Primewest Energy Trust (PWI) 40-F 2006 FY Annual report (Canada)

PRIMEWEST ENERGY TRUSTANNUAL REPORT 2005–MANAGEMENT’S DISCUSSION AND 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. and PrimeWest Gas Corp. 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 Consolidated Financial Statements. Where estimates are used in the preparation of these Consolidated 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 Consolidated 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 its opinion on the Consolidated Financial Statements. The auditors have full and unrestricted access to the Audit and Finance Committee to discuss their findings.

Signed “Don Garner”

Signed “Dennis Feuchuk”

Don Garner

Dennis Feuchuk

President and Chief Executive Officer

Vice-President, Finance and Chief Financial Officer

February 23, 2006

MANAGEMENT’S DISCUSSION AND ANALYSIS–PRIMEWEST ENERGY TRUSTANNUAL REPORT 2005

AUDITORS’ REPORT

TO THE UNITHOLDERS OF PRIMEWEST ENERGY TRUST:

We have audited the Consolidated Balance Sheets of PrimeWest Energy Trust as at December 31, 2005 and 2004, and the Consolidated Statements of Income, Changes in Unitholders’ Equity and Cash Flows for each of the years in the three-year period ended December 31, 2005. These financial statements are the responsibility of the management of PrimeWest. 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, 2005 and 2004, and the results of its operations and cash flows for each of the years in the three-year period ended December 31, 2005, in accordance with Canadian Generally Accepted Accounting Principles.

Signed “PricewaterhouseCoopers LLP”

PricewaterhouseCoopers LLP

Chartered Accountants

Calgary, Alberta

February 10, 2006

COMMENTS BY AUDITORS FOR U.S. READERS ON CANADA – U.S. REPORTING DIFFERENCES

In the United States, reporting standards for auditors require the addition of an explanatory paragraph (following the opinion paragraph) when there is a change in accounting principles that has a material effect on the comparability of the Trust’s financial statements, such as the change described in notes 3 and 20 to the consolidated financial statements. Our report to the Unitholders dated February 10, 2006 is expressed in accordance with Canadian reporting standards, which do not require a reference to such a change in accounting principles in the Auditors’ Report when the change is properly accounted for and adequately disclosed in the financial statements.

Signed “PricewaterhouseCoopers LLP”

PricewaterhouseCoopers LLP

Chartered Accountants

Calgary, Alberta

February 10, 2006

PRIMEWEST ENERGY TRUSTANNUAL REPORT 2005–MANAGEMENT’S DISCUSSION AND ANALYSIS

CONSOLIDATED BALANCE SHEETS

As at December 31 ($ millions)	2005		2004 (restated – see note 3)
ASSETS
Current assets
Cash and cash equivalents	$	36.8	$	54.4
Marketable securities (note 4)		-		68.6
Accounts receivable		125.0		96.9
Assets held for sale (note 6)		-		5.4
Future income taxes (note 16)		3.9		-
Prepaid expenses		16.3		10.9
Inventory		3.5		5.8
		185.5		242.0
Cash reserved for site restoration and reclamation (note 10)		9.2		10.3
Other assets and deferred charges (note 7)		8.8		10.9
Derivative asset		-		0.6
Property, plant and equipment (note 6)		1,859.9		1,908.6
Goodwill		68.5		68.5
	$	2,131.9	$	2,240.9
LIABILITIES AND UNITHOLDERS’ EQUITY
Current liabilities
Accounts payable	$	50.2	$	47.7
Accrued liabilities		75.9		72.3
Derivative liability (note 17)		11.3		0.5
Accrued distributions to Unitholders		25.0		17.7
		162.4		138.2
Long-term debt (note 8)		354.2		656.3
Derivative liability (note 17)		0.2		-
Future income taxes (note 16)		214.8		225.7
Asset retirement obligation (note 9)		40.4		40.3
		772.0		1,060.5
UNITHOLDERS’ EQUITY
Net capital contributions (note 11)		2,294.3		2,042.0
Capital issued but not distributed		3.6		3.3
Convertible Unsecured Subordinated Debentures (note 8)		1.8		8.1
Contributed surplus (note 12)		8.7		6.4
Accumulated income		303.8		96.3
Accumulated cash distributions		(1,244.3)		(967.7)
Accumulated dividends		(8.0)		(8.0)
		1,359.9		1,180.4
	$	2,131.9	$	2,240.9

Commitments and contingencies (note 18). The accompanying notes form an integral part of these financial statements.

Signed “Harold P. Milavsky”

Signed “Don Garner”

Harold P. Milavsky

Don Garner

Chair of the Board of Directors

President and Chief Executive Officer

MANAGEMENT’S DISCUSSION AND ANALYSIS–PRIMEWEST ENERGY TRUSTANNUAL REPORT 2005

CONSOLIDATED STATEMENTS OF CHANGES IN UNITHOLDERS’ EQUITY

For the years ended December 31 ($ millions)	2005		2004 (restated – see  note 3)		2003 (restated – see note 3)
Unitholders’ equity, beginning of year	$	1,180.4	$	1,014.0	$	847.1
Adjustment to Unitholders’ equity at beginning of period to adopt:
New oil and gas accounting standard (note 3)		-		(233.3)		-
Fair value method for unit-based compensation (note 3)		-		-		(6.7)
Net income for the year		207.5		105.4		102.7
Net capital contributions (note 11)		252.3		481.4		256.7
Capital issued but not distributed		0.3		(1.9)		4.3
Convertible Unsecured Subordinated Debentures		(6.3)		8.1		-
Contributed surplus		2.3		2.8		2.5
Cash distributions (note 14)		(276.6)		(196.1)		(192.6)
Unitholders’ equity, end of year	$	1,359.9	$	1,180.4	$	1,014.0

