Primewest Energy Trust 40F 2004 Annual report | PWI Filing

Primewest Energy Trust (PWI) Inactive 40-F2004 FY Annual report (Canada)

Content analysis

Management’s Responsibility for Financial Statements and Management’s Discussion and Analysis

The consolidated financial statements of PrimeWest Energy Trust and Management’s Discussion and Analysis (MD&A) were prepared by, and are the responsibility of the management of PrimeWest Energy Inc. The consolidated financial statements have been prepared in accordance with accounting principles generally accepted in Canada. The financial and operating information presented in this annual report is consistent with that shown in the consolidated financial statements.

Management has designed and maintains a system of internal controls to safeguard assets and ensure that transactions are properly authorized and recorded and form part of these financial statements. Where estimates are used in the preparation of these financial statements, management has ensured that careful judgment has been made and that these estimates are reasonable, based on all information known at the time the estimates are made.

The Board of Directors of PrimeWest is responsible for ensuring that management fulfills its responsibilities for financial reporting, and it has reviewed and approved these financial statements and MD&A. The Board carries out this responsibility through the Audit and Finance Committee, which consists only of independent directors of the Board.

Unitholders have appointed the external audit firm of PricewaterhouseCoopers LLP to express their opinion on the consolidated financial statements. The auditors have full and unrestricted access to the Audit and Finance Committee to discuss their findings.

“Signed”	“Signed”
Don Garner	Dennis G. Feuchuk
President and Chief Executive Officer	Vice-President, Finance and Chief Financial Officer

February 24, 2005

PrimeWest Energy Trust Annual Report 2004

Auditors’ Report

TO THE UNITHOLDERS OF PRIMEWEST ENERGY TRUST:

We have audited the consolidated balance sheets of PrimeWest Energy Trust as at December 31, 2004 and 2003, and the consolidated statements of income, unitholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2004. These financial statements are the responsibility of the management of the Trust. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with Canadian generally accepted auditing standards. Those standards require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free from material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.

In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of the Trust as at December 31, 2004 and 2003, and the results of its operations and cash flows for each of the years in the three-year period ended December 31, 2004, in accordance with Canadian generally accepted accounting principles.

“Signed”

PricewaterhouseCoopers LLP, Chartered Accountants
Calgary, Alberta
February 11, 2005

PrimeWest Energy Trust Annual Report 2004

Consolidated Balance Sheets

				2003
As at December 31 ($ millions)	2004			(restated)
ASSETS
Current assets
Cash and cash equivalents	$	54.4		$	2.5
Marketable securities (note 4)		68.6			–
Accounts receivable		96.9			65.4
Assets held for sale (note 6)		5.4			–
Prepaid expenses		10.9			6.5
Inventory		5.8			2.1
		242.0			76.5
Cash reserved for site restoration and reclamation (note 10)		10.3			8.2
Other assets and deferred charges (note 7)		10.9			1.5
Derivative asset (note 16)		0.6			–
Property, plant and equipment (note 6)		1,908.6			1,548.2
Goodwill (note 5)		68.5			56.1
	$	2,240.9		$	1,690.5

LIABILITIES AND UNITHOLDERS’ EQUITY
Current liabilities
Accounts payable	$	47.7		$	26.7
Accrued liabilities		72.3			45.3
Derivative liability (note 16)		0.5			–
Accrued distributions to Unitholders		17.7			10.3
		138.2			82.3
Long-term debt (note 8)		656.3			250.1
Future income taxes (note 15)		211.2			313.2
Asset retirement obligation (note 9)		40.3			19.7

		1,046.0			665.3
UNITHOLDERS’ EQUITY
Net capital contributions (note 11)		2,049.9			1,565.9
Capital issued but not distributed		3.3			5.2
Convertible Unsecured Subordinated Debentures (note 8)		8.1			–
Long-Term Incentive Plan equity (note 12)		20.1			14.6
Accumulated income		89.2			219.1
Accumulated cash distributions		(967.7	)		(771.6	)
Accumulated dividends		(8.0	)		(8.0	)
		1,194.9			1,025.2
	$	2,240.9		$	1,690.5
Commitments and contingencies (note 17).

The accompanying notes form an integral part of these financial statements.

PrimeWest Energy Trust Annual Report 2004

Consolidated Statements of Unitholders’ Equity

				2003			2002
For the years ended December 31 ($ millions)	2004			(restated)			(restated)

Unitholders’ equity, beginning of year	$	1,025.2		$	847.1		$	856.3
Adjustment to Unitholders’ equity at beginning of period to adopt:
New asset retirement obligation		–			–			1.2
New oil and gas accounting standard		(233.3	)		–			–
Net income for the year		103.4			95.9			(0.6	)
Net capital contributions		484.0			265.9			147.4
Capital issued but not distributed		(1.9	)		4.3			(0.1	)
Convertible Unsecured Subordinated Debentures		8.1			–			–
Long-Term Incentive Plan equity		5.5			4.6			2.1
Cash distributions		(196.1	)		(192.6	)		(158.0	)
Dividends		–			–			(1.2	)
Unitholders’ equity, end of year	$	1,194.9		$	1,025.2		$	847.1

PrimeWest Energy Trust Annual Report 2004

Consolidated Statements of Cash Flow

				2003			2002
For the years ended December 31 ($ millions)	2004			(restated)			(restated)
OPERATING ACTIVITIES
Net income for the year	$	103.4		$	95.9		$	(0.6	)
Add/(deduct):
Items not involving cash from operations
Depletion, depreciation and amortization		197.3			197.4			183.2
Non-cash general and administrative		9.4			14.4			6.1
Non-cash foreign exchange gain		(11.9	)		(12.1	)		–
Cash distributions from marketable securities		4.1			–			–
Non-cash management fees		–			–			1.4
Non-cash internalization		–			–			13.1
Unrealized gain on derivatives		(0.1	)		–			–
Future income taxes recovery		(37.6	)		(79.9	)		(33.2	)
Accretion on asset retirement obligation		2.0			1.2			0.9
Other non-cash items		0.2			(0.3	)		–
Cash flow from operations		266.8			216.6			170.9
Expenditures on site restoration and reclamation		(4.6	)		(2.2	)		(3.9	)
Change in non-cash working capital		11.9			5.3			(10.7	)
	$	274.1		$	219.7		$	156.3
FINANCING ACTIVITIES
Proceeds from issue of Trust Units (net of costs)	$	441.0		$	240.3		$	118.3
Proceeds from issue of Debentures		250.0			–			–
Net cash distributions to Unitholders (note 13)		(159.6	)		(172.5	)		(145.1	)
Dividends		–			–			(1.2	)
Increase (decrease) in bank credit facilities		166.0			(137.0	)		29.9
Increase in Senior Secured Notes		–			174.0			–
Increase in deferred charges		(10.0	)		(1.5	)		–
Change in non-cash working capital		10.9			(3.6	)		1.0
	$	698.3		$	99.7		$	2.9
INVESTING ACTIVITIES
Expenditures on property, plant and equipment	$	(129.7	)	$	(105.8	)	$	(69.1	)
Acquisition of capital/corporate assets		(807.4	)		(210.1	)		(59.6	)
Proceeds on disposal of property, plant and equipment		96.5			2.3			4.5
Investment in marketable securities		(72.7	)		–			–
(Increase) decrease in cash reserved for future site restoration and reclamation		(2.1	)		(6.6	)		0.7
Expenditures on future acquisitions		–			–			(14.1	)
Change in non-cash working capital		(5.1	)		6.4			(10.1	)
	$	(920.5	)	$	(313.8	)	$	(147.7	)
INCREASE IN CASH FOR THE YEAR	$	51.9		$	5.6		$	11.5
CASH (BANK OVERDRAFT) BEGINNING OF THE YEAR		2.5			(3.1	)		(14.6	)
CASH (BANK OVERDRAFT) END OF THE YEAR	$	54.4		$	2.5		$	(3.1	)
CASH INTEREST PAID	$	15.0		$	13.1		$	10.3
CASH TAXES PAID	$	3.8		$	3.9		$	4.0

PrimeWest Energy Trust Annual Report 2004

Consolidated Statements of Income

For the years ended December 31				2003			2002
($ millions, except per Trust Unit amounts)	2004			(restated)			(restated)
REVENUES
Sales of crude oil, natural gas and natural gas liquids	$	521.9		$	442.9		$	326.8
Transportation expenses		(8.2	)		(8.3	)		(6.3	)
Crown and other royalties, net of ARTC		(119.8	)		(101.9	)		(56.5	)
Unrealized gain on derivatives		0.1			–			–
Other income		0.6			(2.8	)		0.3
		394.6			329.9			264.3
EXPENSES
Operating		88.9			79.4			60.8
Cash general and administrative		19.0			14.5			11.3
Non-cash general and administrative		9.4			14.4			6.1
Interest		20.6			15.1			10.8
Depletion, depreciation and amortization		197.3			197.4			183.2
Cash management fees (note 14)		–			–			4.0
Cash internalization costs		–			–			3.6
Non-cash management fees (note 14)		–			–			1.4
Non-cash internalization costs (note 14)		–			–			13.1
Accretion on asset retirement obligation		2.0			1.2			0.9
Foreign exchange gain		(11.7	)		(11.9	)		–
		325.5			310.1			295.2
Income (loss) before taxes for the year		69.1			19.8			(30.9	)
Income and capital taxes		3.3			3.8			2.9
Future income taxes recovery (note 15)		(37.6	)		(79.9	)		(33.2	)
		(34.3	)		(76.1	)		(30.3	)
Net income for the year	$	103.4		$	95.9		$	(0.6	)
Net income per Trust Unit	$	1.74		$	2.08		$	(0.02	)
Diluted net income per Trust Unit	$	1.74		$	2.07		$	(0.02	)

PrimeWest Energy Trust Annual Report 2004

Notes to Consolidated Financial Statements

(All amounts are expressed in millions of Canadian dollars unless otherwise indicated.)

1. STRUCTURE OF THE TRUST

PrimeWest Energy Trust (the Trust) is an open-ended investment trust formed under the laws of Alberta in accordance with a declaration of trust dated August 2, 1996, as Amended. The beneficiaries of the Trust are the holders of Trust Units (the Unitholders).

The principal undertaking of the Trust’s operating companies, PrimeWest Energy Inc. and PrimeWest Gas Corp. (collectively referred to as PrimeWest), is to acquire and hold, directly and indirectly, interests in oil and gas properties. One of the Trust’s primary assets is a royalty entitling it to receive 99% of the net cash flow generated by the oil and gas interests owned by PrimeWest. The royalty acquired by the Trust effectively transfers substantially all of the economic interest in the properties to the Trust.

The common shares of PrimeWest Energy Inc. are 100% owned by the Trust. PrimeWest Gas Corp. is a wholly

owned subsidiary of PrimeWest Energy Inc.

On November 4, 2002, Unitholders voted, by a 92% majority, to internalize management. PrimeWest Management Inc. and its shareholders received a total of $26.3 million in connection with that transaction. Approximately $13.2 million related to the acquisition of the 1% retained royalty and was recorded as an acquisition in property, plant and equipment. The balance was charged to non-cash internalization expense. In addition, retention provisions for senior management to receive 94,340 Exchangeable Shares on each of the second, third, fourth and fifth anniversaries of the completion of the internalization transaction were agreed to and $1.5 million was accrued relating to the termination of the management incentive program (see Note 14).

