	23.09	23.09	440,581
May	23.92	22.61	23.62	364,348
June	25.52	23.88	25.05	329,155
July	28.39	25.42	28.39	400,735
August	29.25	27.10	28.30	554,961
September	31.33	28.07	31.33	367,752
October	32.10	26.93	28.01	689,238
November	28.98	26.37	28.98	360,795
December	32.37	28.96	30.92	391,776

PrimeWest Series I Debentures TSX: PWI.DB.A (Cdn$)⁽¹⁾


2005	High	Low	Close
January	109.03	105.70	109.03
February	114.76	109.00	113.58
March	119.50	106.64	110.00
April	114.22	109.73	110.08
May	113.74	106.01	109.00
June	118.00	107.01	115.29
July	131.00	108.28	130.00

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August	132.00	123.52	125.23
September	138.98	125.60	138.98
October	140.65	121.00	125.00
November	128.50	118.50	125.90
December	140.61	130.00	133.24

Note:

(1)

The Series I Debentures were issued on September 2, 2004.

PrimeWest Series II Debentures TSX: PWI.DB.B (Cdn$)⁽¹⁾


2005	High	Low	Close
January	109.00	106.25	109.00
February	115.75	108.52	113.50
March	119.50	106.30	109.00
April	114.50	110.00	110.40
May	112.00	108.00	111.00
June	118.00	108.01	114.92
July	130.75	116.08	130.45
August	132.05	123.50	126.03
September	137.15	125.00	137.15
October	140.68	121.07	124.30
November	128.00	118.50	127.00
December	140.50	126.72	136.00

Note:

(1)

The Series II Debentures were issued on September 2, 2004.

PrimeWest Energy Inc. – Exchangeable Shares TSX: PWX (Cdn$)


2005	High	Low	Close
January	14.39	13.54	14.39
February	15.87	14.80	15.41
March	16.46	14.50	15.00
April	15.90	15.05	15.50
May	16.50	14.85	16.18
June	16.99	15.76	16.47
July	18.25	17.10	18.25
August	19.00	17.50	17.80
September	19.83	19.34	19.83
October	19.90	17.50	18.90
November	18.78	18.00	18.75
December	20.71	19.50	20.01

ITEM 8: DIRECTORS AND OFFICERS

The Trust has no directors or executive officers. The following information pertains to the Board of Directors of PrimeWest and the executive officers of PrimeWest.

DIRECTORS

The Trust has the right to nominate and elect the Board of Directors of PrimeWest to serve until the next annual meeting of Unitholders. The names of the nominees for election as Directors, their municipalities of residence, principal occupations, experience and qualifications, memberships on other boards, the year in which each became a director of PrimeWest and numbers of Trust Units beneficially owned or over which control or direction is exercised by such persons, as at December 31, 2005, are as follows:

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Name and Present Principal Occupation or Employment		Director of PrimeWest Since⁽¹⁾	Municipality of Residence	Trust Units Beneficially Owned or over which Control or Discretion is Exercised as at December 31, 2005 (#/%)⁽²⁾
Harold P. Milavsky⁽³⁾⁽⁴⁾ Chair, Quantico Capital Corp.		1996	Calgary, Alberta	28,013⁽⁵⁾/0.033
Mr. Milavsky, B.Comm, CA, FCA, is Chair of the Board of Quantico Capital Corp., a privately held company engaged in merchant banking, principal investments and acquisitions. Mr. Milavsky also serves as a director, member of the Audit Committee and member of the Nominating/Corporate Governance Committee of Saskatchewan Wheat Pool and as a director, Chair of the Board and Chair of the Audit Committee of the 13 investment trusts comprising the Citadel Group of Funds^TM. Mr. Milavsky was President and Chief Executive Officer of Trizec Corporation from 1976 to 1986 and Chair of the Board and Chief Executive Officer from 1986 to 1993. He has been a director of TransCanada Corporation, Telus Corporation, Northrock Resources Ltd., Encal Energy Ltd., Wascana Energy Inc., ENMAX Corporation and many other corporatio ns. Mr. Milavsky is a Fellow of the Institute of Chartered Accountants of Alberta and, in 2002, he received the Institute’s Lifetime Achievement Award. Mr. Milavsky is also a member of the Institute of Corporate Directors and received that Institute’s Fellowship Award in 2005.
Barry E. Emes⁽⁴⁾ Partner Stikeman Elliott LLP	1996		Calgary, Alberta	6,943⁽⁶⁾/0.008
Mr. Emes, B.A., LL.B., is a Partner in the corporate/commercial group of the Calgary office of Stikeman Elliott LLP and served for seven years as a member of the firm’s Partnership Board. Mr. Emes was previously employed by a Canadian chartered bank, and in the planning/economics group of a major international oil and gas company. Mr. Emes is a director of Parkbridge Lifestyle Communities Inc. and Graphamite Company (a private corporation).
Harold N. Kvisle⁽⁷⁾⁽⁸⁾ President and CEO TransCanada Corporation	1996		Calgary, Alberta	20,508⁽⁶⁾/0.025
Mr. Kvisle, B.Sc., MBA, P.Eng., is President, Chief Executive Officer and a director of both TransCanada Corporation and TransCanada Pipelines Limited and also serves as a director and member of the Human Resources and Management Compensation Committee of the Bank of Montreal. Prior to May 2001, Mr. Kvisle was Executive Vice President, Trading and Business Development of TransCanada Pipelines Limited (October 1999 to May 2001).
Kent J. MacIntyre⁽⁸⁾ Independent Businessman	1996		Calgary, Alberta	105,625⁽⁹⁾/0.126
Mr. MacIntyre, B.Sc. Eng., MBA, is Chair of the Board of the Canadian Income Fund Group Inc., a private company engaged in capital origination and principal investment activities in the financial services and energy areas. With more than 25 years of oil and gas experience, Mr. MacIntyre has acted as a principal to the formation and start-up of a number of companies, including PrimeWest (having held the office of Vice-Chair of the Board and Chief Executive Officer from inception in 1996 until his retirement in 2003), the 13 investment trusts comprising the Citadel Group of Funds^TM, in which he also serves as a director, Triad Energy Inc. and Olympia Energy Ventures Ltd. Mr. MacIntyre is a director and member of the Governance and Audit Committee of BlackRock Ventures Inc. and a director of a number of private compani es.
Michael W. O'Brien⁽³⁾⁽⁴⁾ Corporate Director	2000		Canmore, Alberta	6,895/0.008