PRIMEWEST ENERGY TRUSTANNUAL REPORT 2005–MANAGEMENT’S DISCUSSION AND ANALYSIS

CONSOLIDATED STATEMENTS OF CASH FLOW

For the years ended December 31 ($ millions)	2005		2004 (restated – see note 3)		2003 (restated – see note 3)
OPERATING ACTIVITIES
Net income for the year	$	207.5	$	105.4	$	102.7
Add/(deduct):
Items not involving cash from operations
Depletion, depreciation and amortization		230.2		197.3		197.4
Non-cash general and administrative		5.4		4.1		3.1
Non-cash foreign exchange gain		(4.9)		(11.9)		(12.1)
Cash distributions from marketable securities		1.2		4.1		-
Gain on sale of marketable securities (note 4)		(27.2)		-		-
Unrealized loss/(gain) on derivatives		11.6		(0.1)		-
Future income tax recovery		(14.8)		(34.3)		(75.4)
Accretion on asset retirement obligation		2.5		2.0		1.2
Other non-cash items		2.6		0.2		(0.3)
Cash flow from operations		414.1		266.8		216.6
Expenditures on site restoration and reclamation		(8.7)		(4.6)		(2.2)
Change in non-cash working capital		(28.0)		11.9		5.3
		377.4		274.1		219.7
FINANCING ACTIVITIES
Proceeds from issue of Trust Units (net of costs)		20.4		441.0		240.3
Proceeds from issue of Debentures		-		250.0		-
Net cash distributions to Unitholders (note 14)		(241.5)		(159.6)		(172.5)
Increase (decrease) in bank credit facilities		(111.0)		166.0		(137.0)
Increase in Senior Secured Notes		-		-		174.0
Increase in deferred charges		-		(10.0)		(1.5)
Change in non-cash working capital		4.2		10.9		(3.6)
		(327.9)		698.3		99.7
INVESTING ACTIVITIES
Expenditures on property, plant and equipment		(192.5)		(129.7)		(105.8)
Acquisition of capital/corporate assets		-		(807.4)		(210.1)
Proceeds on disposal of property, plant and equipment		26.0		96.5		2.3
Investment in marketable securities (note 4)		-		(72.7)		-
(Increase) decrease in cash reserved for future site restoration and reclamation		1.1		(2.1)		(6.6)
Proceeds on disposal of marketable securities		94.5		-		-
Change in non-cash working capital		3.8		(5.1)		6.4
		(67.1)		(920.5)	$	(313.8)
(Decrease)/Increase in cash and cash equivalents for the year	$	(17.6)	$	51.9	$	5.6
Cash and cash equivalents (bank overdraft) beginning of the year		54.4		2.5		(3.1)
Cash and cash equivalents end of the year	$	36.8	$	54.4	$	2.5
Cash interest paid	$	23.8	$	15.0	$	13.1
Cash taxes paid	$	5.4	$	3.8	$	3.9

MANAGEMENT’S DISCUSSION AND ANALYSIS–PRIMEWEST ENERGY TRUSTANNUAL REPORT 2005

CONSOLIDATED STATEMENTS OF INCOME

For the years ended December 31 ($ millions, except per Trust Unit amounts)	2005			2004 (restated – see note 3)			2003 (restated – see note 3)
REVENUES
Sales of crude oil, natural gas and natural gas liquids	$	756.9	$		521.9	$		442.9
Crown and other royalties		(172.8)			(119.8)			(101.9)
Unrealized (loss)/gain on derivatives		(11.6)			0.1			-
Gain on sale of marketable securities		27.2			-			-
Other income		4.7			0.6			(2.8)
		604.4			402.8			338.2
EXPENSES
Operating		117.0			88.9			79.4
Transportation		7.2			8.2			8.3
Cash general and administrative		22.9			19.0			14.5
Non-cash general and administrative (note 13)		5.4			4.1			3.1
Interest		28.3			20.6			15.1
Depletion, depreciation and amortization		230.2			197.3			197.4
Accretion on asset retirement obligations		2.5			2.0			1.2
Foreign exchange gain		(4.6)			(11.7)			(11.9)
		408.9			328.4			307.1
Income before taxes for the year		195.5			74.4			31.1
Income and capital taxes		2.8			3.3			3.8
Future income taxes recovery (note 16)		(14.8)			(34.3)			(75.4)
		(12.0)			(31.0)			(71.6)
Net income for the year	$	207.5	$		105.4	$		102.7
Net income per Trust Unit	$	2.73	$		1.77	$		2.23
Diluted net income per Trust Unit	$	2.66	$		1.77	$		2.22

PRIMEWEST ENERGY TRUSTANNUAL REPORT 2005–MANAGEMENT’S DISCUSSION AND ANALYSIS

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 natural 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 natural 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., a wholly owned subsidiary of PrimeWest Energy Inc., was amalgamated with PrimeWest Energy Inc. effective January 1, 2006.

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.

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 natural 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 natural 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.

MANAGEMENT’S DISCUSSION AND ANALYSIS–PRIMEWEST ENERGY TRUSTANNUAL REPORT 2005

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 (DD&A)

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 natural gas production activities through joint ventures, and the accounts reflect only PrimeWest’s proportionate interest in such activities.

UNIT-BASED COMPENSATION

PrimeWest accounts for its Unit Appreciation Rights (UARs) issued to employees and the Board of Directors using the fair value method. The fair value of each UAR is estimated on the date of the grant using the Black-Scholes options pricing model and charged to earnings over the vesting period with a corresponding increase to contributed surplus.

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 site restoration costs which depend on estimates of oil and natural gas reserves or the economic lives and future cash flows from related assets.

3. Changes in Accounting Policies

CHANGE IN METHOD OF ACCOUNTING FOR UNIT-BASED COMPENSATION

Beginning January 1, 2005, PrimeWest determined that if a series of assumptions were used, it was possible to use a traditional options pricing model to calculate a reasonable estimate of the fair value of PrimeWest’s UARs granted under its Long-Term Incentive Plan (LTIP). Under the fair value method, PrimeWest recognizes compensation expense related to the UARs over the vesting period of the UARs granted with the related credit being charged to contributed surplus. In prior years, PrimeWest had been applying the intrinsic method to value its unit-based compensation whereby the value of the UARs was adjusted at the end of each accounting period to reflect the impact of the reinvestment of cumulative distributions and the changes in the trading price of the Trust Units. The changes in value of the UAR liability were reflected in non-cash G&A on the income statement.

PrimeWest has applied the fair value method retroactively to UARs issued on or after January 1, 2002 and prior periods have been restated. At January 1, 2005 the change in accounting policy resulted in an increase to the future income tax liability of $14.5 million (2004 – $11.2 million), a decrease to net capital contributions of $7.9 million (2004 – $5.3 million), a decrease to the LTIP equity of $20.1 million (2004 – $14.6 million), an increase in contributed surplus of $6.4 million (2004 – $3.6 million) and an increase to accumulated income of $7.1 million (2004 – $5.1 million).

The change in accounting method resulted in an increase to 2005 net income of $52.7 million.