2. ACCOUNTING POLICIES

Consolidation

These consolidated financial statements include the accounts of the Trust and its wholly owned subsidiaries, PrimeWest Energy Inc. and PrimeWest Gas Corp. The Trust, through the royalty, obtains substantially all of the economic benefits of the operations of PrimeWest.

Cash and Cash Equivalents

Short-term investments, with maturities less than three months at the date of acquisition, are considered to be

cash equivalents and are recorded at cost, which approximates market value.

Marketable Securities

Marketable securities are carried at the lower of cost or market.

Inventory

Inventory is measured at lower of cost and net realizable value.

PrimeWest Energy Trust Annual Report 2004

Goodwill

Goodwill represents the excess of purchase price over fair value of net assets acquired and liabilities assumed. Goodwill is assessed for impairment at least annually. To assess impairment, the fair value of each reporting unit is determined and compared to the book value of the reporting unit. The amount of the impairment is determined by deducting the fair value of the reporting unit’s assets and liabilities from the fair value of the reporting unit to determine the implied fair value of goodwill and comparing that amount to the book value of the reporting unit’s goodwill. Any excess of the book value of goodwill over the implied fair value of goodwill is the impairment amount.

Property, Plant and Equipment

PrimeWest follows the full cost method of accounting. All costs of acquiring oil and gas properties and related development costs are capitalized and accumulated in one cost centre. Maintenance and repairs are charged against earnings. Renewals and enhancements that extend the economic life of the capital asset are capitalized.

Gains and losses are not recognized on disposition of oil and gas properties unless that disposition would alter

the rate of depletion by 20% or more.

i) Ceiling Test

PrimeWest places a limit on the aggregate cost of capital assets that may be carried forward for depletion against net revenues of future periods (the ceiling test). The ceiling test is an impairment test whereby the carrying amount of capitalized assets is compared to the undiscounted cash flows from Proved reserves plus Unproved properties using management’s best estimate of future prices. If the asset value exceeds the undiscounted cash flows the impairment is measured as the amount by which the carrying amount of the capitalized asset exceeds the future discounted cash flows from Proved plus Probable reserves. The discount rate used is the risk-free rate.

ii) Asset Retirement Obligation

PrimeWest recognizes the future retirement obligations associated with the retirement of property, plant and equipment. The obligations are initially measured at fair value and subsequently adjusted for accretion of discount and changes in the underlying liability. The asset retirement cost is capitalized to the related asset and amortized to earnings over time.

iii) Depletion, Depreciation and Amortization

Provision for depletion and depreciation is calculated on the unit-of-production method, based on Proved reserves before royalties. Reserves are estimated by independent petroleum engineers. Reserves are converted to equivalent units on the basis of approximate relative energy content. Depreciation and amortization of head office furniture and equipment is provided for at rates ranging from 10–30%.

Joint Venture Accounting

PrimeWest conducts substantially all of its oil and gas production activities through joint ventures, and theaccounts reflect only PrimeWest’s proportionate interest in such activities.

PrimeWest Energy Trust Annual Report 2004

Long-Term Incentive Plan

Liabilities under the Trust’s Long-Term Incentive Plan are estimated at each balance sheet date, based on the amount of Unit Appreciation Rights that are in the money using the Unit price as at that date. Expenses are recorded through non-cash general and administrative costs, with an offsetting amount in Long-Term Incentive Plan equity. As Trust Units are issued under the plan, the exercise value is recorded in net capital contributions.

Income Taxes

The Trust is considered an inter-vivos trust for income tax purposes. As such, the Trust is subject to tax on any taxable income that is not allocated to the Unitholders. Periodically, current taxes may be payable by PrimeWest, depending upon the timing of income tax deductions. Should these taxes prove to be unrecoverable, they will be deducted from royalty income in accordance with the royalty agreement.

Future income taxes are recorded for PrimeWest using the liability method of accounting. Future income taxes are recorded to the extent that the carrying value of PrimeWest’s capital assets exceeds the available tax pools.

Financial Instruments

PrimeWest uses financial instruments to manage its exposure to fluctuations in commodity prices and interest rates. PrimeWest does not use financial instruments for speculative trading purposes. The financial instruments are marked-to-market with the resulting gain or loss reflected in earnings for the reporting period.

Measurement Uncertainty

Certain items recognized in the financial statements are subject to measurement uncertainty. The recognized amounts of such items are based on PrimeWest’s best information and judgment. Such amounts are not expected to change materially in the near term. They include the amounts recorded for depletion, depreciation and future asset retirement obligations which depend on estimates of oil and gas reserves or the economic lives and future cash flows from related assets.

3. CHANGES IN ACCOUNTING POLICIES

Full Cost Accounting

The adoption of CICA Accounting Guideline 16 (AcG-16) modifies how the ceiling test is performed, resulting in a two-stage process. The guideline is effective for fiscal years beginning on or after January 1, 2004. The cost impairment test is now a two-stage process which is to be performed at least annually. The first stage of the test determines if the cost pool is impaired. An impairment loss exists when the carrying amount of an asset is not recoverable and exceeds its fair value. The carrying amount is not recoverable if it exceeds the sum of the undiscounted cash flows from Proved reserves plus Unproved properties using management’s best estimate of future prices. The second stage determines the amount of the impairment loss to be recorded. The impairment is measured as the amount by which the carrying amount of capitalized assets exceeds the future discounted cash flows from Proved plus Probable reserves. The discount rate used is the risk-free rate.

PrimeWest has performed the ceiling test under AcG-16 as of January 1, 2004. The impairment test wascalculated using the consultants’ average prices at January 1 for the years 2004 to 2008 as follows:

PrimeWest Energy Trust Annual Report 2004

Consultants’ Average Price Forecasts

	2004		2005		2006		2007		2008
WTI (US$/bbl)		29.21		26.43		25.42		25.38		25.51
AECO (Cdn$/mcf)		5.90		5.33		4.98		4.95		4.92

The ceiling test resulted in a before-tax impairment of $308.9 million and an after-tax impairment of $233.3 million.This write-down was recorded to accumulated income in the first quarter of 2004 with the adoption of AcG-16.

Asset Retirement Obligation

Effective January 1, 2004, the Trust retroactively adopted the CICA Handbook section 3110, “Asset Retirement Obligations”. The new standard requires the recognition of the liability associated with the future site reclamation costs of tangible long-lived assets. This liability would be comprised of the Trust’s net ownership interest in producing wells and processing plant facilities. The liability for future retirement obligations is to be recorded in the financial statements at the time the liability is incurred.

The asset retirement obligation is initially recorded at the estimated fair value as a long-term liability with a corresponding increase to property, plant and equipment. The depreciation of property, plant and equipment is allocated to expense on the unit-of-production basis. The liability is increased each reporting period for the fair value of any new future site reclamation costs and the corresponding accretion on the original provision. The accretion is charged to earnings in the period incurred. The provision will also be revised for any changes to timing related to cash flows or undiscounted reclamation costs. Actual expenditures incurred for the purpose of site reclamation are charged to the asset retirement obligation to the extent that the liability exists on the balance sheet. Differences between the actual costs incurred and the fair value of the liability recorded are recognized in earnings in the period incurred.

The adoption of CICA Handbook section 3110 allows for the cumulative effect of the change in accounting policy to be recorded to accumulated income with retroactive restatement of prior period comparatives. At January 1, 2004, this resulted in an increase to the asset retirement obligation of $19.7 million (2003 –$15.3 million, 2002 – $11.8 million); an increase to Property, Plant and Equipment (PP&E) of $10.6 million (2003 – $9.0 million, 2002 – $7.7 million); a $5.6 million (2003 – $0.04 million, 2002 – $1.2 million) increase to accumulated income; a decrease of site restoration provision of $17.8 million (2003 – $6.2 million, 2002 –$6.1 million); and an increase to the future tax liability of $3.1 million (2003 – $(0.03) million, 2002 – $0.9 million). See Note 9 for the reconciliation of the asset retirement obligation.

Implementation of this accounting standard did not affect the Trust’s cash flow or liquidity.

Financial Derivatives

Effective January 1, 2004, the Trust has implemented CICA Accounting Guideline 13 (AcG-13), “Hedging Relationships”, which is effective for fiscal years beginning on or after July 1, 2003. AcG-13 addresses the identification, designation, documentation and effectiveness of hedging transactions for the purposes of applying hedge accounting. It also established conditions for applying or discontinuing hedge accounting. Under the new guideline, hedging transactions must be documented and it must be demonstrated that the hedges are sufficiently effective in order to continue accrual accounting for position hedges with derivatives. The Trust is not applying hedge accounting to its hedging relationships.

PrimeWest Energy Trust Annual Report 2004

As of January 1, 2004, the Trust recorded $6.0 million for the mark-to-market value of the outstanding hedges as a derivative liability and a $6.0 million deferred derivative loss, to be realized upon settlement of the corresponding derivative instrument. The deferred loss at January 1, 2004 was comprised of a $3.9 million loss for crude oil, $2.1 million loss for natural gas, $0.6 million loss for interest rate swaps and a gain of $0.6 million for electrical power.

4. MARKETABLE SECURITIES

($ millions)	2004		2003
Investment in Calpine Natural Gas Trust	$	68.6	$	–

As at December 31, 2004, PrimeWest had a 25% ownership in Calpine Natural Gas Trust. The investment isaccounted for using the cost method. The market value of the investment at December 31, 2004 is $91.0 million.

5. ACQUISITIONS

a) On September 2, 2004, PrimeWest Gas Corp. acquired oil and gas assets from Calpine Canada. The acquisition was accounted for using the purchase method of accounting with the net assets acquired and consideration paid as follows:

Net Assets Acquired at Assigned Values	($ millions)			Consideration Paid	($ millions)
Petroleum and natural gas assets	$	746.9
Inventory	$	4.2		Cash	$	747.0
Working capital	$	2.9		Net closing adjustments	$	(10.3	)
Asset retirement obligation	$	(12.0	)	Costs associated with acquisition	$	5.3
	$	742.0			$	742.0

b) On March 16, 2004, PrimeWest Gas Corp. completed the acquisition of Seventh Energy Ltd. Subsequent to the acquisition, Seventh Energy was amalgamated with PrimeWest Gas Corp. The acquisition was accounted for using the purchase method of accounting with net assets acquired and consideration paid as follows:

Net Assets Acquired at Assigned Values	($ millions)			Consideration Paid	($ millions)
Petroleum and natural gas assets	$	46.5
Goodwill	$	12.4
Working capital	$	(2.5	)
Long-term debt assumed	$	(9.9	)
Office lease obligation	$	(0.1	)
Asset retirement obligation	$	(0.5	)	Cash	$	34.6
Future income taxes	$	(11.1	)	Costs associated with acquisition	$	0.2
	$	34.8			$	34.8

PrimeWest Energy Trust Annual Report 2004

c) On January 23, 2003, PrimeWest Gas Inc. completed the acquisition of two private Canadian oil and gas companies. Subsequent to the transaction, PrimeWest Gas Inc. was wound up into PrimeWest Energy Inc. The acquired companies were amalgamated with PrimeWest Gas Corp. The acquisition was accounted for using the purchase method of accounting with net assets acquired and consideration paid as follows:

Net Assets Acquired at Assigned Values	($ millions)			Consideration Paid	($ millions)
Petroleum and natural gas assets	$	220.9
Goodwill	$	56.1
Working capital, including cash of $3.9 million	$	0.7
Site restoration provision	$	(5.4	)	Cash	$	212.7
Future income taxes	$	(53.2	)	Costs associated with acquisition	$	6.4
	$	219.1			$	219.1

6. PROPERTY, PLANT AND EQUIPMENT

	2004
($ millions)	Cost		Accumulated Depletion Depreciation and Amortization			Net Book Value
Property acquisition oil and gas rights	$	2,671.2	$	(1,081.0	)	$	1,590.2
Drilling and completion	$	298.0	$	(77.1	)	$	220.9
Production facilities and equipment	$	125.1	$	(34.0	)	$	91.1
Leasehold improvements, furniture and equipment	$	12.6	$	(6.2	)	$	6.4
	$	3,106.9	$	(1,198.3	)	$	1,908.6

	2003
($ millions)	Cost		Accumulated Depletion Depreciation and Amortization			Net Book Value
Property acquisition oil and gas rights	$	1,933.3	$	(612.3	)	$	1,321.0
Drilling and completion	$	208.0	$	(52.1	)	$	155.9
Production facilities and equipment	$	91.0	$	(23.1	)	$	67.9
Leasehold improvements, furniture and equipment	$	8.0	$	(4.6	)	$	3.4
	$	2,240.3	$	(692.1	)	$	1,548.2

Unproved land costs of $103.9 million (2003 – $36.0 million) are excluded from costs subject to depletionand depreciation.