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Mr. O’Brien, B.A., MBA, serves, among other responsibilities, as director and Chair of the Audit Committee of Shaw Communications Inc., and as a director, member of the Audit Committee and member of the Environmental, Health & Safety Committee of Suncor Energy Inc. Mr. O’Brien is past Chair of the Canadian Petroleum Products Institute, Canada’s Voluntary Challenge Registry for Climate Change and the Nature Conservancy of Canada. Prior to retirement in 2002, Mr. O’Brien was the Executive Vice President, Corporate Development and Chief Financial Officer of Suncor Energy Inc. (December 1999 to June 2002).
W. Glen Russell⁽⁷⁾⁽⁸⁾ Management Consultant	2003	Calgary, Alberta	3,011/0.004
Mr. Russell, B.Sc., P.Eng., principal of Glen Russell Consulting, serves, among other responsibilities, as a director and Chair of the Board of Evoco Inc. (a private company), a director, Chair of the Board, Chair of the Corporate Governance and Human Resources Committee and member of the Operations and Reserves Committee of Petro Andina Resources Inc. (a private company in Argentina). He was previously President and Chief Operating Officer of Chauvco Resources Limited and Senior Vice President and Chief Operating Officer of Gulf Canada Resources Limited. Mr. Russell also acted as Executive Advisor with regard to mergers and acquisitions and corporate strategy for a major Canadian Investment Banking firm.
James W. Patek⁽⁷⁾⁽⁸⁾ President Patek Energy Consultants	2003	Fripp Island, South Carolina, U.S.A.	1,000/0.001
Mr. Patek, B.Sc., M.Sc., is the President of Patek Energy Consultants, based in the United States. He was previously Chief Executive Officer of Petrocorp Exploration Limited, Chief Executive Officer of Fletcher Challenge Energy, Senior Reservoir Engineer at Conoco, Division Engineer and Division Manager of Husky Oil Operations Limited and Operations Manager at Petrocorp Exploration Limited. Prior to June 2000, Mr. Patek was President of Fletcher Challenge Energy Canada.
Peter Valentine⁽³⁾ Senior Advisor to Chief Executive Officer, Calgary Health Region and Senior Advisor to Dean of Medicine, University of Calgary	2004	Calgary, Alberta	566/0.0007
Mr. Valentine, B.Comm, FCA, ICD.D., is currently Senior Advisor to the President and Chief Executive Officer of the Calgary Health Region and to the Dean of Medicine at the University of Calgary. Mr. Valentine is a Trustee, a member of the Audit Committee and a member of the Governance Committee of Fording Canadian Coal Trust, a director and Chair of the Audit Committee of Livingston International Income Fund, a director and member of the Audit Committee of Superior Plus Income Fund and a director and Chair of the Audit Committee of Resmor Trust Company (a private corporation). Mr. Valentine was previously the Auditor General for the Province of Alberta (March 1995 to January 2002), Chair of the Financial Advisory Committee of the Alberta Securities Commission, member of the Accounting Standards Board and Public Sector Accounting Board of the Canadian Institute of Chartered Accountants, Chair of the Canadian Comprehensive Audit Foundation and also held senior positions at KPMG. In addition, for the period of December 2003 to June 2004, Mr. Valentine was Interim Vice-President, Finance and Services at the University of Calgary.

Notes:

(1)

The term of office of each Director expires at the next annual meeting, unless earlier terminated.

(2)

Number and percentage of ownership based upon number of Trust Units, Class A Exchangeable Shares and Convertible Subordinated Unsecured Debentures beneficially owned, directly or indirectly, or over which control is exercised by each nominee for Director, collectively, relative to the total Trust Units and Class A Exchangeable Shares issued and outstanding, Trust Units issuable pursuant to the conversion of the Debentures and Trust Units issuable under the Long Term Incentive Plan, diluted at December 31, 2005 (83,696,701 Units).

(3)

Member of the Audit and Finance Committee.

(4)

Member of the Corporate Governance and EH&S Committee.

(5)

Trust Units held through Quantico Capital Corp.

(6)

Includes five year Convertible Unsecured Subordinated Debentures (Series I) convertible to Trust Units at a price of $26.50 per Trust Unit, 37.7358 Trust Units per $1,000.00 Debenture, which, in the case of Mr. Emes, consists of 25 Debentures convertible into 943 Trust Units and, in the case of Mr. Kvisle, consists of 50 Debentures convertible into 1,886 Trust Units.

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ANNUAL INFORMATION FORM 2005

(7)

Member of the Compensation Committee.

(8)

Member of the Operations and Reserves Committee.

Consists of 100,000 Class A Exchangeable Shares (which, at December 31, 2005, were exchangeable into 56,399 Trust Units), all of which were held by Canadian Income Fund Group Inc., a corporation wholly owned by Mr. MacIntyre.

The information as to voting securities beneficially owned, directly or indirectly, is based upon information furnished to us by the nominees.

OFFICERS

The name, municipality of residence, position held and number of Trust Units beneficially owned or over which each officer of PrimeWest exercises control or direction as of December 31, 2005 are set out below:


Name and Municipality	Principal Occupation			Trust Units Beneficially Owned or over which Control or Discretion is Exercised as at December 31, 2005 (#/%)⁽¹⁾
Donald A. Garner Calgary, Alberta	President and Chief Executive Officer Since January 2003			93,196/0.111
Mr. Garner joined PrimeWest in June 2001 and has overall responsibility for leading and overseeing the business direction of the Trust. He has more than 27 years experience in the Oil and Gas industry. He was President and Chief Operating Officer of Northstar Energy Corporation from January 1998 to February 2001. Prior to that Mr. Garner spent a good portion of his career at Imperial Oil Limited in various capacities, including executive responsibility for the Oilsands Business Unit. Mr. Garner is an engineering graduate of the University of Saskatchewan.
Timothy S. Granger Calgary, Alberta	Chief Operating Officer Since January 2003			7,315/0.009
Mr. Granger joined PrimeWest in June 1999 and has overall responsibility for the day-to-day business and operations of PrimeWest. Mr. Granger has more than 26 years of extensive experience in exploitation, Production operations and asset management. From 1996 to 1999, Mr. Granger held various managerial positions at Pogo Canada Ltd. and Petro-Canada, including Production engineering and upstream information technology. Prior to 1996, Mr. Granger held various management positions at Amerada Hess Canada Ltd. From 1980 to 1991, Mr. Granger held various engineering positions at Dynex Petroleum Ltd., Canterra Energy Ltd. and Dome Petroleum Limited. Mr. Granger holds a P.Eng. (Mechanical) from Carlton University.
Ronald J. Ambrozy Calgary, Alberta	Vice-President, Business Development Since October 1997			18,795/0.022
Mr. Ambrozy has over 30 years of experience in the Oil and Natural Gas industry. Prior to joining PrimeWest in 1997, Mr. Ambrozy held progressively more senior positions at Gulf Canada Resources Limited, as well as manager of Gulf's asset management group. Mr. Ambrozy has a Bachelor of Science in Engineering from the University of Manitoba. Mr. Ambrozy is currently President of the Petroleum Acquisition and Divestment (A&D) Association, an organization of Oil and Gas individuals involved in A&D activity.
Dennis G. Feuchuk Calgary, Alberta	Vice-President, Finance and Chief Financial Officer Since October 2001			27,739/0.033
Mr. Feuchuk joined PrimeWest in October 2001 and is responsible for the general financial operations of PrimeWest including tax and accounting matters, as well as information systems. Mr. Feuchuk has over 30 years of experience in finance, accounting, audit and income tax in the Oil and Natural Gas industry. He was Vice President, Finance and Controller of Gulf Canada Resources Limited from February 1995 to February 2001. Mr. Feuchuk also was Vice President and Treasurer of Athabasca Oil Sands Trust from inception in December 1995 to February 2001. Mr. Feuchuk has a Bachelor of Business Management from Ryerson University, has completed the Richard Ivey School of Business Executive Development Program and is a Certified Management Accountant.
Brian J. Lynam Calgary, Alberta		Vice-President, Operations Since February, 2006.	Nil

PRIMEWEST ENERGY TRUST

ANNUAL INFORMATION FORM 2005


Mr. Lyman graduated from the University of Toronto with a Bachelor of Applied Science in Chemical Engineering. He has 25 years of extensive experience in the oil and gas industry, most recently with Burlington Resources Canada Ltd. where he held leadership positions including Production Optimization Manager and Operations Manager of two operating regions. Previous to that, Mr. Lynam was with Gulf Canada Resources Limited. At Gulf Canada, Mr. Lynam held a number of operational positions including roles in Development Engineering, Safety and Environment, Production Operations, Marketing, Regulatory & Licensing and Joint Interest. Mr. Lynam is responsible for the Trust’s Production Operations, Drilling, Completions & Facilities.
Gordon D. Haun Calgary	General Counsel and Corporate Secretary Since February 2006	2,215/0.003
Mr. Haun is responsible for all legal and corporate secretarial services required by PrimeWest, including those relating to corporate governance, corporate finance, mergers and acquisitions, intellectual property, material agreements and dispute resolution. He has over 17 years of experience in the provision of legal services, spending several years in private practice with two national law firms before moving into the petroleum industry where he has practiced for the last 10 years. Prior to joining PrimeWest in November 2001, Mr. Haun worked for Gulf Canada Resources Limited (1995 to 1997), and, from 1997 to 2001, he was legal counsel for Phillips Petroleum Resources, Ltd. Mr. Haun has a Bachelor of Arts from the University of Calgary, a Bachelor of Laws from the University of Alberta and is an active member of th e Law Society of Alberta and the Institute of Corporate Directors.