PRIMEWEST ENERGY TRUSTANNUAL REPORT 2005–MANAGEMENT’S DISCUSSION AND ANALYSIS

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 a two-stage process, which is 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 r eserves. The discount rate used is the risk free rate.

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

Consultants’ Average Price Forecasts	2004	2005	2006	2007	2008
W.T.I. (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 standard requires the recognition of the liability associated with the future site reclamation costs of tangible long-lived assets. This liability is comprised of the Trust’s net ownership interest in producing wells and processing plant facilities. The liability for future retirement obligations is 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 to earn ings in the period incurred.

The cumulative effect of the change in accounting policy was reflected in 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), an increase to PP&E of $10.6 million (2003 – $9.0 million), a $5.6 million (2003 – $0.04 million) increase to accumulated income, a decrease of site restoration provision of $17.8 million (2003 – $6.2 million) and an increase to the future tax liability of $3.1 million (2003 – $(0.03) 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 implemented CICA Accounting Guideline (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 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. Derivatives are marked-to-market with the resulting gain or loss reflected in earnings for the reporting period.

MANAGEMENT’S DISCUSSION AND ANALYSIS–PRIMEWEST ENERGY TRUSTANNUAL REPORT 2005

4. Marketable Securities

($ millions)		2005		2004
Investment in Viking Energy Royalty Trust	$	-	$	68.6

PrimeWest sold its 8% ownership in the Viking Energy Royalty Trust in 2005 (formerly Calpine Natural Gas Trust) for net proceeds of $94.5 million resulting in a gain of $27.1 million.

5. Acquisitions

a) On September 2, 2004, PrimeWest Gas Corp. acquired oil and natural 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	$	745.3
Inventory		4.2	Cash	$	747.0
Working capital		2.7	Net closing adjustments		(11.1)
Asset retirement obligation		(12.0)	Costs associated with acquisition		4.3
	$	740.2		$	740.2

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

6. Property, Plant and Equipment

	2005
($ millions)	Cost	Accumulated Depletion, Depreciation and Amortization	Net Book Value
Property acquisition oil and natural gas rights	$       2,677.1	$       (1,260.7)	$     1,416.4
Drilling and completion	417.9	(110.7)	307.2
Production facilities and equipment	176.6	(48.4)	128.2
Head office furniture and equipment	16.8	(8.7)	8.1
	$      3,288.4	$       (1,428.5)	$     1,859.9
	2004
($ millions)	Cost	Accumulated Depletion, Depreciation and Amortization	Net Book Value
Property acquisition oil and natural 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
Head office furniture and equipment	12.6	(6.2)	6.4
	$       3,106.9	$       (1,198.3)	$     1,908.6

Unproved land costs of $88.0 million (2004 – $103.9 million) and $4.1 million of capital not in use (2004 – $0 million) are excluded from costs subject to depletion and depreciation.

PrimeWest capitalized $3.7 million of G&A costs in 2005 (2004  – $2.9 million).

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

PrimeWest has performed a ceiling test as at December 31, 2005. The impairment test was calculated using the Consultant’s Average Prices at January 1, 2006 for the years 2006 to 2010 as follows:

Consultants’ Average Price Forecasts	2006	2007	2008	2009	2010
W.T.I. (US$/bbl)	58.44	57.34	52.70	49.23	47.05
AECO (Cdn$/mcf)	10.93	9.88	8.48	7.59	7.23

Subsequent to 2010, prices increased by approximately 2% per year.

The December 31, 2005 ceiling test resulted in a surplus.

7. Other Assets and Deferred Charges

($ millions)		2005		2004
Deferred charges	$	8.7	$	10.6
Other assets		0.1		0.3
	$	8.8	$	10.9

8. Long-Term Debt

($ millions)		2005		2004
Bank credit facility	$	153.0	$	264.0
Senior Secured Notes		145.4		150.3
Convertible Unsecured Subordinated Debentures		55.8		242.0
	$	354.2	$	656.3

Long-term debt is comprised of bank credit facilities, Senior Secured Notes (Secured Notes) and Convertible Unsecured Subordinated Debentures (Debentures) of $153.0 million, $145.4 million and $55.8 million, respectively.

PrimeWest had a borrowing base of $650 million at December 31, 2005 (2004 – $625 million). The bank credit facilities consist of an available revolving term loan of $458.7 million and an operating facility of $35 million with the balance being attributable to the Secured Notes valued at $156.3 million based on the U.S. dollar exchange rate at the time of the last renewal. In addition to amounts outstanding under the bank credit facility, PrimeWest has outstanding letters of credit in the amount of $6.6 million (2004 – $4.9 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 2005, the effective interest rate on the facilities was 4.0% (2004 – 4.0%).

The bank credit facility revolves until June 30, 2006, 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 lenders have the right to extend the revolving period for a further 364-day period or to convert the facility to a term facility. If the lenders convert 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.

The Secured 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 Secured Notes and 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 for the revolving credit facility and Secured Notes have agreed to share the security interests on a pari passu basis.

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

The Secured 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) Debentures were issued on September 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 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 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 at 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 Trust Units.

Debenture issue costs of $10.0 million were included in deferred charges on the balance sheet and are being amortized 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 $94.8 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)).

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. During 2005, $114.3 million (2004 – $0.3 million) of Series I and $72.9 million (2004 – $0 million) of Series II Debentures included in long-term debt were converted to equity. Accretion expense was $1.0 million (2004 – $0.4 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 and natural gas properties:

Asset Retirement Obligations ($ millions)		2005		2004
Asset retirement obligation, January 1	$	40.3	$	19.7
Liabilities incurred		8.3		13.1
Liabilities settled		(8.7)		(4.6)
Accretion expense		2.5		2.0
Acquisition of capital assets		-		12.0
Disposal of capital assets		(2.0)		(2.4)
Acquisition of Seventh Energy		-		0.5
Asset retirement obligation December 31	$	40.4	$	40.3

As at December 31, 2005, the undiscounted amount of estimated cash flows required to settle the obligation is $222.3 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 1 year to a maximum of 50 years, the costs are expected to be paid over an average of 33.9 years. These future asset retirement costs will be funded from the cash reserved for site restoration and reclamation.

PRIMEWEST ENERGY TRUSTANNUAL REPORT 2005–MANAGEMENT’S DISCUSSION AND ANALYSIS

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 2005 and 2004). The cash amount contributed, including interest earned, was $7.6 million in 2005 (2004 – $6.7 million). Actual costs of site restoration and abandonment totaling $8.7 million were paid out of this cash reserve for the year ended December 31, 2005 (2004 – $4.6 million). As at December 31, 2005, the site reclamation fund had a balance of $9.2 million (2004 – $10.3 million).