PrimeWest capitalized $2.9 million of general and administrative costs in 2004 (2003 – $2.5 million).

On February 4, 2005, PrimeWest closed the disposition of a property, receiving the balance of the proceedsof $5.4 million. At December 31, 2004, the amount was recorded as assets held for sale in current assets.

PrimeWest Energy Trust Annual Report 2004

PrimeWest has performed a ceiling test as at December 31, 2004. The impairment test was calculated usingthe consultants’ average prices at January 1 for the years 2005 to 2009 as follows:

Consultants’ Average Price Forecasts	2005		2006		2007		2008		2009
WTI (US$/bbl)		42.76		40.37		37.36		34.82		33.45
AECO (Cdn$/mcf)		6.79		6.52		6.25		5.95		5.79

The December 31, 2004 ceiling test resulted in a surplus.

A ceiling test was performed at December 31, 2003 in accordance with CICA Accounting Guideline 5 (AcG-5), “Full Cost Accounting in the Oil and Gas Industry”, using December 31, 2003 commodity prices of AECO $6.09/mcf for natural gas and WTI US$32.52/barrel for crude oil. The December 31, 2003 ceiling test resulted in a surplus.

7. OTHER ASSETS AND DEFERRED CHARGES

($ millions)	2004		2003
Deferred charges	$	10.6	$	1.3
Other assets		0.3		0.2
	$	10.9	$	1.5

8. LONG-TERM DEBT

($ millions)	2004		2003
Bank credit facility	$	264.0	$	88.0
Senior Secured Notes		150.3		162.1
Convertible Unsecured Subordinated Debentures		242.0		–
	$	656.3	$	250.1

Long-term debt is comprised of bank credit facilities, Senior Secured Notes and Convertible UnsecuredSubordinated Debentures of $264.0 million, $150.3 million and $242.0 million respectively.

PrimeWest had a maximum borrowing base of $625 million at December 31, 2004 (2003 – $390 million) as established by the lenders. The bank credit facilities consist of a revolving term loan of $437.5 million and an operating facility of $25 million with the balance of $162.5 million being the maximum amount of the Senior Secured Notes. In addition to amounts outstanding under the facility, PrimeWest has outstanding letters of credit in the amount of $4.9 million (2003 – $5.1 million).

Advances under the bank credit facility are made in the form of Banker’s Acceptances (BA), prime rate loans or letters of credit. In the case of BAs, interest is a function of the BA rate plus a stamping fee based on the Trust’s current ratio of debt to cash flow. In the case of prime rate loans, interest is charged at the bank’s prime rate. For 2004, the effective interest rate on the facilities was 4.0% (2003 – 4.7%).

The bank credit facility revolves until June 30, 2005, by which time the lenders will have conducted their annual borrowing base review. The lenders also have the right to re-determine the borrowing base at one other time during the year. During the revolving phase, the bank credit facility has no specific terms of repayment. At the end of the revolving period, the lender has the right to extend the revolving period for a further 364-dayperiod or to convert the facility to a term facility. If the lender converts to a non-revolving facility, 60% of the aggregate principal amount of the loan shall be repayable on the date that is 366 days after such conversion date and the remaining 40% of the aggregate principal amount outstanding shall be repayable on the date that is 365 days after the initial term repayment date.

PrimeWest Energy Trust Annual Report 2004

The Senior Secured Notes (the “Notes”) in the amount of US$125 million have a final maturity of May 7, 2010, and bear interest at 4.19% per annum, with interest paid semi-annually on November 7 and May 7 of each year. The Note Purchase Agreement requires PrimeWest to make four annual principal repayments of US$31,250,000 commencing May 7, 2007.

Collateral for the Notes and the bank credit facility is a floating charge Debenture covering all existing and after acquired property in the principal amount of US$1 billion. The secured parties under the bank credit facility and Senior Secured Notes have agreed to share the security interests on a pari passu basis.

The costs incurred in connection with the Notes, in the amount of $1.5 million, are classified as deferredcharges on the balance sheet and are being amortized over the term of the Notes.

The Notes are the legal obligation of PrimeWest Energy Inc. and are guaranteed by PrimeWest Energy Trust.

The 7.5% (Series I) and 7.75% (Series II) Convertible Unsecured Subordinated Debentures were issued onSeptember 2, 2004 for proceeds of $150 million and $100 million respectively.

The Series I Debentures pay interest semi-annually on March 31 and September 30 and have a maturity date of September 30, 2009. The Series I Debentures are convertible at the option of the holder to Trust Units at a conversion price of $26.50 per Trust Unit. PrimeWest has the option to redeem the Series I Debentures at a price of $1,050 per Series I Debenture after September 30, 2007 and on or before September 30, 2008, and at a price of $1,025 per Series I Debenture after September 30, 2008 and before maturity. On redemption or maturity, the Trust may elect to satisfy its obligation to repay the principal by issuing PrimeWest Trust Units.

The Series II Debentures pay interest semi-annually on June 30 and December 30 and have a maturity date of December 31, 2011. The Series II Debentures are convertible at the option of the holder to Trust Units at a conversion price of $26.50 per Trust Unit. PrimeWest has the option to redeem the Series II Debentures at a price of $1,050 per Series II Debenture after December 31, 2007 and on or before December 31, 2008, at a price of $1,025 per Debenture after December 31, 2008 and on or before December 31, 2009 and after December 31, 2009 and before maturity at $1,000 per Series II Debenture. On redemption or maturity, the Trust may elect to satisfy its obligations to repay the principal by issuing PrimeWest Trust Units.

Debenture issue costs of $10.0 million are included in deferred charges on the balance sheet and are beingamortized over the terms of the Debentures.

In accordance with CICA Handbook section 3860 – “Financial Instruments,” the Convertible Unsecured Subordinated Debentures were initially recorded at their fair value of $147.0 million (Series I) and $94.9 million (Series II). The difference between the fair value and proceeds of $8.1 million was recorded in equity ($3.0 million (Series I) and $5.1 million (Series II)).

PrimeWest Energy Trust Annual Report 2004

The Series I and Series II Debentures are being accreted such that the liability at maturity will equal the proceeds of $150 million and $100 million less conversions respectively. As at December 31, 2004, $0.3 million of the Series I Debentures had been converted to equity and $0.2 million of accretion was realized. Series II accretion was $0.2 million.

9. ASSET RETIREMENT OBLIGATIONS

Management has estimated the total future asset retirement obligation based on the Trust’s net ownership interest in all wells and facilities. This includes all estimated costs to dismantle, remove, reclaim and abandon the wells and facilities and the estimated time period during which these costs will be incurred in the future.

The following table reconciles the asset retirement obligation associated with the retirement of oil andgas properties:

Asset Retirement Obligation($ millions)	2004			2003
Asset retirement obligation, January 1	$	19.7		$	15.3
Liabilities incurred		13.1			5.4
Liabilities settled		(4.6	)		(2.2	)
Accretion expense		2.0			1.2
Acquisition of capital assets		12.0			–
Disposal of capital assets		(2.4	)		–
Acquisition of Seventh Energy		0.5			–
Asset retirement obligation December 31	$	40.3		$	19.7

As at December 31, 2004, the undiscounted amount of estimated cash flows required to settle the obligation is $238.6 million. The estimated cash flow has been discounted using a credit-adjusted risk-free rate of 7.0% and an inflation rate of 1.5%. Although the expected period until settlement ranges from a minimum of one year to a maximum of 50 years, the costs are expected to be paid over an average of 33.2 years. These future asset retirement costs will be funded from the cash reserved for site restoration and reclamation. This cash reserve of $10.3 million is currently funded at $0.50/BOE from PrimeWest’s operations.

10. CASH RESERVE FOR SITE RESTORATION AND RECLAMATION

Commencing in 1998, funding for the reserve was provided for by reducing distributions otherwise payable based on an amount per BOE produced ($0.50/BOE produced for 2004 and 2003). The cash amount contributed, including interest earned, was $6.7 million in 2004 (2003 – $8.7 million). Actual costs of site restoration and abandonment totalling $4.6 million were paid out of this cash reserve for the year ended December 31, 2004 (2003 – $2.2 million).

PrimeWest Energy Trust Annual Report 2004

11. UNITHOLDERS' EQUITY

The authorized capital of the Trust consists of an unlimited number of Trust Units.

Trust Units	Number of Units		Amounts ($ millions)
Balance, December 31, 2002		37,004,522	$	1,252.2
Issued for cash		9,100,000		234.8
Issue expenses		–		(12.1	)
Issued on exchange of Exchangeable Shares		964,897		21.2
Issued pursuant to Distribution Reinvestment Plan		600,598		14.8
Issued pursuant to Long-Term Incentive Plan		360,608		9.4
Issue of Units due to odd lot program		38		–
Issue of fractional units due to 4:1 consolidation		11		–
Issued pursuant to Optional Trust Unit Purchase Plan		721,209		17.6
Balance, December 31, 2003		48,751,883	$	1,537.9
Issued for cash		17,700,000		442.1
Issue expenses		–		(22.6	)
Issued on exchange of Exchangeable Shares		833,162		17.0
Issued pursuant to Distribution Reinvestment Plan		268,677		6.5
Issued pursuant to Premium Distribution Plan		1,311,462		32.0
Issued pursuant to Long-Term Incentive Plan		116,233		3.0
Issued pursuant to conversion of Debentures		10,527		0.3
Issued pursuant to Optional Trust Unit Purchase Plan		894,167		21.5
Balance, December 31, 2004		69,886,111	$	2,037.7

The weighted average number of Trust Units and Exchangeable Shares outstanding in 2004 was 59,482,034 (2003 – 46,015,519). For purposes of calculating diluted net income per Trust Unit, 1,868,995 and 1,247,551 Trust Units issuable pursuant to the conversion of the Series I and Series II Convertible Unsecured Subordinated Debentures respectively and 525,129 Trust Units (2003 – 345,278) issuable pursuant to the Long-Term Incentive Plan were added to the weighted average number. The per Unit cash distribution amounts paid or declared reflects distributions paid or declared to Trust Units outstanding on the record dates.