Notes:

(1)

Number and percentage of ownership based upon number of Trust Units, Class A Exchangeable Shares and Convertible Subordinated Unsecured Debentures beneficially owned, directly or indirectly, or over which control is exercised by each officer, collectively, relative to the total Trust Units and Class A Exchangeable Shares issued and outstanding, Trust Units issuable pursuant to the conversion of the Debentures and Trust Units issuable under the Long-Term Incentive Plan, diluted at December 31, 2005 (83,696,701 Units).

EMPLOYEES

As of December 31, 2005, PrimeWest had a total permanent staff and field operator complement of 156 in the corporate head office and 52 in the field for a total of 208 employees.

AUDIT COMMITTEE DISCLOSURE

The disclosure regarding PrimeWest's Audit and Finance Committee required under Multilateral Instrument 52-110 adopted by certain of the Canadian securities regulatory authorities is contained in Schedule "C" to this Annual Information Form.

LEGAL PROCEEDINGS

PrimeWest is engaged in a number of matters of litigation, none of which could reasonably be expected to result in any material adverse consequence.

INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS

To the knowledge of PrimeWest, no Director or Officer of PrimeWest, or an associate or affiliate thereof, had any material interest, direct or indirect, in any transaction within the three most recently completed financial years or has any material interest, direct or indirect, in any transaction during the current financial year, that has materially affected or will materially affect the Trust on a consolidated basis.

TRANSFER AGENT AND REGISTRAR

The transfer agent and registrar for the Trust Units, the Exchangeable Shares, the Series I Debentures and the Series II Debentures is Computershare at its principal offices in Toronto and Calgary.

PRIMEWEST ENERGY TRUST

ANNUAL INFORMATION FORM 2005

INTERESTS OF EXPERTS

Reserve estimates contained in this Annual Information Form are based upon the GLJ Report. The principals of GLJ, as a group, own, directly or indirectly, less than 1% of the outstanding Trust Units.

ITEM 9: ADDITIONAL INFORMATION

Additional information, including Directors' and Officers' remuneration and indebtedness, principal holders of the Trust's securities and the interests of insiders in material transactions, where applicable, is contained in the Circular. Additional financial information is provided in the Trust's consolidated comparative financial statements for the year ended December 31, 2005, contained in the Annual Report. Additional information relating to the Trust may also be found on the Trust’s website at www.primewestenergy.com, SEDAR at www.sedar.com or EDGAR at the SEC’s website at http://www.sec.gov/.

Upon request to the Secretary of PrimeWest, the Trust will provide one copy of this Annual Information Form, together with one copy of any document incorporated herein by reference, one copy of the Annual Report (including the consolidated comparative financial statements of the Trust for the year ended December 31, 2005 and accompanying report of the auditors), one copy of any interim financial statements subsequent to the consolidated financial statements for the year ended December 31, 2005 and one copy of the Circular.

When securities of the Trust are in the course of a distribution pursuant to a short form prospectus, or a preliminary short form prospectus has been filed in respect of a distribution of the Trust's securities, copies of the foregoing documents and any other documents that are incorporated by reference into the short form prospectus or preliminary short form prospectus may also be obtained from the Secretary of PrimeWest.

ITEM 10: DISCLOSURE PURSUANT TO THE REQUIREMENTS OF THE NYSE

The Canadian Securities Administrators have prescribed that all entities listed on the TSX must annually disclose their corporate governance practices in accordance with the requirements of National Instrument 58-101 Disclosure of Corporate Governance Practices (“NI 58-101”). PrimeWest has structured its corporate governance so as to be in compliance with NI 58-101 and other applicable legislation and policies, including National Policy 41-201 – Income Trusts and Other Indirect Offerings, Multilateral Instrument 52-110 – Audit Committees (“MI 52-110”) and National Policy 58-201 - Corporate Governance Guidelines (“NP 58-201”). In addition, PrimeWest continually reviews its corporate governance to ensure compliance with other published policies, including the corporate governance rules set forth in Section 303A (the “NYSE Rules” ) of the New York Stock Exchange (the “NYSE”) Listed Company Manual and the Sarbanes–Oxley Act of 2002.

As a Canadian company listed on the NYSE, PrimeWest is not required to comply with most of the NYSE rules and instead may comply with domestic requirements. As a “foreign private issuer”, PrimeWest is only required to comply with four of the NYSE Rules: 1) have an Audit Committee that satisfies the requirement of the United StatesSecurities Exchange Actof 1934; 2) the Chief Executive Officer must promptly notify the NYSE in writing after an Executive Officer becomes aware of any material non-compliance with the applicable NYSE Rules; 3) provide a brief description of any significant ways in which its corporate governance practices differ from those followed by domestic companies under the NYSE Rules; and 4) submit to the NYSE an Annual Written Affirmation each year and an Interim Written Affirmation each time there is a change to the Board of Directors or a ny Committee thereof. However, PrimeWest has voluntarily chosen to adopt corporate governance practices that comply with the NYSE Rules in all significant respects. The differences between PrimeWest’s corporate governance practices and those followed by domestic companies under the NYSE Rules are discussed in the Circular and on PrimeWest’s website at www.primewestenergy.com.

ITEM 11: GLOSSARY OF ABBREVIATIONS AND DEFINITIONS

ABBREVIATIONS

In this Annual Information Form, the abbreviations set forth below have the following meanings:


bbls	Barrels	mcf/day	1,000 cubic feet /day
mbbls	1,000 barrels	bcf	1,000,000,000 cubic feet
mmbbls	1,000,000 barrels	m3	1000 cubic metres

PRIMEWEST ENERGY TRUST

ANNUAL INFORMATION FORM 2005


bbls/day	Barrels /day	BOE	barrels of oil equivalent
mcf	1,000 cubic feet	mBOE	1,000 barrels of oil equivalent
mmcf	1,000,000 cubic feet	BOE/day	barrels of oil equivalent /day
mmcf/day	1,000,000 cubic feet/day	mmBOE	millions of barrels of oil equivalent

For purposes of this document, and in accordance with NI 51-101, 6 mcf of Natural Gas and 1 bbl of NGLs each equal 1 bbl of Oil. This conversion rate is not based on price or energy content. BOE’s may be misleading, particularly if used in isolation. A BOE conversation 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.

DEFINITIONS

In this Annual Information Form, the capitalized terms set forth below have the following meanings:

Annual Report means the 2005 Annual Report of the Trust filed on SEDAR at www.sedar.com.

ARTC means Alberta royalty tax credit.

Associated Gas means the Gas cap overlying a Crude Oil accumulation in a reservoir.

Board of Directorsmeans the board of directors of PrimeWest.