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, 2003	48,751,883	$	1,532.5(1)
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		0.5
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	$	2,029.8
Issued on exchange of Exchangeable Shares	91,871		1.7
Issued pursuant to Distribution Reinvestment Plan	262,347		7.9
Issued pursuant to Premium Distribution Plan	932,142		27.4
Issued pursuant to Long-Term Incentive Plan	487,421		1.3
Issued pursuant to conversion of Debentures	7,301,654		193.5
Issued pursuant to Optional Trust Unit Purchase Plan	704,806		20.4
Balance December 31, 2005	79,666,352	$	2,282.0

(1)

Restated – see note 3.

The weighted average number of Trust Units and Exchangeable Shares outstanding for the twelve months ended December 31, 2005 was 75,808,919 (2004 – 59,482,034). For purposes of calculating diluted net income per Trust Unit, 3,247,742 (2004 – 1,868,995) and 2,286,791 Trust Units (2004 –1,247,551) issuable pursuant to the conversion of the Series I and Series II Debentures outstanding respectively and 1,220,958 Trust Units (2004 – 525,129) issuable pursuant to the LTIP were added to the weighted average number.

PRIMEWEST EXCHANGEABLE CLASS A SHARES

PrimeWest has an unlimited number of Exchangeable Shares. The Exchangeable Shares are exchangeable into Trust Units at any time up to March 29, 2010, based on an exchange ratio that adjusts each time the Trust makes distribution to its Unitholders. The exchange ratio, which was 1:1 on the date that the Shares were issued, is based on the total monthly distribution, divided by the closing unit price on the distribution payment date. The exchange ratio on December 31, 2005 was 0.56399:1 (2004 – 0.50408:1).

Exchangeable Shares	Number of Units	Amounts  ($ millions)
Balance, December 31, 2003	3,041,123	$	28.0
Issued for Special Employee Retention Plan	94,340		1.2
Exchanged for Trust Units	(1,841,072)		(17.0)
Balance, December 31, 2004	1,294,391	$	12.2
Issued for Special Employee Retention Plan	94,340		1.8
Exchanged for Trust Units	(169,396)		(1.7)
Balance, December 31, 2005	1,219,335	$	12.3

MANAGEMENT’S DISCUSSION AND ANALYSIS–PRIMEWEST ENERGY TRUSTANNUAL REPORT 2005

TRUST UNITS AND EXCHANGEABLE SHARES ISSUED AND OUTSTANDING

Number of Shares	2005	2004
Trust Units issued and outstanding	79,666,352	69,886,111
Exchangeable Shares
Class A Shares
(2005 – 1,219,335 shares exchangeable at 0.56399;
2004 – 1,294,391 shares exchangeable at 0.50408)	687,693	652,477
Total Trust Units and Exchangeable Shares issued and outstanding	80,354,045	70,538,588
Convertible Unsecured Subordinated Debentures
Series I	1,246,981	5,649,849
Series II	874,717	3,773,585
Unit Appreciation Rights	1,220,958	525,129
Total Trust Units and Exchangeable Shares issued and outstanding and Trust Units issuable pursuant to the conversion of the Convertible Unsecured Subordinated Debentures and the Long-Term Incentive Plan	83,696,701	80,487,151

12. Contributed Surplus

Contributed surplus includes the accumulated unit-based compensation charge in respect of PrimeWest’s unexercised Unit Appreciation Rights granted under the LTIP on or after January 1, 2002. Upon exercise of the UARs and delivery of the Trust Units, the contributed surplus account is reduced and the amount is transferred to net capital contributions.  

($ millions)
Balance, December 31, 2003	$	3.6
Non-cash general and administrative expense		3.3
Unit Appreciation Rights exercised		(0.5)
Balance, December 31, 2004	$	6.4
Non-cash general and administrative expense		3.6
Unit Appreciation Rights exercised		(1.3)
Balance, December 31, 2005	$	8.7

13. Long-Term Incentive Plan

Under the terms of the LTIP, a maximum of 1,800,000 Trust Units are reserved for issuance pursuant to the exercise of UARs granted to Directors and employees 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 those issued to the members of the Board, which 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.

Effective January 1, 2005, PrimeWest adopted the fair value method of accounting for its LTIP with respect to UARs granted on or after January 1, 2002. Under this method of accounting, the fair value of the UARs is estimated using a recognized options pricing model on the grant date and is amortized over the vesting period with the amortized amount recorded in non-cash G&A expense offset by an increase to contributed surplus. When the UARs are exercised, contributed surplus is decreased and net capital contributions are increased.

PrimeWest recorded $3.6 million (2004 – $3.3 million) in non-cash G&A expense related to the LTIP.

For the twelve months ended December 31, 2005, PrimeWest used the Black-Scholes Options Pricing Model to calculate the estimated fair value of outstanding UARs issued on or after January 1, 2002. The following assumptions were used to arrive at the estimated fair value:

PRIMEWEST ENERGY TRUSTANNUAL REPORT 2005–MANAGEMENT’S DISCUSSION AND ANALYSIS

Weighted Average Assumptions	2005	2004
Risk-free interest rate	3.18%	3.49%
Expected volatility in Trust Unit price	19.8%	22.0%
Expected time until exercise	3 years	3 years
Expected forfeiture rate	13%	13%
Expected annual dividend yield	zero	zero

Summary of Changes	Number of UARs	Weighted Average Exercise Price
Balance outstanding at December 31, 2003	2,046,436	$28.03
Granted	1,495,373	27.94
Forfeited/expired	(141,989)	(29.02)
Exercised	(166,328)	(27.37)
Balance outstanding at December 31, 2004	3,233,492	$28.77
Granted	1,517,674	30.40
Forfeited/expired	(122,873)	(28.44)
Exercised	(458,618)	(28.42)
Balance outstanding at December 31, 2005	4,169,675	$29.09

Summary of UARS Outstanding at December 31, 2005

Year of Grant	UARS Issued and Outstanding	UARS Vested	Range of Exercise Prices		Expiry Date
2002 grants	602,526	600,732	$	25.90 – 33.94		2008
2003 grants	805,641	516,356		25.25 – 32.24		2009
2004 grants	1,303,893	489,681		24.24 – 32.49		2010
2005 grants	1,457,615	138,464		28.90 – 40.51		2011
Total grants	4,169,675	1,745,233	$	24.24 – 40.51