PrimeWest Exchangeable Class A Shares

PrimeWest has an unlimited number of Exchangeable Shares. The Exchangeable Shares are exchangeable into PrimeWest Trust Units at any time up to March 29, 2010, based on an exchange ratio that adjusts each time the Trust makes a distribution to its Unitholders. The exchange ratio, which was 1:1 on the date of the initial Exchangeable Share offering, is based on the total monthly distribution, divided by the closing Unit price on the distribution payment date. The exchange ratio on December 31, 2004 was 0.50408:1 (2003 – 0.44302:1).

Exchangeable Shares	Number of Units			Amounts ($ millions)
Balance, December 31, 2002		5,179,278		$	47.7
Issued for management incentive program		161,717			1.5
Exchanged for Trust Units		(2,299,872	)		(21.2	)
Balance, December 31, 2003		3,041,123			28.0
Issued for special employee incentive program		94,340			1.2
Exchanged for Trust Units		(1,841,072	)		(17.0	)
Balance, December 31, 2004		1,294,391		$	12.2

PrimeWest Energy Trust Annual Report 2004

Trust Units and Exchangeable Shares Issued and Outstanding
Number of Shares	2004		2003
Trust Units issued and outstanding		69,886,111		48,751,883
Exchangeable Shares
Class A Shares
(2004 – 1,294,391 shares exchangeable at 0.50408; 2003 – 3,041,123 shares exchangeable at 0.44302)		652,477		1,347,277
Total Units and Exchangeable Shares issued and outstanding		70,538,588		50,099,160
Convertible Unsecured Subordinated Debentures
Series I		5,649,849		–
Series II		3,773,585		–
Unit Appreciation Rights		525,129		345,278
Total Trust Units and Exchangeable Shares issued and outstanding and Trust Units issuablepursuant to the conversion of the Convertible Unsecured Subordinated Debentures and the Long-Term Incentive Plan		80,487,151		50,444,438

12. LONG-TERM INCENTIVE PLAN

Under the terms of the Trust Unit Incentive Plan, a maximum of 1,800,000 Trust Units are reserved for issuance pursuant to the exercise of Unit Appreciation Rights (UARs) granted to employees and directors of PrimeWest. Payouts under the plan are based on total Unitholder return, calculated using both the change in the Trust Unit price as well as cumulative distributions paid. The plan requires that a hurdle return of 5% per annum be achieved before payouts accrue. UARs have a term of up to six years and vest equally over a three-year period, except for the members of the Board, whose UARs vest immediately. The Board of Directors has the option of settling payouts under the plan in PrimeWest Trust Units or in cash. To date, all payouts under the plan have been in the form of Trust Units.

As at December 31, 2004

Year of Grant

UARs Issued and Outstanding

UARs Vested

Current Return per “In the Money” UARs

Total Equity($ Millions)

Trust Unit Dilution

1999

35,919

38.55

1.4

52,020

2000

110,985

19.42

2.2

80,979

2001

323,235

322,444

10.11

3.3

122,424

2002

825,982

585,423

7.67

6.3

160,042

2003

962,043

382,801

6.48

5.0

90,987

2004

1,445,467

163,912

2.87

1.9

18,677

Total

3,703,631

1,601,484

20.1

525,129

PrimeWest Energy Trust Annual Report 2004

As at December 31, 2003

Year of Grant	UARs Issued and Outstanding		UARs Vested		Current Return per “In the Money” UARs		Total Equity($ Millions)		Trust Unit Dilution
1998		10,391		10,391	$	49.98	$	0.5		18,844
1999		55,160		55,160		34.92		1.9		69,892
2000		120,137		119,387		16.40		2.0		71,007
2001		383,424		265,645		7.81		3.0		74,891
2002		961,405		447,562		6.09		4.7		86,694
2003		1,085,031		141,896		4.75		2.5		23,950
Total		2,615,548		1,040,041			$	14.6		345,278

Cumulative to December 31, 2004, 1,287,601 UARs have been exercised (cumulative to December 31, 2003 –1,030,850), resulting in the issuance of 835,607 Trust Units from treasury (cumulative to December 31, 2003 –719,374).

13. CASH DISTRIBUTIONS

($ millions)	2004			2003			2002
Cash flow from operations	$	266.8		$	216.6		$	170.9
Deduct amounts to reconcile to distribution:
Cash retained from cash available for distribution⁽¹⁾		(64.0	)		(15.3	)		(7.3	)
Contribution to reclamation fund		(6.7	)		(8.7	)		(4.1	)
	$	196.1		$	192.6		$	159.5
Cash distributions to Trust Unitholders	$	196.1		$	192.6		$	158.0
Cash distributions per Trust Unit	$	3.30		$	4.32		$	4.80

(1) The Board of Directors determines the cash distribution level which results in a discretionary amount of cash being retained.

14. RELATED-PARTY TRANSACTIONS

On September 26, 2002, the Trust announced the planned elimination, effective October 1, 2002, of its external management structure and all related management, acquisition and disposition fees, as well as the acquisition of the right to mandatory quarterly dividends commonly referred to as the “1% retained royalty”. The transaction was approved by the Unitholders and the holders of Exchangeable Shares on November 4, 2002 and closed November 6, 2002. The transaction resulted in the elimination of the 2.5% management fee on net production revenue, quarterly incentive payments payable in the form of Trust Units, the 1.5% acquisition fee and the 1.25% disposition fee, which resulted in payments to PrimeWest Management Inc. in 2002 totalling $5.8 million. In addition, the amount of the 1% retained royalty paid in 2002 was $1.3 million.

The internalization transaction was achieved through the purchase by PrimeWest of all of the issued and outstanding shares of PrimeWest Management Inc. for a total consideration of approximately $26.3 million comprised of a cash payment of $13.2 million and the issuance of Exchangeable Shares exchangeable, based on an agreed exchange ratio, for approximately 491,000 Trust Units and valued at approximately $13.1 million based on the closing price of the Trust Units on the TSX on September 26, 2002. The $13.2 millionthat related to the acquisition of the 1% retained royalty was capitalized; an additional $9.5 million was capitalized with an offset to future tax liability as a result of the property, plant and equipment having no tax basis. In addition, PrimeWest agreed to issue Exchangeable Shares valued at $1.5 million to certain executive officers to terminate a management incentive program of PrimeWest Management Inc. and to create a special employee retention plan for those executive officers which provides for long-term incentive bonuses in the form of Exchangeable Shares. Under the special employee retention plan, PrimeWest agreed to issue 94,340 Exchangeable Shares on each of the second, third, fourth and fifth anniversaries of the completion of the internalization transaction. In November 2004, 94,340 Exchangeable Shares were issued relating to the special employee retention plan at a value of $1.2 million. As at December 31, 2004, $0.2 million has been accrued in non-cash general and administrative expenses related to the special employee retention plan.

PrimeWest Energy Trust Annual Report 2004

15. INCOME TAXES

PrimeWest and its subsidiaries had no taxable income for 2004, 2003 and 2002 as tax pool deductions andthe royalty payable were sufficient to reduce taxable income in these entities to nil.

The future tax provision results from temporary differences between the financial statement carrying amountsof assets and liabilities and their respective tax bases.

($ millions)	2004			2003
Loss carry forwards	$	(1.4	)	$	–
Capital assets		229.2			318.9
Foreign exchange gain on long-term debt		3.7			2.1
Asset retirement obligation		(13.5	)		(2.9	)
Long-term incentive liability		(6.8	)		(4.9	)
	$	211.2		$	313.2

The provisions for income taxes varies from the amounts that would be computed by applying the combinedCanadian federal and provincial income tax rates due to the following:

($ millions)	2004			2003			2002
Net income (loss) before taxes	$	69.1		$	19.8		$	(30.9	)
Computed income tax expense (recovery) at the Canadian statutory rate of 38.87% (2003 – 40.62%; 2002 – 42.12%)		26.9			7.6			(13.0	)
Increase (decrease) resulting from:
Non-deductible Crown royalties and other payments, net of ARTC		0.3			0.3			5.7
Federal resource allowance		(8.9	)		(16.2	)		(3.5	)
Change in income tax rate		(8.6	)		(43.1	)		(4.2	)
Foreign exchange gain on long-term debt		(2.2	)		(2.4	)		–
Amounts included in Trust income and other		(45.1	)		(26.1	)		(18.2	)
Future income taxes	$	(37.6	)	$	(79.9	)	$	(33.2	)

PrimeWest Energy Trust Annual Report 2004

16. FINANCIAL INSTRUMENTS

a) Commodity Price Risk Management

PrimeWest generally sells its oil and gas under short-term market-based contracts. Derivative financial instruments, options and swaps may be used to hedge the impact of oil and gas price fluctuations. A summary of these derivative financial instruments, options and swaps in place at December 31, 2004 follows:

Crude Oil
Period	Volume (bbls/day)		Type		WTI Price (US$/bbl)
Jan – Mar 2005		500		Swap		27.25
Jan – Mar 2005		500		Swap		28.60
Jan – Mar 2005		500		Swap		30.00
Jan – Mar 2005		500		Costless Collar		28.00/34.35
Jan – Mar 2005		500		3 Way		25.00/30.00/35.50
Jan – Mar 2005		500		Costless Collar		35.00/49.80
Jan – Mar 2005		500		Costless Collar		35.00/50.00
Jan – Mar 2005		500		Costless Collar		40.00/51.50
Jan – Mar 2005		500		Costless Collar		40.00/57.60
Jan – Mar 2005		500		Costless Collar		40.00/65.80
Apr – Jun 2005		500		Swap		27.07
Apr – Jun 2005		500		Swap		28.50
Apr – Jun 2005		500		Swap		30.00
Apr – Jun 2005		500		3 Way		25.00/30.00/36.75
Apr – Jun 2005		500		Costless Collar		35.00/47.00
Apr – Jun 2005		500		Costless Collar		35.00/46.90
Apr – Jun 2005		500		Costless Collar		37.50/50.90
Apr – Jun 2005		500		Costless Collar		37.50/56.70
Apr – Jun 2005		500		Costless Collar		40.00/60.75
Jul – Sep 2005		500		Swap		27.05
Jul – Sep 2005		500		Swap		28.50
Jul – Sep 2005		500		Costless Collar		35.00/44.90
Jul – Sep 2005		500		Costless Collar		35.00/44.35
Jul – Sep 2005		500		Costless Collar		35.00/51.30
Jul – Sep 2005		500		Costless Collar		35.00/56.50
Oct – Dec 2005		500		Swap		27.18
Oct – Dec 2005		500		Costless Collar		35.00/42.80
Oct – Dec 2005		500		Costless Collar		35.00/42.40
Oct – Dec 2005		500		Costless Collar		35.00/48.05
Oct – Dec 2005		500		Costless Collar		35.00/53.25
Jan – Mar 2006		1000		Costless Collar		35.00/49.90