Cash Distribution Date means the date Distributable Income is paid to Unitholders, currently being the 15th day of a given calendar month, or if such date is not a business day, the immediately preceding business day, subject to any change permitted by, and made pursuant to, the Declaration of Trust.

Circular means the Management Proxy Circular of the Trust, to be dated on or about March 15, 2006.

Company Interest means in relation to PrimeWest’s interest in Production or Reserves, its working interest (operating or non-operating) share before deduction of royalties and including royalty interests of PrimeWest and the Trust;

Consolidation means the consolidation of the Trust Units on a one-for-four basis, effective August 16, 2002.

Constant Prices and Costs means prices and costs used in an estimate that are:

(9)

PrimeWest’s prices (being the ported price for Oil and the spot price for Natural Gas, after historical adjustments for transportation, gravity and other factors) and costs as at December 31, 2005, held constant throughout the estimated lives of the Properties to which the estimate applies; or

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

Credit Facility means, collectively, certain credit facilities provided by a syndicate of Canadian chartered banks and term debt provided by certain institutional investors, together offering a maximum aggregate borrowing capability of $625 million.

Crude Oil means a mixture that consists mainly of pentanes and heavier hydrocarbons, which may contain sulphur and other non hydrocarbon compounds, that is recoverable at a well from an underground reservoir and that is liquid at the conditions under which its volume is measured or estimated. It does not include Solution Gas or Natural Gas Liquids.

Debt Service Costs has the meaning ascribed thereto in the Royalty Agreements.

Declaration of Trust means the declaration of trust dated August 2, 1996 among the Trustee, PrimeWest and the Initial Unitholder (as therein defined), as amended and restated as of November 6, 2002, as amended as of May 6, 2004, and as further amended from time to time.

Developed Non-Producing Reserves means 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.

Developed Producing Reserves means 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.

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ANNUAL INFORMATION FORM 2005

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 to put the Reserves on Production. The Developed category may be subdivided into Developed Producing and Developed Non-Producing.

Development Costs means costs incurred to obtain access to Reserves and to provide facilities for extracting, treating, gathering and storing the Oil and Natural Gas from the Reserves. More specifically, Development Costs, including applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:

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, Natural Gas lines and power lines, to the extent necessary in developing the Reserves;

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 the wellhead assembly;

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

Provide improved recovery systems.

Development Wellmeans a well drilled inside the established limits of an Oil or Natural Gas reservoir, or in close proximity to the edge of the reservoir, to the depth of a stratigraphic horizon known to be productive.

Distributable Income means all amounts received by the Trust in respect of the Royalty, ARTC, the gross overriding royalties held by the Trust directly and other income, less certain expenses and other deductions.

Distribution Reinvestment Programor DRIP means the Distribution Reinvestment, Premium Distribution and Optional Trust Unit Purchase Plan of the Trust. The conventional component of the Plan, available to U.S. and Canadian Unitholders, allows Unitholders to reinvest Distributions in order to acquire additional Trust Units at a 5% discount to the Average Market Price defined in the Plan document. Under the premium distribution component, which is only available to Canadian Unitholders, participants are entitled to cash payments equivalent to 102% of the cash distribution that they would otherwise be entitled to receive, subject to proration. Finally, under the Optional Trust Unit Purchase component of the DRIP, which is also only available to Canadian Unitholders, participants can purchase Trust Units valued at up to $100,000 per annum at a 5% discount to t he Average Market Price.

EDGAR means the Electronic Data Gathering, Analysis and Retrieval System on which submissions by companies and others required by law to file forms with the SEC are filed and accessible at www.sec.gov.

Establishedmeans in relation to PrimeWest’s interest in Production or Reserves prior to December 31, 2003, Proved plus half of Probable Reserves (as such terms were defined in NP 2B).

Exchangeable Sharesmeans the Exchangeable Shares in the capital of PrimeWest.

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 Natural Gas Reserves, including costs of drilling Exploratory Wells and exploratory type stratigraphic test wells. Exploration Costs, which include applicable operating costs of support equipment and facilities and other costs of exploration activities, are:

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 (collectively sometimes referred to as “geological and geophysical costs”);

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;

Dry hole contributions and bottom hole contributions;

Costs of drilling and equipping Exploratory Wells; and

Costs of drilling exploratory type stratigraphic test wells.

Exploratory Well means a well that is not a Development Well, a Service Well or a stratigraphic test well.

PRIMEWEST ENERGY TRUST

ANNUAL INFORMATION FORM 2005

Forecast Prices and Costs means future prices and costs that are:

Generally accepted as being a reasonable outlook for the future; or

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

Future Income Tax Expenses means future income tax expenses estimated (generally, year by year):

Making appropriate allocations of estimated unclaimed costs and losses carried forward for tax purposes, between Oil and Gas activities and other business activities;

Without deducting estimated future costs (for example, Crown royalties) that are not deductible in computing taxable income;

Taking into account estimated tax credits and allowances (for example, royalty tax credits); and

Applying to the future pre tax net cash flows relating to PrimeWest’s Oil and Gas activities the appropriate year end statutory tax rates, taking into account future tax rates already legislated.

Future Net Revenue means the estimated amount to be received with respect to the development and Production of Reserves (including Synthetic Oil, coal bed methane and other non conventional Reserves) estimated using either Constant Prices and Costs or Forecast Prices and Costs and by deducting from estimated future revenues estimated future royalty obligations, costs related to the development and Production of Reserves, Well Abandonment Costs and Future Income Tax Expenses, unless otherwise specified herein.

GAAP means Generally Accepted Accounting Principles.

General and Administrative Costs means the amount in aggregate representing all expenditures and costs incurred by or in respect of PrimeWest, the Trust or the Royalty or in the management and administration of PrimeWest, the Trust or the Royalty.

GLJ means GLJ Petroleum Consultants Ltd.

GLJ Report means the reserve report prepared by GLJ evaluating the light and medium Oil, Heavy Oil and Associated and Non-Associated Gas Reserves attributable to Properties owned by PrimeWest and the Trust as at December 31, 2005.

Gross means:

In relation to PrimeWest’s interest in Production or Reserves, its “company gross Reserves”, which are PrimeWest’s working interest (operating or non-operating) share before deduction of royalties and without including any royalty interests of PrimeWest or the Trust; or

In relation to wells, the total number of wells in which PrimeWest has an interest; or

In relation to Properties, the total area of Properties in which PrimeWest has an interest.

Heavy Oil means, in a jurisdiction that has a royalty regime specific to Heavy Oil, oil that qualifies for royalties specific to Heavy Oil, or in a jurisdiction that has no such royalty regime, oil with a density between 10 to 22.3 degrees API.

Natural Gas or Gasmeans the lighter hydrocarbons and associated non-hydrocarbon substances (including hydrogen sulphate, carbon dioxide and nitrogen) occurring naturally in an underground reservoir which under atmospheric conditions are essentially gases but which may contain Natural Gas Liquids.

Natural Gas Liquidsor NGLs means those hydrocarbon components that can be recovered from natural gas as liquids including, but not limited to, ethane, propane, butanes, pentanes plus, condensate and small qualities of non hydrocarbons.

Netmeans:

In relation to PrimeWest’s interest in Production or Reserves, PrimeWest’s working interest (operated or non-operated) share after deduction of royalty obligations, plus the royalty interests of PrimeWest and the Trust in Production or Reserves; or

PRIMEWEST ENERGY TRUST

ANNUAL INFORMATION FORM 2005

In relation to PrimeWest’s interest in wells, the number of wells obtained by aggregating PrimeWest’s working interest in each of its Gross wells; or

In relation to PrimeWest’s interest in a Property, the total area in which PrimeWest has an interest multiplied by the working interest owned by PrimeWest.