14. Cash Distributions

($ millions)	2005		2004				2003
Cash flow from operations	$	414.1		$	266.8	$		216.6
Deduct amounts to reconcile to distribution:
Cash retained from cash available for distribution (1)		(129.9)			(64.0)			(15.3)
Contributed to reclamation fund		(7.6)			(6.7)			(8.7)
	$	276.6		$	196.1	$		192.6
Cash distributions to Trust Unitholders	$	276.6		$	196.1	$		192.6
Cash distributions per Trust Unit	$	3.66		$	3.30	$		4.32

(1)

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

15. Related Party Transactions

Under the Special Employee Retention Plan (SERP), PrimeWest agreed to issue 94,340 Exchangeable Shares to certain executive officers on each of the second, third, fourth and fifth anniversaries of the completion of the internalization transaction, which closed on November 6, 2002. In November 2005, 94,340 exchangeable shares were issued relating to the SERP. For the twelve months ended December 31, 2005, $1.8 million (2004 – $0.9 million) was recorded in non-cash G&A expense related to the SERP.  

MANAGEMENT’S DISCUSSION AND ANALYSIS–PRIMEWEST ENERGY TRUSTANNUAL REPORT 2005

16. Income Taxes

PrimeWest and its subsidiaries had no taxable income for 2005, 2004 and 2003, as tax pool deductions and the royalty payable were sufficient to reduce taxable income in these entities to nil.

The future income tax asset and liability result from temporary differences between the financial statement carrying amounts of assets and liabilities and their respective tax bases.

($ millions)	2005		2004
Derivative liabilities	$	3.9	$	-
Future income tax asset	$	3.9	$	-

($ millions)	2005		2004 Restated
Loss carry forwards	$	(1.2)	$	(1.4)
Capital assets		224.8		236.9
Foreign exchange gain on long-term debt		4.8		3.7
Asset retirement obligation		(13.6)		(13.5)
Future income tax liability	$	214.8	$	225.7

The provisions for income taxes varies from the amounts that would be computed by applying the combined Canadian federal and provincial income tax rates for the following reasons:

($ millions)	2005		2004 Restated		2003 Restated
Income before taxes	$	195.5	$	74.4	$	31.1
Computed income tax expense (recovery) at the Canadian statutory rate
of 37.62% (2004 – 38.87%; 2003 – 40.62%)		73.5		28.9		12.6
Increase (decrease) resulting from:
Non-deductible Crown royalties and other payments, net of ARTC		0.3		0.3		0.3
Federal resource allowance		(12.3)		(9.2)		(17.4)
Change in income tax rate		(2.7)		(7.0)		(42.4)
Foreign exchange gain on long-term debt		(0.9)		(2.2)		(2.4)
Amounts included in Trust income and other		(72.7)		(45.1)		(26.1)
Future income tax recovery	$	(14.8)	$	(34.3)	$	(75.4)

17. Financial Instruments

a) Commodity Price Risk Management

PrimeWest generally sells its oil and natural gas under short-term market-based contracts. Derivative financial instruments, options and swaps may be used to hedge the impact of oil and natural gas price fluctuations.

A summary of these contracts in place at December 31, 2005 follows:

PRIMEWEST ENERGY TRUSTANNUAL REPORT 2005–MANAGEMENT’S DISCUSSION AND ANALYSIS

CRUDE OIL

Period	Volume (bbls/day)	Type	WTI Price (US$/bbl)
Jan – Mar 2006	1000	Costless Collar	35.00/49.90
Jan – Mar 2006	500	Costless Collar	40.00/60.25
Jan – Mar 2006	500	Costless Collar	40.00/71.75
Jan – Mar 2006	500	Costless Collar	50.00/70.00
Jan – Mar 2006	500	Costless Collar	50.00/75.00
Jan – Mar 2006	1000	Costless Collar	50.00/82.80
Apr – Jun 2006	500	Costless Collar	40.00/71.25
Apr – Jun 2006	500	Costless Collar	50.00/70.00
Apr – Jun 2006	500	Costless Collar	50.00/75.70
Apr – Jun 2006	1000	Costless Collar	50.00/82.75
Apr – Jun 2006	500	Costless Collar	50.00/75.05
Jul – Sep 2006	500	Costless Collar	50.00/75.30
Jul – Sep 2006	1000	Costless Collar	50.00/82.05
Jul – Sep 2006	500	Costless Collar	50.00/76.05
Oct – Dec 2006	500	Costless Collar	50.00/75.03
Oct – Dec 2006	1000	Costless Collar	50.00/81.50
Oct – Dec 2006	500	Costless Collar	50.00/75.00
Jan – Mar 2007	500	Costless Collar	50.00/76.00
Apr  – Jun 2007	500	Costless Collar	50.00/80.00

NATURAL GAS

Period	Volume (mmcf/day)	Type	AECO Price (Cdn$/mcf)
Jan – Mar 2006	10	Costless Collar	6.33/9.96
Jan – Mar 2006	10	Costless Collar	6.33/10.22
Jan – Mar 2006	5	Costless Collar	6.33/10.42
Jan – Mar 2006	10	Costless Collar	6.33/10.55
Jan – Mar 2006	5	Costless Collar	6.33/11.61
Jan – Mar 2006	5	Costless Collar	6.33/12.66
Jan – Mar 2006	5	Costless Collar	6.33/13.13
Jan – Mar 2006	5	Costless Collar	6.33/14.03
Jan – Mar 2006	5	Costless Collar	7.39/14.51
Jan – Mar 2006	10	Costless Collar	7.39/14.56
Jan – Mar 2006	5	Costless Collar	10.34/16.88
Jan – Mar 2006	5	Costless Collar	10.55/26.11
Jan – Mar 2006	5	Costless Collar	11.61/22.42
Apr – Jun 2006	5	Costless Collar	6.33/8.91
Apr – Jun 2006	10	Costless Collar	6.86/10.55
Apr – Jun 2006	5	Costless Collar	6.86/10.63
Apr – Jun 2006	5	Costless Collar	7.39/13.72
Apr – Jun 2006	5	Costless Collar	8.44/12.98
Apr – Jun 2006	5	Costless Collar	8.44/15.30
Apr – Jun 2006	10	Costless Collar	8.44/16.62
Jul – Sep 2006	10	Costless Collar	6.86/10.55
Jul – Sep 2006	5	Costless Collar	6.86/10.68
Jul – Sep 2006	5	Costless Collar	7.39/13.56
Jul – Sep 2006	5	Costless Collar	8.44/13.98
Jul – Sep 2006	5	Costless Collar	8.44/15.72
Jul – Sep 2006	5	Costless Collar	8.44/15.83
Jul – Sep 2006	10	Costless Collar	8.44/16.30
Oct – Dec 2006	5	Costless Collar	6.86/11.92
Oct – Dec 2006	10	Costless Collar	6.86/12.66
Oct – Dec 2006	5	Costless Collar	7.39/15.83
Oct – Dec 2006	5	Costless Collar	8.44/15.83
Oct – Dec 2006	5	Costless Collar	8.44/17.94
Oct – Dec 2006	5	Costless Collar	8.44/18.99
Oct – Dec 2006	10	Costless Collar	8.44/19.25
Jan – Mar 2007	5	Costless Collar	8.44/18.46
Jan – Mar 2007	5	Costless Collar	8.44/21.10
Jan – Mar 2007	5	Costless Collar	8.44/21.21