PrimeWest Energy Trust Annual Report 2004

Natural Gas (AECO)
Period	Volume (mmcf/day)		Type		AECO Price (Cdn$/mcf)
Nov 2004 – Mar 2005		4.7		Costless Collar		5.80/7.91
Nov 2004 – Mar 2005		4.7		Swap		6.71
Nov 2004 – Mar 2005		4.7		Costless Collar		6.33/11.87
Nov 2004 – Mar 2005		4.7		Costless Collar		6.86/11.61
Jan 2005 – Mar 2005		10.0		Costless Collar		6.33/11.18
Jan 2005 – Mar 2005		10.0		Costless Collar		6.33/10.76
Jan 2005 – Mar 2005		10.0		Costless Collar		6.33/10.55
Jan 2005 – Mar 2005		10.0		Costless Collar		6.33/12.13
Jan 2005 – Mar 2005		5.0		3 Way		5.28/6.33/10.44
Jan 2005 – Mar 2005		5.0		3 Way		5.28/6.33/10.35
Jan 2005 – Mar 2005		5.0		3 Way		5.28/6.33/12.53
Jan 2005 – Mar 2005		5.0		Costless Collar		6.33/16.40
Feb 2005 – Mar 2005		5.0		Costless Collar		6.33/10.76
Apr 2005 – Jun 2005		10.0		Costless Collar		6.33/7.75
Apr 2005 – Jun 2005		10.0		Costless Collar		6.33/7.63
Apr 2005 – Jun 2005		10.0		Costless Collar		6.33/7.49
Apr 2005 – Jun 2005		10.0		Costless Collar		6.33/7.84
Apr 2005 – Jun 2005		5.0		Costless Collar		6.33/7.85
Apr 2005 – Jun 2005		5.0		Costless Collar		6.33/6.99
Apr 2005 – Jun 2005		5.0		Costless Collar		6.33/7.09
Apr 2005 – Jun 2005		5.0		Costless Collar		6.33/7.44
Apr 2005 – Jun 2005		5.0		Costless Collar		6.33/8.56
Apr 2005 – Jun 2005		5.0		Costless Collar		6.33/8.97
Apr 2005 – Jun 2005		5.0		Costless Collar		6.33/8.33
Jul 2005 – Sep 2005		10.0		Costless Collar		6.33/7.81
Jul 2005 – Sep 2005		10.0		Costless Collar		6.33/7.66
Jul 2005 – Sep 2005		10.0		Costless Collar		6.33/7.53
Jul 2005 – Sep 2005		10.0		Costless Collar		6.33/7.86
Jul 2005 – Sep 2005		2.4		Costless Collar		6.33/7.88
Jul 2005 – Sep 2005		5.0		Costless Collar		6.33/7.50
Jul 2005 – Sep 2005		5.0		Costless Collar		6.33/7.60
Jul 2005 – Sep 2005		5.0		Costless Collar		6.33/7.79
Jul 2005 – Sep 2005		5.0		Costless Collar		6.33/9.28
Oct 2005 – Dec 2005		10.0		Costless Collar		6.33/8.97
Oct 2005 – Dec 2005		10.0		Costless Collar		6.33/8.71
Oct 2005 – Dec 2005		10.0		Costless Collar		6.33/8.60
Oct 2005 – Dec 2005		10.0		Costless Collar		6.33/8.96
Oct 2005 – Dec 2005		5.0		3 Way		5.28/6.33/9.92
Oct 2005 – Dec 2005		5.0		3 Way		5.28/6.33/9.76
Oct 2005 – Dec 2005		5.0		3 Way		5.28/6.33/10.04
Oct 2005 – Dec 2005		5.0		Costless Collar		6.33/10.90
Jan 2006 – Mar 2006		10.0		Costless Collar		6.33/10.55
Jan 2006 – Mar 2006		10.0		Costless Collar		6.33/10.22
Jan 2006 – Mar 2006		10.0		Costless Collar		6.33/9.96
Jan 2006 – Mar 2006		5.0		Costless Collar		6.33/10.42
Jan 2006 – Mar 2006		5.0		Costless Collar		6.33/13.13

PrimeWest Energy Trust Annual Report 2004

A 3-way option is like a traditional collar, except that PrimeWest has resold the put at a lower price. Utilizing the first 3-way natural gas contract on the prior table as an example, PrimeWest has sold a call at $10.44, purchased a put at $6.33, and resold the put at $5.28. Should the market price drop below $6.33, PrimeWest will receive $6.33 until the price is less than $5.28, at which time PrimeWest would then receive market price plus $1.05. However, should market prices rise above $10.44, PrimeWest would receive a maximum price of $10.44. Should the market price remain between $6.33 and $10.44, PrimeWest would receive the market price.

In 2004, the financial impact of contracts settling in the year was a decrease in sales revenues of $28.2 million(2003 – $30.5 million decrease in sales revenues; 2002 – $28.1 million increase in sales revenues).

The mark-to-market value of the hedges in place as at December 31, 2004 is a $0.2 million gain of which$9.1 million gain is attributable to natural gas and an $8.9 million loss is attributable to crude oil.

Electrical Power

Period		Power Amount (MW)			Type			Price($/MWhr)
Calendar 2005			5			Fixed Price Swap			51.65

The mark-to-market value of the hedges at December 31, 2004 is a $0.1 million loss.

b) Fair Value Of Financial Instruments

Financial instruments include cash, marketable securities, accounts receivable, accounts payable and accrued liabilities, accrued distributions to Unitholders, long-term debt and financial hedges. As at December 31, 2004, 2003 and 2002, the fair market value of the financial instruments, other than long-term debt and financial hedges, approximate their carrying value, due to the short-term maturity of these instruments. The fair value of long-term debt approximates its carrying value in all material respects, because the cost of borrowing approximates the market rate for similar borrowings.

17. COMMITMENTS AND CONTINGENCIES

a) PrimeWest has lease commitments relating to office buildings. The estimated annual minimum operating lease rental payments for the buildings, after deducting sublease income, will be $3.6 million in 2005, $3.6 million in 2006 and $3.4 million in 2007, $3.3 million in 2008 and $0.8 million in 2009.

b) As part of PrimeWest’s internalization transaction (see Note 14), PrimeWest agreed to issue 377,360 Exchangeable Shares as a special employee retention plan. One-quarter of the Exchangeable Shares (94,340) were issued to the executive officers of PrimeWest on November 6, 2004. An additional 94,340 Exchangeable Shares will be issued each on November 6, 2005, November 6, 2006 and November 6, 2007. As at December 31, 2004, $0.2 million has been accrued in non-cash general and administrative expenses related to the special employee retention plan.

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

d) PrimeWest has various pipeline transportation commitments that run through 2010. The estimated annual payments are $7.1 million in 2005, $4.1 million in 2006, $2.9 million in 2007, $0.4 million in 2008 and $0.2 million in 2009.

PrimeWest Energy Trust Annual Report 2004

e) Pursuant to the purchase of the Calpine assets, PrimeWest entered into a natural gas Purchase and Sale Agreement where the purchaser has the right to purchase natural gas in an amount based on a notional quantity of natural gas produced from certain of the Calpine Assets. The gas purchase and sale arrangement is on a firm basis for a seven-year term, based on a monthly index price, with predetermined declining quantities. As part of the arrangement, the purchase obligations will be secured by credit support acceptable to PrimeWest provided by the purchaser. The parties will share in the proceeds of sale of the natural gas subject to this purchase and sale arrangement realized between December 31, 2004 and December 31, 2006. The sale proceeds will only be shared if gas prices exceed an agreed forward-strip pricing prevailing at the time that the Purchase and Sale Agreement was executed, plus $1.00/mcf, and the maximum amount that will be paid by PrimeWest Gas under that price-sharing mechanism is $2.5 million in any calendar quarter to a maximum aggregate amount of $25 million.

18. PRIOR YEARS’ COMPARATIVE NUMBERS

Certain prior years’ comparative numbers have been restated to conform to the current year’s presentation.

19. DIFFERENCES BETWEEN CANADIAN AND UNITED STATES GENERALLY ACCEPTED ACCOUNTING PRINCIPLES

PrimeWest’s financial statements are prepared in accordance with generally accepted accounting principles (GAAP) in Canada which, in some respects, differ from those generally accepted in the United States (US). The following are those policies that result in significant measurement differences.

1. Property, Plant and Equipment

PrimeWest adopted CICA Accounting Guideline 16 (AcG-16), “Oil and Gas Accounting – Full Costs” on January 1, 2004. The new guideline modifies how the ceiling test is performed and requires that cost centres be tested for recoverability using undiscounted future cash flows from Proved reserves, which are determined by using forward indexed prices. When the carrying amount of a cost centre is not recoverable, the cost centre must be written down to its fair value. Fair value is estimated using accepted present value techniques that incorporate risks and other uncertainties when determining expected cash flows.

In accordance with the full cost method of accounting under US GAAP, the net carrying value is limited to a standardized measure of discounted future cash flows, before financing and general administrative costs. Where the amount of a ceiling test write-down under Canadian GAAP differs from the amount of a write-down under US GAAP, the charge for depreciation and depletion under US and Canadian GAAP will differ in subsequent years.

Under Canadian GAAP, depletion charges are calculated by reference to Proved reserves estimated using future prices and estimated future costs. Under US GAAP, depletion charges are calculated by reference to Proved reserves using constant prices.

2. Asset Retirement Obligation

Effective January 1, 2004, PrimeWest changed its accounting policy with respect to accounting for asset retirement obligations. CICA section 3110 requires the fair value of asset retirement obligations be recorded when they are incurred rather than merely accumulated or accrued over the useful life of the respective asset. The change in accounting policy is recorded as an adjustment to accumulated income with retroactive restatement of prior period comparatives.

PrimeWest Energy Trust Annual Report 2004

The change in accounting policy is consistent with the Trust’s adoption of the Financial Accounting Standards Board (FAS) 143 Accounting for Asset Retirement Obligations, effective January 1, 2003. The new standard requires the recognition of the liability associated with the future site reclamation costs of the long-lived assets. The liability for future retirement obligations is to be recorded in the financial statements at the time the liability is incurred.

The adoption of FAS 143 allows for the cumulative effect of the change in accounting policy to be booked as a transitional adjustment to net income with no restatement of prior period comparatives. At January 1, 2003, this resulted in an increase to the asset retirement obligation of $15.3 million, an increase to PP&E of $8.4 million in 2003, a $0.4 million decrease to net income after tax, a decrease in the site restoration provision of $6.2 million and a decrease to future tax liability of $0.3 million.

Implementation of this accounting standard did not affect the Trust’s cash flow or liquidity.

3. Marketable Securities

PrimeWest follows the cost method of accounting for the investment in marketable securities as established by the CICA. Under this accounting policy, the investment is initially recorded at cost with the corresponding distributions received in excess of earnings recorded as a reduction to the carrying amount of the investment. Under US GAAP, the marketable securities are considered held for trading and recorded on the balance sheet at fair value. The corresponding tax difference between the cost method and fair value is recorded in earnings in the current year and results in a Canadian/US GAAP difference.

Recent US Accounting Pronouncements Issued But Not ImplementedShare-Based Payment

On December 15, 2004, the FAS in the United States issued FAS Statement No. 123R “Share-Based Payment”. The standard mandates that a public entity measure the cost of equity-based service awards based on the fair value of the award at grant date. That cost will be recognized over the period during which an employee is required to provide service in exchange for the award or the requisite service period. No compensation cost is recognized for equity instruments for which employees do not render the requisite service. The public entity will initially measure the cost of the liability-based service awards based on its current fair value. The fair value of that award will be re-measured subsequently at each reporting date through the settlement date. Changes in fair value during the requisite service period will be recognized as compensation cost over that period. The Trust is currently assessing the impact of the pronouncement on the financial statements.