Net Production Revenue in respect of any period for which Net Production Revenue is calculated means the aggregate of:

The amount received or receivable by PrimeWest in respect of the sale of its interest in all Petroleum Substances produced from the Properties;

Crown royalties and other Crown charges which are not deductible for income tax purposes to the extent those royalties are not included in the amounts described in paragraph d);

PrimeWest's share of all other revenues that accrue in respect of the Properties, including, without limitation,

(i)

Fees and similar payments made by third parties for the processing, transportation, gathering or treatment of their Petroleum Substances in facilities that are part of the Properties,

(ii)

Proceeds from the sale or licensing of seismic and similar data,

(iii)

Incentives, rebates and credits in respect of Production Costs or in respect of capital expenditures,

(iv)

Overhead and other cost recoveries,

(v)

Royalties and similar income; and

(vi)

ARTC applicable to the Properties; less

The amount of non-capital operating costs paid or payable by or on behalf of PrimeWest in respect of operating the Properties including, without limitation, the costs of gathering, compressing, processing, transporting and marketing all Petroleum Substances produced therefrom and all other amounts paid to third parties which are calculated with reference to Production from the Properties including, without limitation, gross overriding royalties and lessors' royalties, but excluding Crown royalties and other Crown charges and any site reclamation and abandonment costs.

NI 51-101means National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities of the Canadian Securities Administrators.

Non Associated Gas means an accumulation of Natural Gas in a reservoir where there is no Crude Oil.

NYSE means the New York Stock Exchange.

Oil means Crude Oil or Synthetic Oil.

Person means an individual, a body corporate, a partnership (limited or general), a joint venture, a trust, a pension fund, a union, a government and a governmental agency.

Petroleum Substancesmeans Oil, Natural Gas and related hydrocarbons (except coal) including, without limitation, all liquid hydrocarbons, and all other substances, including sulphur, whether gaseous, liquid or solid and whether hydrocarbon or not, produced in association with Oil, Natural Gas or related hydrocarbons.

Possible Reservesmeans those additional Reserves that are less certain to be recovered than Probable Reserves. It is unlikely that the actual remaining quantities recovered will exceed the sum of the estimated Proved plus Probable plus Possible Reserves. In addition, the level of certainty targeted by the reporting company should result in at least a 10% probability that the quantities actually recovered will equal or exceed the sum of the estimated Proved plus Probable plus Possible Reserves.

Probable Reserves means those additional Reserves that are less certain to be recovered than Proved Reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated Proved plus Probable Reserves. In addition, the level of certainty targeted by the reporting company should result in at least a 50% probability that the quantities actually recovered will equal or exceed the sum of the estimated Proved plus Probable Reserves.

Production means recovering, gathering, treating, field or plant processing and field storage of Oil and Natural Gas.

PRIMEWEST ENERGY TRUST

ANNUAL INFORMATION FORM 2005

Production Costs means costs incurred to operate and maintain wells and related equipment and facilities, including applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. Lifting costs become part of the cost of Oil and Natural Gas produced.

Examples of Production Costs are:

Costs of labour to operate the wells and related equipment and facilities;

Costs of repairs and maintenance;

Costs of materials, supplies and fuel consumed, and supplies utilized, in operating the wells and related equipment and facilities;

Costs of workovers;

Property taxes and insurance costs applicable to Properties and wells and related equipment and facilities; and

Taxes, other than income and capital taxes.

Property/Properties includes:

Fee ownership or a lease, concession, agreement, permit, license or other interest representing the right of PrimeWest, the Trust or their subsidiaries to extract Oil or Natural Gas subject to such terms as may be imposed by the conveyance of that interest;

Royalty interests of PrimeWest, the Trust or their subsidiaries, Production payments payable to PrimeWest, the Trust or their subsidiaries in Oil or Natural Gas, and other non operating interests of PrimeWest, the Trust or their subsidiaries in Properties operated by others; and

An agreement with a foreign government or authority under which PrimeWest, the Trust or any of their subsidiaries participates in the operation of Properties or otherwise serves as “producer” of the underlying Reserves (in contrast to being an independent purchaser, broker, dealer or importer);

but does not include supply agreements, or contracts that represent a right to purchase, rather than extract, Oil or Natural Gas.

Property Acquisition Costs means costs incurred to acquire a Property (directly by purchase or lease, or indirectly by acquiring another corporate entity with an interest in the Property), including:

Costs of lease bonuses and options to purchase or lease a Property;

The portion of the costs applicable to hydrocarbons when land including rights to hydrocarbons is purchased in fee; and

Brokers’ fees, recording and registration fees, legal costs and other costs incurred in acquiring Properties.

Proved Property means a Property or part of a Property to which Reserves have been specifically attributed.

Proved Reserves means those Reserves that can be estimated with a high degree of certainty to be recoverable. The reporting company must believe that there is at least a 90% probability that the actual remaining quantities recovered will equal or exceed those estimated Proved Reserves.

Record Date means, in respect of distributions of Distributable Income payable in a given calendar month, the fifth business day following the Cash Distribution Date in the immediately preceding calendar month.

Reserve Life Index means the amount obtained by dividing the quantity of Reserves by the Production of Petroleum Substances from those Reserves for the year ending December 31, 2005.

Reserves means 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, which are generally accepted as being reasonable, and shall be disclosed.

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ANNUAL INFORMATION FORM 2005

Royalty means the royalty payable to the Trust pursuant to the Royalty Agreements, which royalty equals 99% of Royalty Income.

Royalty Agreements means the amended and restated royalty agreement dated January 1, 2002 between PrimeWest and the Trustee as trustee for and on behalf of the Trust, and the royalty agreement dated January 24, 2003 between PrimeWest Gas and PrimeWest, which PrimeWest assigned to the Trust, as amended from time to time, regarding the creation and sale of the Royalty.

Royalty Income in respect of any period for which Royalty Income is calculated means Net Production Revenue less the aggregate of:

The Debt Service Costs, General and Administrative Costs and taxes (other than Crown royalties but including any capital taxes) payable by PrimeWest or the Trust;

Capital expenditures intended to improve or maintain Production from the Properties or to acquire additional Properties, in excess of amounts borrowed or designated as a deferred purchase price obligation pursuant to the Royalty Agreements, provided that the amount of capital expenditures that can be deducted will not be in excess of 10% of the annual net cash flow from the Properties in the year before the year in which the determination is made;

Net contributions to PrimeWest's reclamation fund; and

ARTC applicable to the Properties.

Any income derived from Properties which are not working, royalty or other interests in Canadian resource Properties or which do not relate to Production from working, royalty or other interests in Canadian resource properties, will not be included as Royalty Income and will be used to defray other expenses, capital expenditures of PrimeWest and Debt Service Costs.

SECmeans the United States Securities and Exchange Commission.

SEDARmeans the System for Electronic Document Analysis and Retrieval established by the Canadian Securities Administrators as the system used for electronically filing most securities related information with the Canadian securities regulatory authorities and accessible at www.sedar.com.

Series I Debentures means the Series I Convertible Unsecured Subordinated Debentures issued on September 2, 2004 that bear interest at an annual rate of 7.5%, payable semi-annually on March 31 and September 30 commencing March 31, 2005. The Series I Debentures are convertible at any time at the option of the holder into PrimeWest Trust Units at a conversion price of $26.50 per Trust Unit prior to maturity on September 30, 2009.

Series II Debentures means the Series II Convertible Unsecured Subordinated Debentures issued on September 2, 2004 that bear interest at 7.75%, payable semi-annually on June 30 and December 31 commencing December 31, 2004. The Series II Debentures are convertible at any time at the option of the holder into Trust Units at a conversion price of $26.50 per Trust Unit prior to maturity on December 31, 2011.