In 2005, the financial impact of contracts settling in the year was a decrease in sales revenues of $44.3 million (2004 – $28.2 million decrease in sales revenue).

The mark-to-market value of the hedges in place as at December 31, 2005 is an $11.5 million loss of which $9.2 million is attributable to natural gas and $2.3 million is attributable to crude oil.

b) Fair Value of Financial Instruments

Financial instruments include cash, accounts receivable, accounts payable and accrued liabilities, accrued distributions to Unitholders and long-term debt. As at December 31, 2005, 2004, and 2003, the fair market value of these financial instruments, other than long-term debt, 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.

18. 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 $3.7 million in 2006, $3.5 million in 2007, $3.4 million in 2008 and $0.9 million in 2009.

b)  As part of PrimeWest’s internalization transaction which closed on November 6, 2002 PrimeWest agreed to issue 377,340 Exchangeable Shares to certain executive officers as a SERP. The SERP issued 94,340 Exchangeable Shares on each of November 6, 2004 and 2005 and will issue an additional 94,340 Exchangeable Shares on November 6, 2006 and 2007. For the twelve months ended December 31, 2005, $1.8 million was recorded in non-cash general and administrative expense related to the SERP.

c)  PrimeWest has various pipeline transportation commitments that run through 2011. The estimated annual payments are $7.2 million in 2006, $3.2 million in 2007, $0.5 million in 2008, $0.3 million in 2009, $0.2 million in 2010 and $0.1 million in 2011.

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

19. Prior Years’ Comparative Numbers

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

MANAGEMENT’S DISCUSSION AND ANALYSIS–PRIMEWEST ENERGY TRUSTANNUAL REPORT 2005

20. 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 GAAP). The following are those policies that result in significant measurement difference.

1. Property, Plant and Equipment

PrimeWest uses the ceiling test method set out in CICA Accounting Guideline 16 (AcG-16), “Oil and Gas Accounting – Full Costs”. This guideline 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 U.S. 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 U.S. GAAP, the charge for depreciation and depletion under U.S. 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 U.S. 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 was recorded as an adjustment to accumulated income with retroactive restatement of prior period comparatives.

The change in accounting policy was 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 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 (PP&E) is allocated to expense on the unit-of-production basis.

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 the future income 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 U.S. GAAP, the marketable securities are considered held for trading and recorded on the balance sheet at fair value. The corresponding difference between the cost method and fair value is recorded in earnings in the current year and results in a Canadian/US GAAP difference.

4. Unitholders’ Mezzanine Equity

PrimeWest accounts for all Trust Units and Exchangeable Shares outstanding as permanent equity presented as Net capital contributions under Unitholder’s Equity on the balance sheet. The Trust Units are redeemable at the option of the Unitholder, and therefore must be valued at their redemption amount and presented as mezzanine equity in the consolidated balance sheet under U.S. GAAP. The redemption value of the Trust Units is based on the trading value of the Trust Units and the Trust Unit equivalent of the Exchangeable Shares at each balance sheet date. At December 31, 2005 and 2004, the Trust classified $2.8 billion and $1.6 billion from Unitholders’ Equity, respectively, to mezzanine equity in accordance with U.S. GAAP. The Trust has also recognized a deficit of $1.6 billion for 2005 and $0.5 billion for 2004 resulting from eliminating the Unitholders’ equity accounts of the Trust and replacing them with Unitholders’ mezzanine equity at redemption value.

In 2004 and prior years, the Trust believed there were sufficient restrictions on redemptions to classify the trust units as permanent equity for U.S. GAAP purposes. Upon further review it was determined that the Trust Units should be accounted for as temporary equity for U.S. GAAP purposes as set out in the preceding paragraph. Prior year amounts have been restated.

5. Unit-Based Compensation

Effective January 1, 2005, PrimeWest adopted the fair value method of accounting for Unit Appreciation Rights (UARs) for Canadian GAAP purposes. In prior years, the intrinsic method had been used. For U.S. GAAP purposes, the intrinsic method of valuing unit-based compensation continues to be used in accordance with APB Opinion No. 25 “Accounting for Stock Issued to Employees”. For U.S. GAAP purposes, the accounting policy change restatements recorded for Canadian GAAP purposes have been reversed and restatement of only the future income tax portion has been recorded. In addition, unit-based compensation expense computed in accordance with the intrinsic method is included as non-cash G&A expense in 2005 consistent with prior years.

If the fair value method of valuing unit-based compensation were used for U.S. GAAP purposes, reported earnings per share numbers would increase by $0.70 in 2005 ($0.09 in 2004; $0.24 in 2003).

RECENT ACCOUNTING PRONOUNCEMENTS ISSUED BUT NOT IMPLEMENTED

On December 15, 2004 FAS Statement No. 123R “Share-Based Payment” was issued. 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 remeasured 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 prono uncement on the financial statements.