The following tables set out the significant differences in the consolidated financial statements usingUS GAAP.

PrimeWest Energy Trust Annual Report 2004

a) Consolidated Net Income

($ millions, except per Trust Unit amounts)	2004			2003			2002
Net income/(loss) as reported	$	103.4		$	95.9		$	(0.6	)
Adjustments
Depletion and depreciation		(4.2	)		35.4			67.3
FAS 115 adjustment		22.6			–			–
FAS 133 adjustment		5.4			6.1			(55.8	)
Accretion of asset retirement obligation		–			–			0.9
Future income tax expense		(4.3	)		(42.3	)		(1.4	)
Adjusted net income before change in accounting policy		122.9			95.1			10.4
Cumulative effect of change in accounting policy, net of tax of $0.3 million		–			(0.4	)		–
Adjusted net income	$	122.9		$	94.7		$	10.4
Net income per Trust Unit
US GAAP – Basic	$	2.07		$	2.01		$	0.30
– Diluted	$	2.05		$	1.99		$	0.30
Cumulative effect of change in accounting policy per Trust Unit
US GAAP – Basic		–		$	0.01			–
– Diluted		–		$	0.01			–

b) Pro Forma Consolidated Net Income

US GAAP requires the cumulative impact of a change in accounting policy to be presented in the current year’s consolidated statement of income with no restatement of the comparative prior periods. The following table illustrates the pro forma impact on the Trust’s 2002 net income under US GAAP had the prior period been restated.

($ millions, except per Trust Unit amounts)	2002
Net income
As reported	$	10.4
As restated	$	11.2
Net income per Trust Unit (Basic)
As reported	$	0.30
As restated	$	0.33
Net income per Trust Unit (Diluted)
As reported	$	0.30
As restated	$	0.32

Asset retirement obligation at January 1, 2002	$	11.8

c) Consolidated Unitholders’ Equity

($ millions)		2004			2003
Unitholders’ equity as reported	$	1,194.9		$	1,025.2
Adjustments
Depletion and depreciation		(270.3	)		(493.6	)
FAS 115 adjustment		22.6			–
FAS 133 adjustment		–			(5.4	)
Future income tax recovery		119.2			127.0
	$	1,066.4		$	653.2

PrimeWest Energy Trust Annual Report 2004

d) Consolidated Balance Sheets

	2004					2003
($ millions)	Cdn GAAP		US GAAP			Cdn GAAP		US GAAP
Property, plant and equipment (net)	$	1,908.6	$	1,699.4		$	1,548.2	$	1,042.1
Marketable securities	$	68.6	$	91.2			–		–
Derivative liability	$	0.5	$	0.5			–	$	5.4
Future income tax liability	$	211.2	$	153.2		$	313.2	$	183.0
Accumulated income/(deficit)	$	89.2	$	(39.3	)	$	219.1	$	(162.2	)

e) Consolidated Cash Flows

The consolidated statements of cash flows prepared in accordance with Canadian GAAP conform in all material respects with US GAAP, except that Canadian GAAP allows for the presentation of operating cash flow before changes in non-cash working capital items in the consolidated statement of cash flows. This total cannot be presented under US GAAP.

FAS 69 Supplemental Reserve Information (Unaudited)

The following data supplements oil and gas disclosure in the Trust’s annual report, and is provided inaccordance with the provisions of FAS 69.

Oil and Gas Reserves

Users of this information should be aware that the process of estimating quantities of “Proved” and “Proved developed” crude oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of the numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions to existing reserve estimates occur from time-to-time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the significance of the subjective decisions required and variances in available data for various reservoirs make these estimates generally less precise than other estimates presented in connection with financial statement disclosures.

Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.

Proved developed oil and gas reserves are reserves that can be expected to be recovered through existingwells with existing equipment and operating methods.

Canadian provincial royalties are determined based on a graduated percentage scale which varies with prices and production volumes. Canadian reserves, as presented on a net basis, assume prices and royalty rates in existence at the time the estimates were made, and the Trust’s estimate of future production volumes. Future fluctuations in prices, production rates, or changes in political or regulatory environments could cause the Trust’s share of future production from Canadian reserves to be materially different from that presented.

PrimeWest Energy Trust Annual Report 2004

Subsequent to December 31, 2004, no major discovery or other favourable or adverse event is believed tohave caused a material change in the estimates of Proved or Proved developed reserves as of that date.

Results of Oil and Gas Operations($ millions)	2004			2003			2002
Revenues	$	394.6		$	329.9		$	264.3
Expenses
Production costs		88.9			79.4			60.8
Depreciation, depletion and amortization		201.5			170.3			113.5
Accretion		2.0			1.2			–
Tax recovery		(30.0	)		(39.9	)		(26.0	)
		262.4			211.0			148.3
Results of operations from oil and gas operations	$	132.2		$	118.9		$	116.0

Costs Incurred($ millions)		2004			2003			2002
Property acquisition costs
Proved properties	$	770.5		$	202.4		$	57.7
Unproved properties		52.1			34.0			5.7
Exploration costs		16.0			5.7			1.8
Development costs		123.6			101.5			56.8
	$	962.2		$	343.6		$	122.0

Acquisition costs include costs incurred to purchase, lease, or otherwise acquire oil and gas properties.

Development costs include the costs of drilling and equipping development wells and facilities to extract,treat and gather and store oil and gas, along with an allocation of overhead.

There were no oil and gas property costs not being amortized in any of the years presented.

Capitalized Costs($ millions)	2004			2003			2002
Proved properties	$	2,599.1		$	2,189.0		$	1,838.8
Unproved properties		103.9			36.0			44.2
		2,703.0			2,225.0			1,883.0
Less related accumulated depreciation,depletion and amortization		(1,010.0	)		(1,186.2	)		(1,011.6	)
	$	1,693.0		$	1,038.8		$	871.4

Proved Oil and Gas Reserve Quantities
	2004			2004			2003			2003			2002			2002
	Crude Oil and Natural Gas Liquids			Natural Gas			Crude Oil and Natural Gas Liquids			NaturalGas			Crude Oil and Natural Gas Liquids			NaturalGas
	(mbbls)			(mmcf)			(mbbls)			(mmcf)			(mbbls)			(mmcf)
Opening balance		25,643			272,897			25,989			279,106			26,657			267,371
Revision of previous estimates		(806	)		2,640			225			(33,640	)		1,737			5,700
Purchase of reserves in place		6,940			180,914			1,640			50,389			954			18,929
Sale of reserves in place		(2,120	)		(8,027	)		(28	)		(803	)		(568	)		(5,328	)
Discoveries and extensions		791			16,018			941			14,742			736			25,337
Production		(2,649	)		(42,215	)		(3,124	)		(36,897	)		(3,527	)		(32,903	)
Closing Balance		27,799			422,227			25,643			272,897			25,989			279,106

PrimeWest Energy Trust Annual Report 2004

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves

The standardized measure for calculating the present value of future net cash flows from Proved oil and gasreserves is based on current costs and prices and a 10% discount factor as prescribed by FAS 69.

Accordingly, the estimated future net cash inflows were computed by applying prevailing selling prices at year end to the estimated future production of Proved reserves. Estimated future expenditures are based on future development costs.

Although these calculations have been prepared according to the standards described above, it should be emphasized that, due to the number of assumptions and estimates required in the calculation, the amounts are not indicative of the amount of net revenue that the Trust expects to receive in future years. They are also not indicative of the current value or future earnings that may be realized from the production of Proved reserves, nor should it be assumed that they represent the fair market value of the reserves or of the oil and gas properties.

Although the calculations are based on existing economic conditions at each year end, such economic conditions have changed and may continue to change significantly due to events such as the continuing changes in the natural gas market and changes in government policies and regulations. While the calculations are based on the Trust’s understanding of the established FASB guidelines, there are numerous other equally valid assumptions under which these estimates could be made that would produce significantly different results.

Standardized Measure($ millions)	2004			2003			2002
Future cash inflows	$	4,187.1		$	2,631.1		$	2,890.5
Future production costs		(1,186.6	)		(804.9	)		(699.0	)
Future development costs		(72.0	)		(69.4	)		(73.4	)
Other related future costs		(37.1	)		(42.1	)		(43.4	)
Future net cash flows		2,891.4			1,714.7			2,074.7
Discount at 10%		(1,242.7	)		(721.6	)		(919.4	)
Standardized measure of discounted future net cash flow related to Proved reserves	$	1,648.7		$	993.1		$	1,155.3

Summary of Changes in the Standardized Measure During the Year($ millions)	2004			2003			2002
Sales of oil and gas produced, net of production costs	$	(312.2	)	$	(255.0	)	$	(203.5	)
Net change in sales and transfer prices, net of development and production costs		144.4			(106.2	)		672.6
Sales of reserves in place		(54.4	)		(2.3	)		(4.5	)
Purchases of reserves in place		630.4			156.4			45.6
Extensions, discoveries and improved recovery, less related costs		106.7			48.5			52.3
Changes in timing of future net cash flows and other		37.1			(60.6	)		(93.6	)
Revisions of previous quantity estimates		4.3			(58.5	)		28.3
Accretion of discount		99.3			115.5			59.8
Net change		655.6			(162.2	)		557.0
Balance at beginning of year		993.1			1,155.3			598.3
Balance at end of year	$	1,648.7		$	993.1		$	1,155.3

PrimeWest Energy Trust Annual Report 2004

Trading Performance
For the quarter ended	Dec 31/04		Sep 30/04		Jun 30/04		Mar 31/04		Dec 31/03
TSX Trust Unit prices (Cdn$ per Trust Unit)
High	$	28.33	$	26.70	$	26.80	$	28.35	$	27.34
Low	$	25.06	$	23.29	$	22.18	$	22.70	$	24.48
Close	$	26.62	$	26.70	$	23.25	$	26.65	$	24.51
Average daily traded volume		255,944		259,219		187,767		256,922		184,428

For the quarter ended	Dec 31/04		Sep 30/04		Jun 30/04		Mar 31/04		Dec 31/03
NYSE Trust Unit prices (US$ per Trust Unit)
High	$	22.98	$	21.16	$	20.44	$	22.14	$	21.48
Low	$	20.85	$	17.65	$	16.00	$	17.31	$	18.67
Close	$	22.18	$	21.16	$	17.43	$	20.31	$	21.27
Average daily traded volume		542,483		329,862		279,882		469,694		243,921
Number of Trust Units outstanding including Exchangeable Shares (millions of units)		70.5		69.7		56.8		50.87		50.10
Distribution paid per Trust Unit	$	0.90	$	0.83	$	0.75	$	0.82	$	0.96

Total Compound Annual Return (%)⁽¹⁾
	PrimeWest			TSX Oil and Gas Index			TSX S&P			S&P 500 Cdn			S&P 500$US			S&P/TSX Cdn Energy $Trust Index

Five year		21.5	%		23.4	%		3.6	%		(5.9	)%		(2.3	)%		13.4	%
Three year		18.5	%		24.9	%		7.7	%		(6.5	)%		2.9	%		15.7	%
One year		9.7	%		40.5	%		14.4	%		2.8	%		10.8	%		29.6	%