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.

Solution Gas means Natural Gas dissolved in Crude Oil.

Standard & Poorsmeans Standard & Poors, a division of The McGraw-Hill Companies, Inc.

Synthetic Oil means a mixture of hydrocarbons derived by upgrading crude bitumen from Oil sands or kerogen from Oil shales or other substances such as coal.

Tax Act means theIncome Tax Act (Canada), as amended from time to time.

Trust Units means the units of the Trust, each unit representing an equal undivided beneficial interest in the Trust.

TSXmeans the Toronto Stock Exchange.

PRIMEWEST ENERGY TRUST

ANNUAL INFORMATION FORM 2005

Undeveloped Reserves means those Reserves expected to be recovered from known accumulations where a significant expenditure is required to render them capable of Production. They must fully meet the requirements of the Reserves classification (Proved, Probable or Possible) to which they are assigned.

Unproved Properties means a Property or part of a Property to which no Reserves have been specifically attributed.

Unitholdersmeans the holders from time to time of one or more Trust Units.

Well Abandonment Costs mean costs of abandoning a well (net of salvage value) and of disconnecting the well from the surface gathering system. They do not include costs of abandoning the gathering system or reclaiming the wellsite.

PRIMEWEST ENERGY TRUST

ANNUAL INFORMATION FORM 2005

ITEM 12: SCHEDULE A – REPORT ON RESERVES DATA

BY INDEPENDENT QUALIFIED RESERVES EVALUATOR OR AUDITOR

Terms to which a meaning is ascribed in National Instrument 51-101 have the same meaning herein.

To the Board of Directors of PrimeWest Energy Inc. (the “Company”):

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

(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

(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 on the Reserves data, based on our evaluation.

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

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

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.


Description and Preparation Date of Audit/ Evaluation/ Review Report	Location of Reserves (Country or Foreign Geographic Area)	Net Present Value of Future Net Revenue (before income taxes 10% discount rate - $000’s)
	Location of Reserves (Country or Foreign Geographic Area)	Audited	Evaluated	Reviewed	Total
January 13, 2006	Canada	$ 0	$2,601,946	$ 82,013	$2,683,959

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 this evaluation for events and circumstances occurring after their respective preparation dates.

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

PRIMEWEST ENERGY TRUST

ANNUAL INFORMATION FORM 2005

Executed as to our report referred to above.

GLJ Petroleum Consultants Ltd., Calgary, Alberta, Canada

/s/ Myron J. Hladyshevsky

Hladyshevsky, P.Eng.

Vice-President

Dated: January 23, 2006

PRIMEWEST ENERGY TRUST

ANNUAL INFORMATION FORM 2005

ITEM 13: SCHEDULE B – REPORT OF MANAGEMENT AND DIRECTORS ON RESERVES DATA

AND OTHER INFORMATION (FORM 51-101 F3)

Terms to which a meaning is ascribed in National Instrument 51-101 have the same meaning herein.

Management of PrimeWest Energy Inc. (the “Company”) are responsible for the preparation and disclosure, or arranging for the preparation and disclosure of information with respect to the Company’s Oil and Gas activities in accordance with securities regulatory requirements. This information includes Reserves data, which consist of the following:

(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

(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 and reviewed the Company’s Reserves data. The report of the independent qualified Reserves evaluators is presented in Schedule B to the Annual Information Form of PrimeWest Energy Trust effective as at December 31, 2005.

The Operations and Reserves Committee of the Board of Directors of the Company has:

Reviewed the Company’s procedures for providing information to the independent qualified Reserves evaluators;

Met with the independent qualified Reserves evaluator(s) to determine whether any restrictions affected the ability of the independent qualified Reserves evaluators to report without reservation; and

Reviewed the Reserves data with Management and the independent qualified Reserves evaluators.

The Operations and Reserves Committee of the Board of Directors has reviewed the Company’s procedures for assembling and reporting other information associated with Oil and Gas activities and has reviewed that information with Management. The Board of Directors has, on the recommendation of the Operations and Reserves Committee, approved:

The content and filing with securities regulatory authorities of the Reserves data and other oil and gas information;

The filing of the report of the independent qualified Reserves evaluator(s) on the Reserves data; and

The content and filing of this report.

PRIMEWEST ENERGY TRUST

ANNUAL INFORMATION FORM 2005

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

/s/ Donald A. Garner

Donald A. Garner, President & Chief Executive Officer

/s/ Timothy S. Granger

Timothy S. Granger, Chief Operating Officer

/s/ Harold N. Kvisle

Harold N. Kvisle, Director

/s/ W. Glen Russell

W. Glen Russell, Director

Dated: March 15, 2006

PRIMEWEST ENERGY TRUST

ANNUAL INFORMATION FORM 2005

ITEM 14: SCHEDULE C – AUDIT COMMITTEE DISCLOSURE

PURSUANT TO MULTILATERAL INSTRUMENT 52-110

THE AUDIT AND FINANCE COMMITTEE CHARTER

1.0

Constitution

A standing Committee of the Board of Directors of PrimeWest Energy Inc. (the “Corporation”) consisting of members of the Board is hereby appointed by the Board from among their number and complying with all other legislation, regulations, TSX and NYSE listing standards agreements, articles and policies to which the Corporation, PrimeWest Energy Trust (the “Trust”) and their business are subject is hereby established and designated as the Audit and Finance Committee (hereinafter referred to as the “Audit Committee”). References to the Corporation in this Mandate shall be deemed to include the Trust, as applicable.

2.0

Overall Purpose/Objectives

The Audit Committee will assist the Board in fulfilling its oversight responsibilities, including the review and approval of:

the integrity of the Corporation’s financial statements;

the integrity of the financial reporting process;

the system of internal control and management of financial risks;

the external auditors’ qualifications and independence;

the external audit process and the Corporation’s process for monitoring compliance with laws and regulations;

internal audit and reviews as required or scheduled;

disclosure of any material information;

management information systems and the office operation disaster recovery program; and

equity offering prospectus.

In performing its duties, the Audit Committee will maintain effective working relationships with the Board, Management, the external auditors and the internal auditor. To perform his or her role effectively, each Audit Committee member will obtain an understanding of the Corporation’s business, operations, risks and related legislation, regulations and industry standards. So that the Audit Committee can discharge its duties as a whole, all Audit Committee members must be financially literate, and at least one member must have accounting or related financial management expertise.

3.0

Authority

The Board authorizes the Audit Committee, within its scope of duties and responsibilities, to:

seek any information it requires from employees of the Corporation (which employees are directed to co-operate with any request made by the Audit Committee);

seek any information it requires directly from external parties, including the external auditors, and approve the terms of retainer and the fees payable to such parties;

obtain outside legal or other professional advice and determine the fees payable for such advice without seeking Board approval (however providing notice to the Chair of the Board); and

determine the level of administrative expenses necessary for the Audit Committee to carry out its duties.