The following tables set out the significant differences in the consolidated financial statements using U.S. GAAP.

a)  Consolidated Net Income

($ millions, except per Trust Unit amounts)	2005		2004		2003
Net income as reported	$	207.5	$	105.4	$	102.7
Reverse restatement of unit-based compensation expense
Non-cash G&A expense		-		(5.3)		(11.3)
Future income tax expense		-		3.3		4.5
Net income as published in prior years	$	207.5	$	103.4	$	95.9
Record for U.S. GAAP purposes restatement of future income tax expense related to unit-based compensation		-		(3.3)		(4.5)
Adjustments
Depletion and depreciation		17.8		(4.2)		35.4
FAS 115 adjustment		(22.6)		22.6		-
FAS 133 adjustment		-		5.4		6.1
Non-cash G&A expense related to unit-based compensation (intrinsic method)		(56.3)		-		-
Non-cash G&A expense related to unit-based compensation (fair value method)		3.6		-		-
Future income tax expense		(6.0)		(4.3)		(42.3)
Adjusted net income before change in accounting policy		144.0		119.6		90.6
Cumulative effect of change in accounting policy, net of tax of $0.3 million		-		-		(0.4)
Adjusted net income	$	144.0	$	119.6	$	90.2
Net income per Trust Unit
U.S. GAAP – Basic	$	1.90	$	2.01	$	1.96
– Diluted	$	1.88	$	1.99	$	1.95
Cumulative effect of change in accounting policy per Trust Unit
U.S. GAAP – Basic	$	-	$	-	$	0.01
– Diluted	$	-	$	-	$	0.01

PRIMEWEST ENERGY TRUSTANNUAL REPORT 2005–MANAGEMENT’S DISCUSSION AND ANALYSIS

b)  Consolidated Unitholders’ Equity

($ millions, except per Trust Unit amounts)	2005		2004
Unitholders’ equity as reported	$	1,359.9	$	1,180.4
Reverse restatement resulting from change in accounting method of unit-based compensation recorded for Canadian GAAP purposes:
Capital contributions		7.9		7.9
Accumulated income		(7.1)		(7.1)
Contributed surplus		(6.4)		(6.4)
LTIP equity		20.1		20.1
Unitholders’ equity as reported before restatement	$	1,374.4	$	1,194.9
Record restatement of future income tax expense for U.S. GAAP		(14.5)		(14.5)
Adjustments related to income
Depletion and depreciation		(252.5)		(270.3)
FAS 115 adjustment		-		22.6
Future income tax recovery		113.2		119.2
Adjustments related to presentation of mezzanine equity:
Net capital contributions		(2,313.0)		(2,049.9)
Capital issued but not distributed		(3.6)		(3.3)
Convertible Unsecured Subordinated Debentures		(1.8)		(8.1)
Long-term incentive plan equity		(64.3)		(20.1)
US GAAP accumulated income		(90.2)		53.8
Accumulated cash distributions		1,244.3		967.7
Accumulated dividends		8.0		8.0
Deficit		(1,568.4)		(529.6)
Unitholders’ equity	$	(1,568.4)	$	(529.6)

c) Consolidated Balance Sheets

	2005
($ millions)	Note	CDN GAAP			US GAAP
Property, plant and equipment (net)	1	$	1,859.9	$	1,668.6
Marketable securities	3		-		-
Future income tax liability	1,2		214.8		162.7
Mezzanine equity	4		-		2,789.1
Net capital contributions	4,5		2,294.3		-
Convertible Unsecured Subordinated Debentures	4		1.8		-
Capital issued but not distributed	4		3.6		-
Contributed surplus	4,5		8.7		-
Accumulated income (deficit)	1,2,4,5		303.8		(1,568.4)
Accumulated cash distributions	4		(1,244.3)		-
Accumulated dividends	4		(8.0)		-

MANAGEMENT’S DISCUSSION AND ANALYSIS–PRIMEWEST ENERGY TRUSTANNUAL REPORT 2005

	2004
($ millions)	Note	CDN GAAP		US GAAP (restated – see note 4)
Property, plant and equipment (net)	1	$	1,908.6	$	1,699.4
Marketable securities	3		68.6		91.2
Future income tax liability	1,2		225.7		167.7
Mezzanine equity	4		-		1,581.5
Net capital contributions	4,5		2,042.0		-
Convertible Unsecured Subordinated Debentures	4		8.1		-
Capital issued but not distributed	4		3.3		-
Contributed surplus	4,5		6.4		-
Accumulated income (deficit)	1,2,4,5		96.3		(529.6)
Accumulated cash distributions	4		(967.7)		-
Accumulated dividends	4		(8.0)		-

d)  Consolidated Cash Flows

The consolidated statements of cash flows prepared in accordance with Canadian GAAP conform in all material respects with U.S. 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 U.S. GAAP.

FAS 69 SUPPLEMENTAL RESERVE INFORMATION (UNAUDITED)

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

Oil and Natural 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 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 a vailable data for various reservoirs make these estimates generally less precise than other estimates presented in connection with financial statement disclosures.

Proved oil and natural 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 natural gas reserves are reserves that can be expected to be recovered through existing wells 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.

Subsequent to December 31, 2005, no major discovery or other favorable or adverse event is believed to have caused a material change in the estimates of Proved or Proved developed reserves as of that date.

PRIMEWEST ENERGY TRUSTANNUAL REPORT 2005–MANAGEMENT’S DISCUSSION AND ANALYSIS

Results of Oil and Gas Operations ($ millions)	2005		2004		2003
Revenues	$	597.1	$	394.6	$	329.9
Expenses
Production costs		117.0		88.9		79.4
Depreciation, depletion and amortization		212.4		201.5		170.3
Accretion		2.5		2.0		1.2
Tax recovery		(12.4)		(30.0)		(39.9)
		319.5		262.4		211.0
Results of operations from oil and natural gas operations	$	277.6	$	132.2	$	118.9

Costs Incurred ($ millions)	2005		2004		2003
Property acquisition costs
Proved properties	$	2.7	$	770.5	$	202.4
Unproved properties		17.6		52.1		34.0
Exploration costs		8.7		16.0		5.7
Development costs		165.4		123.6		101.5
	$	194.4	$	962.2	$	343.6

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

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

Capitalized Costs($ millions)	2005		2004		2003
Proved properties	$	2,852.6	$	2,599.1	$	2,189.0
Unproved properties		88.0		103.9		36.0
		2,940.6		2,703.0		2,225.0
Less related accumulated depreciation, depletion and amortization		(1,280.2)		(1,010.0)		(1,186.2)
	$	1,660.4	$	1,693.0	$	1,038.8