PrimeWest Energy Trust Annual Report 2004

Supplemental Information

FIVE-YEAR FINANCIAL SUMMARY

($ millions, except per BOE and per Trust Unit amounts)	2004			2003(restated)			2002(restated)			2001(restated)			2000(restated)
Cash flow from operations	$	266.8		$	216.6		$	170.9		$	214.5		$	112.1
Per Trust Unit		4.33			4.67			4.96			8.27			9.82
Per BOE		20.49			17.82			15.51			19.74			18.91
Net revenues		394.6			329.9			264.3			306.5			156.6
Per Trust Unit		6.25			7.12			7.67			11.81			13.72
per BOE		30.30			27.14			23.98			28.20			26.42
Operating expenses		88.9			79.4			60.8			59.0			30.2
Per Trust Unit		1.41			1.71			1.76			2.27			2.65
Per BOE		6.83			6.53			5.52			5.42			5.09
Operating margin		305.6			250.5			203.5			247.6			126.4
Per Trust Unit		4.84			5.41			5.90			9.54			11.08
Per BOE		23.47			20.61			18.46			22.78			21.33
Cash general and administrative expenses		19.0			14.5			11.3			10.4			4.1
Per Trust Unit		0.30			0.31			0.33			0.40			0.36
Per BOE		1.46			1.20			1.02			0.96			0.70
Interest expense		20.6			15.1			10.8			13.8			6.4
Per Trust Unit		0.33			0.32			0.32			0.53			0.56
Per BOE		1.58			1.24			0.98			1.27			1.07
Capital expenditures		125.1			104.5			64.2			83.9			25.8
Acquisitions net of dispositions		707.9			228.6			56.5			744.5			117.8
Working capital (deficit)		104.3			(5.8	)		(0.7	)		(29.4	)		(0.3	)
Total assets		2,240.9			1,690.5			1,511.5			1,530.0			445.0
Net asset value⁽¹⁾		1,541.2			692.4			727.9			755.2			560.4
Per Trust Unit(diluted)⁽¹⁾		19.15			13.74			18.52			22.82			42.14
Total capitalization (including debt)		2,429.7			1,636.6			1,072.5			1,080.7			377.2
Debt Analysis
Long-term debt, including working capital		552.0			255.9			225.7			224.4			78.8
Debt to annual cash flow ratio		1.70			1.18			1.32			1.05			0.71
Debt to equity ratio		31.6			25.1			26.6			26.2			26.6
Interest coverage ratio		14.2			15.9			16.9			16.5			18.6
Average cost of debt		4.8	%		4.7	%		4.6	%		5.4	%		7.4	%
Net debt per Trust Unit		7.77			5.07			5.75			6.78			5.93
Tax Pools (Consolidated)
Canadian oil and gas property expense (COGPE)		879.0			426.0			425.0			424.0			299.0
Canadian exploration expense (CEE)		79.8			61.5			–			23.7			5.7
Canadian development expense (CDE)		109.5			60.9			41.2			11.1			9.0
Capital cost allowance (CCA)		281.8			126.0			108.0			101.2			35.8
Losses available for carry forward		3.6			–			11.8			24.8			–
Unit issue expenses		37.5			17.3			12.5			12.2			6.2

(1) 2004 is based on Consultants’ Average Pricing as at December 31, 2004.

PrimeWest Energy Trust Annual Report 2004

FIVE-YEAR OPERATING SUMMARY

	2004			2003			2002			2001			2000
Average Daily Production
Natural gas (mmcf/day)		145.1			134.1			113.5			104.8			49.0
Crude oil (bbls/day)		8,282			8,116			9,239			10,033			6,582
Natural gas liquids (bbls/day)		3,107			2,855			2,030			2,273			1,483
Total (BOE/day)		35,578			33,316			30,189			29,774			16,237
Average Selling Prices (Cdn$)
Natural gas ($/mcf)	$	6.61		$	6.05		$	4.55		$	6.16		$	4.65
Crude oil ($/bbl)		36.83			33.94			33.53			32.21			36.67
Natural gas liquids ($/bbl)		43.69			35.34			26.56			30.96			34.42
Total ($/BOE)	$	39.35		$	35.63		$	29.16		$	34.80		$	32.19
Benchmark Prices
Monthly AECO Spot (Cdn$/mcf)	$	6.79		$	6.70		$	4.07		$	6.30		$	5.02
WTI (US$/bbl)	$	41.40		$	31.04		$	26.08		$	25.97		$	30.20
Operating Margin ($/BOE)
Revenues	$	39.50		$	35.52		$	29.11		$	34.93		$	32.28
Royalties		(9.20	)		(8.38	)		(5.13	)		(6.73	)		(5.92	)
Operating expenses		(6.83	)		(6.53	)		(5.52	)		(5.42	)		(5.09	)
Operating margin ($/BOE)	$	23.47		$	20.61		$	18.46		$	22.78		$	21.27
Reserves Summary^{(1, 2)}
Crude oil (mmbbls)		23.9			22.9			24.5			28.5			24.4
Natural gas liquids (mmbbls)		18.3			11.9			10.2			9.5			6.4
Natural gas (Bcf)		677.9			432.2			418.5			413.7			232.7
Total (mmBOE)		155.2			106.8			104.4			107.0			69.6
Net Asset Value
($millions, except per Trust Unit amounts)
Reserves (10% discount)⁽³⁾	$	1,714.4⁽⁴	⁾	$	904.6		$	923.0		$	872.6		$	623.0
Market value of Calpine Trust Units		91.0			–			–			–			–
Hedging mark-to-market		0.1			(0.5	)		(13.6	)		50.5			(1.0	)
Unproved lands and reclamation fund		114.2			44.2			44.2			56.5			17.2
Long-term debt and working capital deficiency		(378.5	)		(255.9	)		(225.7	)		(224.4	)		(78.8	)
Total net asset value	$	1,541.2		$	692.4		$	727.9		$	755.2		$	560.4
Per Trust Unit (diluted)	$	19.15		$	13.74		$	18.52		$	22.82		$	42.14

Reserve Life Index⁽²⁾(years)		10.3			9.8			9.5			10.0			10.2

(1)	Company Interest reserves.
(2)	Total Proved plus Probable used for 2004 and 2003, all prior years used Established.
(3)	Company Interest Proved plus Probable reserves.
(4)	Based on December 31, 2004 Consultants’ Average Pricing.

PrimeWest Energy Trust Annual Report 2004

FIVE-YEAR TRADING, PERFORMANCE AND DISTRIBUTION SUMMARY

	2004
	Q1			Q2			Q3			Q4			Full Year			2003			2002			2001			2000
Units Issued and Outstanding
Period end (000s)		50,223			56,218			69,077			69,886			69,886			48,752			37,005			31,492			12,746
Exchangeables Issuedand Outstanding
Period end (000s)		1,407			1,320			1,315			1,294			1,294			3,041			5,179			4,068			1,112
Converted to Trust Units		646			625			641			652			652			1,347			1,940			1,294			304
Exchange ratio at period end		0.45885			0.4731			0.48773			0.50408			0.50408			0.44302			0.37454			0.31799			0.27333
TSX Unit Price (Cdn$)
High	$	28.35		$	26.80		$	26.70		$	28.33		$	28.35		$	28.15		$	29.56		$	42.16		$	37.20
Low	$	22.70		$	22.18		$	23.29		$	25.06		$	22.18		$	23.40		$	23.60		$	23.80		$	25.20
Close	$	26.65		$	23.25		$	26.70		$	26.62		$	26.62		$	27.56		$	25.40		$	25.44		$	35.80
Average daily volume traded		256,922			187,767			254,219			255,944			233,579			192,678			123,455			156,122			30,314
Market capitalization atend of period (Cdn$ millions)		1,338			1,307			1,844			1,878			1,878			1,381			989			834			467
Total return for Canadian
Unitholders during period		-0.2	%		-10.0	%		18.6	%		3.0	%		9.7	%		28.0	%		19.5	%		-5.8	%		75.7	%
NYSE Unit Price (US$)
High	$	22.14		$	20.44		$	21.16		$	22.98		$	22.98		$	21.48		$	16.69
Low	$	17.31		$	16.00		$	17.65		$	20.85		$	16.00		$	15.97		$	15.62
Close	$	20.31		$	17.43		$	21.16		$	22.18		$	22.18		$	21.27		$	16.16
Average daily volume traded		469,694			279,882			329,862			542,483			402,694			169,269			39,276
Total return for US Unitholdersduring period		-1.4	%		-11.5	%		25.4	%		8.3	%		18.5	%		55.3	%
Distribution Summary (Cdn$ millions, except per Trust Unit amounts)

Cash distributed to Unitholders	$	41.10		$	42.00		$	50.40		$	62.60		$	196.10		$	192.60		$	158.00		$	234.40		$	79.00
Per Trust Unit	$	0.82		$	0.75		$	0.83		$	0.90		$	3.30		$	4.32		$	4.80		$	9.24		$	7.08
Percentage paid out		70	%		72	%		74	%		76	%		74	%		89	%		92	%		109	%		70	%
Cumulative cash distributions		812.6			854.6			905			967.7			967.7			771.5			578.9			420.9			186.5
Per Trust Unit	$	41.06		$	41.81		$	42.64		$	43.54		$	43.54		$	40.24		$	35.92		$	31.12		$	21.88

Distribution History ($ per Trust Unit)

	2004						2003					2002							2001					2000
Funds paid in:	Cdn$			$US			Cdn$			$US			Cdn$			$US			Cdn$			$US		Cdn$			$US
Q1	$	0.82		$	0.62		$	1.20		$	0.81		$	1.20		$	0.75		$	2.40		$	1.56	$	1.20		$	0.82
Q2		0.75			0.55			1.2			0.87			1.2			0.77			2.56			1.66		1.32			0.89
Q3		0.83			0.64			0.96			0.7			1.2			0.77			2.64			1.71		1.92			1.29
Q4		0.9			0.74			0.96			0.73			1.2			0.76			2.04			1.31		2.24			1.46
Total for year	$	3.30		$	2.55		$	4.32		$	3.12		$	4.80		$	3.05		$	9.64		$	6.24	$	6.68		$	4.46
% tax deferred		45	%		55	%		42	%		100	%		45	%		100	%		33	%		N/A		47	%		N/A
Exchange rate(US$/Cdn$)	$	0.769	*				$	0.72					$	0.64					$	0.65				$	0.67

* Average exchange rate during 2004. Some numbers may not add due to rounding.

PrimeWest Energy Trust Annual Report 2004

THREE-YEAR DISTRIBUTION HISTORY

	Distribution		Distribution
	Per Unit⁽¹⁾		Per Unit⁽¹⁾
2002	Cdn		$ US$
January		0.40		0.25
February		0.40		0.25
March		0.40		0.25
April		0.40		0.26
May		0.40		0.26
June		0.40		0.26
July		0.40		0.26
August		0.40		0.25
September		0.40		0.25
October		0.40		0.25
November		0.40		0.26
December		0.40		0.26
Total 2002		4.80		3.06

2003
January		0.40		0.26
February		0.40		0.27
March		0.40		0.28
April		0.40		0.289
May		0.40		0.299
June		0.40		0.287
July		0.32		0.23
August		0.32		0.23
September		0.32		0.24
October		0.32		0.246
November		0.32		0.24
December		0.32		0.2465
Total 2003		4.32		3.118

2004
January		0.32		0.2431
February		0.25		0.1870
March		0.25		0.1860
April		0.25		0.1798
May		0.25		0.183
June		0.25		0.1887
July		0.25		0.1910
August		0.275		0.2120
September		0.30		0.2395
October		0.30		0.2499
November		0.30		0.2450
December		0.30		0.2468
Total 2004		3.295		2.552

(1)	Monthly information refers to the month in which the record date for the relevant distribution occurs with payment being paid on the 15th of the following month.