PRIMEWEST ENERGY TRUST

ANNUAL INFORMATION FORM 2005

4.0

Organization

The following provisions and regulations shall apply to the composition of the Audit Committee:

4.1

the Audit Committee shall consist of not less than three members of the Board of the Corporation;

4.2

the members of the Audit Committee shall be unrelated to Management and independent members of the Board as determined in accordance with TSX, Canadian Securities Administrators and NYSE Corporate Governance Guidelines as well as the Sarbanes-Oxley Act and any similar legislation as it becomes applicable to the Corporation;

4.3

the Chair of the Audit Committee shall be determined by the Board of the Corporation or by the members of the Audit Committee if the Chair is absent from the meeting;

4.4

as a minimum, one member of the Audit Committee must be viewed as a financial expert;

4.5

two members of the Audit Committee shall constitute a quorum thereof;

4.6

no business shall be transacted by the Audit Committee except at a meeting of its members at which a quorum is present in person or by telephone or by a resolution in writing signed by all members of the Audit Committee;

4.7

the meetings and proceedings of the Audit Committee shall be governed by the provisions of the by-laws of the Corporation that regulate meetings and proceedings of the Board;

4.8

the Audit Committee may invite such Directors, Officers or employees of the Corporation and the external auditors as it may see fit, to attend its meetings and take part in the discussion and consideration of the affairs of the Audit Committee;

4.9

meetings shall be held not less than four times per year, generally coinciding with the release of interim or year-end financial information. Special meetings may be convened as required upon the request of the Audit Committee or the Officers of the Corporation. The external auditors may convene a meeting if they consider that it is desirable or necessary;

4.10

the proceedings of all meetings will be minuted;

4.11

the Audit Committee shall meet separately, at least quarterly, with

Management

external auditors

internal auditors (or other such personnel responsible for the internal audit function)

and at the end of each meeting, by themselves;

4.12

the Audit Committee shall meet annually with the Operations and Reserves Committee; and

4.13

a forward Agenda will be established with Management.

5.0

Duties and Responsibilities

The Board hereby delegates and authorizes the Audit Committee to carry out the following duties and responsibilities to the extent that these activities are not carried out by the Board as a whole:

5.1

Corporate Information and Internal Control

5.1.1

review and recommend for approval of the quarterly and annual financial statements, Management Discussion & Analysis, press releases, annual report, AIF and Management Proxy Circular (salary and related benefit information will be reviewed and approved by the Compensation Committee);

PRIMEWEST ENERGY TRUST

ANNUAL INFORMATION FORM 2005

5.1.2

as part of the year end review process, jointly with the Operations and Reserves Committee, review and recommend for approval the year end Reserves and NAV reports;

5.1.3

review of internal control systems maintained by the Corporation;

5.1.4

review of major changes to management information systems;

5.1.5

review of spending authority and approval of limits;

5.1.6

review of significant accounting and tax compliance issues where there is choice among various alternatives or where application of a policy has a significant effect on the financial results of the Corporation;

5.1.7

review of significant proposed non-recurring events such as mergers, acquisitions or divestitures;

5.1.8

review press releases and other publicly circulated documents containing financial and earnings information, including financial information and earnings guidance provided to analysts and rating agencies; and

5.1.9

review and discuss with Management the minutes of all meetings of the Corporation’s Disclosure Committee.

5.2.

External Auditors

5.2.1

retain and terminate the external auditors (subject to Unitholder approval);

5.2.2

review the terms of the external auditors’ engagement and the appropriateness and reasonableness of the proposed engagement fees;

5.2.3

annually, obtain and review a report by the external auditors describing: the firm’s internal quality control procedures; any material issues raised by the most recent internal quality control review (or peer review) of the firm, or by any inquiry or investigation by governmental or professional authorities, within the preceding five years, respecting one or more independent audits carried out by the firm and any steps taken to deal with such issues;

5.2.4

annually, a certificate attesting to the external auditors’ independence, identifying all relationships between the external auditors and the Corporation;

5.2.5

annually, evaluate the external auditors’ qualifications, performance and independence, taking into account the opinions of Management and the Corporation’s internal auditor, and present conclusions to the Board;

5.2.6

annually, to assure continuing auditor independence, consider the rotation of lead audit partner or the external auditor itself;

5.2.7

where there is a change of external auditor, review all issues related to the change, including information to be included in the notice of change of auditors (National Instrument 51-102 as adopted by the Canadian Securities Regulatory Authorities), and the planned steps for an orderly transition;

5.2.8

review all reportable events, including disagreements, unresolved issues and consultations, as defined in National Instrument 51-102, on a routine basis, whether or not there is a change of auditors;

5.2.9

pre-approve engagements for non-audit services provided by the external auditors or their affiliates, together with estimated fees and potential issues of independence; and

5.2.10

set clear hiring policies for employees or former employees of the external auditors.

PRIMEWEST ENERGY TRUST

ANNUAL INFORMATION FORM 2005

5.3

Audit

5.3.1

review the audit plan for the coming year with the external auditors and with Management;

5.3.2

review with Management and the external auditors major issues regarding accounting principles and financial statement presentation, including any proposed changes in major accounting policies, the presentation and impact of significant risks and uncertainties, and key estimates and judgments of Management that may be material to financial reporting;

5.3.3

question Management and the external auditors regarding significant financial reporting issues during the fiscal period and the method of resolution of such issues;

5.3.4

review any problems experienced by the external auditors in performing the audit, as set out in an internal control letter issued by the auditor or otherwise, including any restrictions imposed by Management or significant accounting issues in which there was a disagreement with Management;

5.3.5

review audited annual financial statements and quarterly financial statements with Management and the external auditors (including disclosures under “Management Discussion & Analysis”), in conjunction with the report of the external auditors, and obtain explanation from Management of all significant variances between comparative reporting periods;

5.3.6

review the auditors’ report to Management, containing recommendations of the external auditors’, and Management’s response and subsequent remedy of any identified weaknesses;

5.3.7

prepare an Audit Committee report as required by the United States Securities and Exchange Commission to be included in the Corporation’s annual Management Proxy Circular; and

5.3.8

confirm with the external auditors, grants and payouts made, from time to time, under the Corporation’s Long Term Incentive Plan, including those made to the Officers of the Corporation.

5.4

Internal Auditor

5.4.1

ensure that the Corporation’s internal auditor has the qualifications and experience necessary to comply with the Corporation’s job description for this position, including systems experience, an appropriate designation and membership in the Institute of Internal Auditors;

5.4.2

review and approve the responsibilities, budget and staffing of the internal audit function and ensure that the chair of the committee and the CEO of the Corporation jointly conduct annual performance evaluations of the internal auditor;

5.4.3

review and approve an annual audit plan and ensure that the Chair of the Committee and the CEO of the Corporation jointly conduct annual reviews of the performance of the internal auditor;

5.4.4

ensure that the Corporation’s internal auditor is present at all Committee meetings; and

5.4.4

review and forward to the Board summaries of all reports prepared by the internal auditor with respect to the review of compliance and testing of internal controls, general audit reviews, special audits and other audit functions. The summaries will

PRIMEWEST ENERGY TRUST

ANNUAL INFORMATION FORM 2005

include the audit name, main recommendations and management plans to address the recommendations.

5.5

Risk Management and Controls

5.5.1

generally, review the Corporation’s risk assessment and risk management policies;

5.5.2

review hedging strategies, policies, objectives and controls;

5.5.3

review, not less than quarterly, a mark to market assessment of the Corporation’s hedge positions and counter party credit risk and exposure;

5.5.4

review the Corporation’s risk retention philosophy and resulting exposure to the Corporation;

5.5.5

review adequacy of insurance coverage, outstanding or pending claims and premium costs;

5.5.6

review loss prevention policies and risk management programs in the context of competitive and operational consideration ensuring that the Corporation is adequately protected from losses without impairing its business or its ability to compete in the industry;

5.5.7

annually review authority limits for capital expenditures sales and purchases;

5.5.8

review the Corporation’s procedures for the control, identification and reporting of fraudulent acts; and

5.5.9

take the steps necessary to address and resolve all instances or allegations of fraud reported to the Committee Chair by the Corporate Secretary or other designated recipient of complaints received through the Corporation’s Code of Business Conduct and Confidence Line.

5.6

Audit Committee Evaluation and Complaints

5.6.1

annually, in conjunction with the Corporate Governance and EH&S Committee, assess individual Audit Committee member and Chair performance and evaluate the performance of the Audit Committee as a whole, including its processes and effectiveness;

5.6.2

annually make determinations as to whether any Audit Committee member’s simultaneous service on audit committees of other boards impairs the member’s ability to effectively serve on the Audit Committee;

5.6.3

in conjunction with the Corporate Governance and EH&S Committee, develop and approve Audit Committee member eligibility criteria, identify Directors qualified to become Committee members and recommend appointments to and removals from the Audit Committee;

5.6.4

establish and publish procedures for the receipt, retention and treatment of complaints received by the Corporation regarding accounting, internal accounting controls or auditing matters;

5.6.5

establish and publish procedures for the confidential, anonymous submission by employees of the Corporation of concerns regarding questionable accounting or auditing matters, including submission through the Corporation’s Code of Business Conduct and Ethic Hotline, which shall be reported to the Committee Chair by the Corporate Secretary or other designated recipient; and

5.6.6

establish and publish procedures for the taking of the steps necessary to address and resolve complaints and concerns relating to accounting, internal control and auditing matters.

PRIMEWEST ENERGY TRUST

ANNUAL INFORMATION FORM 2005

5.7

Other Duties and Responsibilities

5.7.1

The responsibilities, practices and duties of the Audit Committee outlined herein are not intended to be comprehensive. The Board may, from time to time, charge the Audit Committee with the responsibility of reviewing items of a financial, control or of a risk management nature; and

5.7.2

The Audit Committee shall periodically report to the Board the results of all reviews undertaken and any associated recommendations.

COMPOSITION OF THE AUDIT COMMITTEE

The members of the Audit and Finance Committee are Peter Valentine, Harold P. Milavsky and Michael W. O’Brien. Mr. Valentine was appointed Chair of the Committee on May 5, 2005, replacing Mr. Milavsky in that capacity. Each member of the Audit and Finance Committee is independent and financially literate within the meaning of Multilateral Instrument 52-110.

RELEVANT EDUCATION AND EXPERIENCE

Mr. Valentine, B. Comm., FCA is currently Senior Advisor to the President and Chief Executive Officer of the Calgary Health Region and to the Dean of Medicine at the University of Calgary. Mr. Valentine is a Trustee, a member of the Audit Committee and a member of the Governance Committee of Fording Canadian Coal Trust, a director and Chair of the Audit Committee of Livingston International Income Fund, a director and member of the Audit Committee of Superior Plus Income Fund and a director and Chair of the Audit Committee of Resmor Trust Company (a private corporation).

Mr. Valentine was previously the Auditor General for the Province of Alberta (March 1995 to January 2002), Chair of the Financial Advisory Committee of the Alberta Securities Commission, member of the Accounting Standards Board and Public Sector Accounting Board of the Canadian Institute of Chartered Accountants, Chair of the Canadian Comprehensive Audit Foundation and also held senior positions at KPMG. In addition, for the period of December 2003 to June 2004, Mr. Valentine was Interim Vice-President, Finance and Services at the University of Calgary.

Mr. Milavsky, B. Comm., CA, is Chair of the Board of Quantico Capital Corp., a privately held company engaged in merchant banking, principal investments and acquisitions. Mr. Milavsky also serves as a director, member of the Audit Committee and member of the Nominating/Corporate Governance Committee of Saskatchewan Wheat Pool and as a director, Chair of the Board and Chair of the Audit Committee of the 13 investment trusts comprising the Citadel Group of Funds^TM. Mr. Milavsky was President and Chief Executive Officer of Trizec Corporation from 1976 to 1986 and Chair of the Board and Chief Executive Officer from 1986 to 1993. He has been a director of TransCanada Corporation, Telus Corporation, Northrock Resources Ltd., Encal Energy Ltd., Wascana Energy Inc., ENMAX Corporation and many other corporations. Mr. Milavsky is a Fellow of the Institute of Chartered Accountants of Alberta and, in 2002, he received the Institute’s Lifetime Achievement Award. Mr. Milavsky is also a member of the Institute of Corporate Directors and received that Institute’s Fellowship Award in 2005.

Mr. O’Brien B.A., MBA, serves, among other responsibilities, as director and Chair of the Audit Committee of Shaw Communications Inc., and as a director, member of the Audit Committee and member of the Environmental, Health & Safety Committee of Suncor Energy Inc. Mr. O’Brien is past Chair of the Canadian Petroleum Products Institute, Canada’s Voluntary Challenge Registry for Climate Change and the Nature Conservancy of Canada. Prior to retirement in 2002, Mr. O’Brien was the Executive Vice President, Corporate Development and Chief Financial Officer of Suncor Energy Inc. (December 1999 to June 2002).

PRE-APPROVAL POLICIES AND PROCEDURES

It is within the mandate of PrimeWest’s Audit and Finance Committee to approve all audit and non-audit related fees. The Audit and Finance Committee has pre-approved specifically identified non-audit tax-related services,

PRIMEWEST ENERGY TRUST

ANNUAL INFORMATION FORM 2005

including tax compliance; the review of tax returns; and tax planning and advisory services relating to common forms of domestic and international taxation (i.e. income tax, capital tax, goods and services tax, and value added tax) up to a pre-determined maximum annual limit of $50,000. The Audit and Finance Committee will be informed routinely as to the non-audit services actually provided by the auditor pursuant to this pre-approved process. The auditors also present the estimate for the annual audit related services to the Committee for approval prior to undertaking the annual audit of the financial statements.

EXTERNAL AUDITOR SERVICE FEES

The aggregate fees paid by PrimeWest to PricewaterhouseCoopers LLP, the auditors of PrimeWest, for professional services rendered in the Trust’s last two fiscal years are as follows:


	2005	2004
Audit fees⁽¹⁾	$ 297,000	$ 282,000
Audit related fees⁽²⁾	$ 9,000	$ 12,000
Tax fees⁽³⁾	$ 22,300	$ 66,858
All other fees⁽⁴⁾	$ 290,000	$ 105,000
	$ 618,300	$ 465,858

Notes:

(1)

Audit fees were for professional services rendered by PricewaterhouseCoopers LLP for the audit of the Trust’s annual financial statements and reviews of the Trust’s quarterly financial statements, as well as services provided in connection with statutory and regulatory filings or engagements.

(2)

Audit related fees are those fees billed for assurance and related services by PriceWaterhouseCoopers LLP that are reasonably related to the performance of the audit or review of the Trust’s financial statements but not included in Audit Fees. These services consisted of advice and guidance on new reporting standards.

(3)

Tax fees were for tax compliance, tax advice and tax planning professional services. The fees were for services performed by the Trust’s auditors’ tax division except those tax services related to the audit. These services consisted of: tax compliance including the review of tax returns; and tax planning and advisory services relating to common forms of domestic and international taxation (i.e. income tax, capital tax, goods and services tax and value added tax).

(4)

All other fees are those fees billed for products and services provided by PriceWaterhouseCoopers LLP, other than Audit Fees, Audit-related Fees and Tax Fees. Specifically, these fees relate to: Sarbanes-Oxley compliance and prospectus fees in 2004 and Sarbanes-Oxley compliance and the Registrant’s enterprise risk assessment in 2005.

Positive
Negative
Uncertain
Constraining
Legalese
Litigious
Readability	6th grade Avg

Primewest Energy Trust (PWI) Inactive 40-F2006 FY Annual report (Canada)

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