PrimeWest Energy Trust Annual Report 2004

Income Tax Considerations

This commentary regarding income taxes is of a general nature only and is not intended to be legal or tax advice applicable to a specific Unitholder. Unitholders and prospective investors are, therefore, encouraged to consult a tax advisor with regard to their specific circumstances.

For Canadian Unitholders

PrimeWest is regarded as a mutual fund trust for purposes of the Canadian Income Tax Act. Each year, an income tax return is filed by the Trust with the taxable income allocated to, and taxable in the hands of Unitholders. Distributions paid by the Trust have two components: (1) a tax-deferred return of capital (i.e. a repayment of a portion of a Unitholders’ investment) and (2) a taxable return on capital (i.e. other income).

Each year, the return on capital or taxable portion of the distribution is reported on the Trust’s T3 return. It is then allocated to each Unitholder who received distributions in the taxation year on the T3 supplementary forms, which are mailed in late February or early March of the following calendar year. Registered Unitholders receive a T3 from the Trust’s transfer agent, Computershare Trust Company of Canada, while Unitholders who hold their units beneficially will receive a T3 from their bank or brokerage firm. The T3 form will indicate only the currently taxable portion, or other income, as it is regarded under Canadian tax law in box 26. This other income component is taxed on the same basis as interest income. The tax-deferred return of capital portion of the distribution should be treated as an adjustment to cost base (ACB) of the Units. On disposition, the cost base should be reduced by the accumulated value of returned capital, resulting in a capital gain or loss for tax purposes.

For 2004, 45% of the distributions paid to Canadian residents were deemed a tax-deferred return of capital, and 55% was deemed taxable as other income. For tax year 2005, PrimeWest’s distributions payable to Canadian residents are estimated to be 55% taxable and 45% a tax-deferred return of capital.

For American and Other Non-Resident Unitholders

Investors who do not qualify as residents of Canada for income tax purposes should seek advice from a qualified tax advisor in their country of residence regarding the tax treatment of the distributions paid by PrimeWest. Monthly distributions payable to non-residents of Canada are normally subject to a withholding tax of 25% as prescribed by the Canadian Income Tax Act. However, the level of withholding tax may be reduced in accordance with reciprocal tax treaties.

In the case of the Canada–United States Tax Convention, US residents are subject to a 15% withholding tax on the distributions paid by PrimeWest. For distributions paid during tax years 2004 and prior, the 15% withholding tax is refundable for that portion of the distributions deemed to be a tax-deferred return of capital. US residents may apply to the Canada Revenue Agency (CRA) of the Government of Canada for this refund no later than two years after the calendar year in which the distributions were paid. Application for refund may be made by filing CRA Form NR7-R “Application for Refund of Non-Resident Tax”, which can be obtained by contacting the International Tax Services Office of the CRA at 1-800-267-5177 or on the internet at www.cra.gc.ca. US investors are cautioned that the administrative protocol required to apply for the refund is burdensome, and they will require the assistance of their broker or tax advisor.

PrimeWest Energy Trust Annual Report 2004

Alternatively, US Unitholders may elect to claim Canadian tax withheld on distributions paid during 2004 as a deduction against income or, subject to certain restrictions, as a credit against their US tax liability. US Unitholders wishing to claim a foreign tax credit must complete IRS Form 1116, “Foreign Tax Credit”, as an attachment to the Form 1040.

In the case of a US Unitholder, the taxable portion of the monthly distribution is determined based upon current and accumulated earnings in accordance with the IRS tax code. The currently taxable portion is regarded as a foreign issuer “qualified dividend” under the terms of the Jobs and Growth Reconciliation Act of 2003 (P.L. 108-27, 117 Stat.752) for tax reporting purposes and registered US Unitholders should receive a CRA Form NR-4 from the Trust’s transfer agent, Computershare Trust Company of Canada. US Unitholders who hold their units beneficially should receive an IRS Form 1099-DIV or similar document from their bank or brokerage firm.

The tax-deferred return of capital portion of the distribution should be treated as an adjustment to the cost base (ACB) of the Units. The original cost of the Units should be reduced by this accumulated amount when computing gains or losses at the time of disposition, at which time this should be reported as a capital gain or loss.

Due to differences in the income tax code of the United States, certain deductions not available in Canada are available in the United States and could result in differences in tax treatment of the distributions for US Unitholders compared to those in Canada. For Unitholders resident in the United States, the taxability of distributions is derived using US tax rules, which permit the deduction of Crown royalties and accounting-based depletion. As a result, in the case of a US resident, 45% of the distributions paid by PrimeWest during 2004 should be treated as a “qualified dividend” with the remaining 55% treated as a tax-deferred return of capital.

On December 6, 2004, the Government of Canada announced significant changes to the non-resident withholding tax provisions effective January 1, 2005. Commencing with the 2005 tax year, the gross amount of the distributions payable to US residents will be subject to a non-refundable withholding tax of 15%, applicable to Units held in both taxable and tax-exempt accounts. Similarly, non-residents of countries with whom there is no reciprocal tax treaty with Canada will be subject to a non-refundable withholding tax of 25%, applicable to Units held in both taxable and tax-exempt accounts. Non-resident Unitholders are strongly advised to consult a resident tax advisor to determine the deductibility of these withholding taxes in their resident jurisdictions.

PrimeWest Energy Trust Annual Report 2004

Premium Distribution, Distribution Reinvestment, and Optional Trust Unit Purchase Plan

PrimeWest offers a number of attractive and economical options for Canadian Unitholders to maximize their investment, including a Premium Distribution (PREP), Distribution Reinvestment (DRIP) and Optional Trust Unit Purchase Plan (OTUPP). Investors are able to participate in all of these plans without paying fees, including brokerage commissions.

The PREP enables Canadian Unitholders to receive a 2% cash premium on the monthly distribution they receive. The more conventional DRIP allows eligible Canadian Unitholders to reinvest distribution payments into PrimeWest Units, acquired at a 5% discount to the volume weighted average market price.

Additional Trust Units may be purchased by eligible Canadian Unitholders through the OTUPP in minimum amounts of $100 per remittance up to a maximum amount of $100,000 per calendar year, at a 5% discount to the volume weighted average market price. The number of units available under the OTUPP is limited by the Toronto Stock Exchange (TSX) to a maximum of 2% of the total Trust Units outstanding at the end of the previous fiscal year.

Most larger banks, trust companies and brokerage firms will allow investors to participate in these programs, but many of the smaller firms do not. Please contact the bank, trust company or brokerage firm which holds your account to determine if they permit participation in these plans. If you are unable to participate as a beneficial holder, you will need to hold the Units directly as a registered Unitholder or transfer the Units to a financial institution that permits participation.

If you are a registered Canadian Unitholder, we invite you to participate in these programs by completing the enrolment form on the PrimeWest Energy website at www.primewestenergy.com. If you hold your Units with a bank or brokerage firm, you will need to inform the firm directly of your interest in enrolling in the program. Additional information regarding the PREP, DRIP and OTUPP can be obtained by contacting the Computershare Trust Company of Canada (Plan Agent) toll-free at 1-800-564-6253, or the Investor Relations group at PrimeWest Energy toll-free at 1-877-968-7878, or via e-mail at investor@primewestenergy.com.

PrimeWest Energy Trust Annual Report 2004

Abbreviations

ARTC	Alberta Royalty Tax Credit	mmBOE	millions of barrels of oil equivalent
bbls	barrels	mmbtu	million British thermal unit
mbbls	thousand barrels	Tcf	trillion cubic feet
mmbbls	million barrels
bbls/day	barrels per day	CONVERSION FACTORS:
mcf	thousand cubic feet	1 cubic metre (liquids) = 6.29 barrels
mmcf	million cubic feet	1 cubic metre (natural gas) = 35.49 cubic feet
mcf/day	thousand cubic feet per day	1 litre = 0.22 imperial gallon
Bcf	billion cubic feet	1 hectare = 2.47 acres
BOE	barrel of oil equivalent	1 cubic metre = 1,000 litres
MWhr	mega watt hour	1 mcf of natural gas = 1.055 gigajoules of
BOE/day	barrel of oil equivalent per day	natural gas = 1 mmbtu

Definitions

AECO

Refers to a pricing point for gas produced in Western Canada located at a gas storage facility adjacent to the TransCanada PipeLine’s mainline near the Alberta-Saskatchewan border.

BARREL OF OIL EQUIVALENT (BOE)

Natural gas production is converted using six thousand cubic feet of gas for one barrel of oil, with this number added to the actual number of barrels of crude oil and natural gas liquids on an average day to derive the barrels of oil equivalent produced per day. BOEs may be misleading, particularly if used in isolation. The BOE conversion ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

CASH DISTRIBUTION DATE

The date Distributable Income is paid to Unitholders, currently being the 15th of each month, or the earlier business day if applicable, following any record date.

COMPANY INTEREST

Refers 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.

DECLARATION OF TRUST

Refers to the declaration of trust dated August 2, 1996 among the Trustee, PrimeWest, and the Initial Unitholder (as therein defined), as amended from time-to-time and administered.

FORECAST PRICES AND COSTS

Refers to future prices and costs that are generally accepted as being a reasonable outlook for the future; or 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.

GENERAL AND ADMINISTRATIVE COSTS

Is the amount in aggregate representing all expenditures and costs incurred by PrimeWest, in the management and administration of PrimeWest.

GROSS

Refers to the “company gross reserves”, which are PrimeWest’s working interest (operated or non-operated) share before deduction of royalties and without including any royalty interests of PrimeWest or the Trust; orin 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.

PrimeWest Energy Trust Annual Report 2004

100

NET

Refers 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 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.

PROBABLE RESERVES

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.

PROVED RESERVES

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

The date by which a Unitholder must officially own the Trust Units in order to be entitled to receive a distribution.

RESERVE LIFE INDEX

Is calculated by dividing the quantity of reserves by the total production of oil, natural gas, and natural gas liquids during the year.

TRUST UNITS

Refers to the Units of the Trust, each Unit representing an equal undivided beneficial interest in the Trust.

TRUSTEE

Refers to Computershare Trust Company of Canada, or its successor as trustee of the Trust.

UNDEVELOPED RESERVES

Refers to 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

Refers to a property or part of a property to which no reserves have been specifically attributed.

WELL ABANDONMENT COSTS

The 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.

WEST TEXAS INTERMEDIATE (WTI)

A high-quality grade of crude oil produced in West Texas whose price is most commonly used as a benchmark for crude oil pricing internationally.

See PrimeWest’s Renewal Annual Information Form for an explanation of additional defined terms used in this annual report.

PrimeWest Energy Trust Annual Report 2004

101

PrimeWest 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.

Notes:

(1)	The Trust also directly owns certain gross overriding royalty interests.
(2)	PrimeWest, directly and indirectly through its subsidiaries, including PrimeWest Gas, actively manages its oil and natural gas properties to maximize cash flow and reserve value.

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 and PrimeWest Gas 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.

PrimeWest Energy Trust Annual Report 2004

102

Positive
Negative
Uncertain
Constraining
Legalese
Litigious
Readability	7th grade Avg

“Signed”

“Signed”

Harold P. Milavsky

Don Garner

Chair of the Board of Directors

President and Chief Executive Officer