PROVED OIL AND NATURAL GAS RESERVE QUANTITIES

	2005		2004		2003
	Crude Oil and Natural Gas Liquids	Natural Gas	Crude Oil and Natural Gas Liquids	Natural Gas	Crude Oil and Natural Gas Liquids	Natural Gas
	(mbbls)	(mmcf)	(mbbls)	(mmcf)	(mbbls)	(mmcf)
Opening balance	27,799	422,227	25,643	272,897	25,989	279,106
Revision of previous estimates	891	992	(806)	2,640	225	(33,640)
Purchase of reserves in place	-	148	6,940	180,914	1,640	50,389
Sale of reserves in place	(72)	(1,913)	(2,120)	(8,027)	(28)	(803)
Discoveries and extensions	1,400	38,088	791	16,018	941	14,742
Production	(3,114)	(49,535)	(2,649)	(42,215)	(3,124)	(36,897)
Closing balance	26,904	410,007	27,799	422,227	25,643	272,897

MANAGEMENT’S DISCUSSION AND ANALYSIS–PRIMEWEST ENERGY TRUSTANNUAL REPORT 2005

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 natural gas reserves is based on current costs and prices and a ten percent 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 natural 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)	2005		2004		2003
Future cash inflows	$	6,072.0	$	4,187.1	$	2,631.1
Future production costs		(1,371.3)		(1,186.6)		(804.9)
Future development costs		(123.1)		(72.0)		(69.4)
Other related future costs		(40.7)		(37.1)		(42.1)
Future net cash flows		4,536.9		2,891.4		1,714.7
Discount at 10%		(1,999.1)		(1,242.7)		(721.6)
Standardized measure of discounted future net cash flow related to Proved Reserves	$	2,537.8	$	1,648.7	$	993.1

Summary of Changes in the Standardized Measure During The Year  ($ millions)	2005		2004		2003
Sales of oil and natural gas produced, net of production costs	$	(459.9)	$	(312.2)	$	(255.0)
Net change in sales and transfer prices, net of development and production costs		987.1		144.4		(106.2)
Sales of reserves in place		(10.4)		(54.4)		(2.3)
Purchases of reserves in place		0.5		630.4		156.4
Extensions, discoveries and improved recovery, less related costs		223.0		106.7		48.5
Changes in timing of future net cash flows and other		(12.5)		37.1		(60.6)
Revisions of previous quantity estimates		(3.6)		4.3		(58.5)
Accretion of discount		164.9		99.3		115.5
Net change		889.1		655.6		(162.2)
Balance at beginning of year		1,648.7		993.1		1,155.3
Balance at end of year	$	2,537.8	$	1,648.7	$	993.1

PRIMEWEST ENERGY TRUSTANNUAL REPORT 2005–MANAGEMENT’S DISCUSSION AND ANALYSIS

TRADING PERFORMANCE

For the Quarter Ended	Dec 31/05		Sep 30/05		Jun 30/05		Mar 31/05		Dec 31/04
TSX Trust Unit Prices ($ per Trust Unit)
High	$	37.68	$	36.42	$	31.68	$	32.00	$	28.33
Low	$	30.55	$	30.86	$	28.35	$	26.15	$	25.06
Close	$	35.90	$	36.40	$	30.66	$	28.99	$	26.62
Average daily traded volume		199,849		183,469		202,225		269,714		255,944

For the quarter ended	Dec 31/05		Sep 30/05		Jun 30/05		Mar 31/05		Dec 31/04
NYSE Trust Unit Prices (US$ per Trust Unit)
High	$	32.57	$	31.37	$	25.59	$	26.60	$	22.98
Low	$	25.71	$	25.15	$	22.50	$	21.30	$	20.85
Close	$	30.92	$	31.33	$	25.05	$	23.96	$	22.18
Average daily traded volume		480,603		445,338		377,264		536,170		542,483
Number of Trust Units outstanding
including Exchangeable Shares (millions of Trust Units)		80.4		79.1		77.2		72.9		70.5
Distribution paid per Trust Unit	$	0.96	$	0.90	$	0.90	$	0.90	$	0.90

TOTAL COMPOUND ANNUAL RETURN (%)⁽¹⁾

	PrimeWest	TSX Oil & Gas Index	TSX S&P	S&P 500 Cdn$	S&P 500 US$	S&P/TSX CDN Energy Trust Index
Five year	19.0	25.8	6.7	(4.5)	0.5	30.7
Three year	28.6	38.5	21.7	3.7	13.2	41.8
One year	51.4	63.7	24.3	1.5	4.9	49.5

(1)

Total return = Unit price plus distributions re-invested.

MANAGEMENT’S DISCUSSION AND ANALYSIS–PRIMEWEST ENERGY TRUSTANNUAL REPORT 2005

FIVE YEAR FINANCIAL SUMMARY

($ millions, except per BOE and per Trust Unit amounts)	2005		2004		2003			2002		2001
Cash flow from operations	$	414.1	$	266.8		$	216.6	$	170.9	$	214.5
Per Trust Unit		5.16		4.33			4.67		4.96		8.27
Per BOE		28.11		20.49			17.82		15.51		19.74
Net revenues		604.4		402.8			338.2		270.6		311.5
Per Trust Unit		7.32		6.38			7.30		7.85		12.00
Per BOE		41.04		30.93			27.82		24.55		28.66
Operating expenses		117.0		88.9			79.4		60.8		59.0
Per Trust Unit		1.42		1.41			1.71		1.76		2.27
Per BOE		7.94		6.83			6.53		5.52		5.42
Operating margin		464.6		305.6			250.5		203.5		247.6
Per Trust Unit		5.63		4.84			5.41		5.90		9.54
Per BOE		31.54		23.47			20.61		18.46		22.78
Cash G&A		22.9		19.0			14.5		11.3		10.4
Per Trust Unit		0.28		0.30			0.31		0.33		0.40
Per BOE		1.56		1.46			1.20		1.02		0.96
Interest expense		28.3		20.6			15.1		10.8		13.8
Per Trust Unit		0.34		0.33			0.32		0.32		0.53
Per BOE		1.92		1.58			1.24		0.98		1.27
Development capital expenditures		185.6		125.1			104.5		64.2		83.9
Acquisitions net of dispositions		(17.9)		707.9			228.6		56.5		744.5
Working capital surplus/(deficit)(1)		30.5		104.3			(5.8)		(0.7)		(29.4)
Total assets		2,131.9		2,240.9			1,690.5		1,511.5		1,530.0
Net asset value		2,565.1		1,541.2			692.4		727.9		755.2
Per Trust Unit		30.64		19.15			13.74		18.52		22.82
Total capitalization (including debt)		3,208.4		2,429.7			1,636.6		1,072.5		1,080.7
Debt Analysis
Long-term debt, including working capital		323.7		552.0			255.9		225.7		224.4
Debt to annual cash flow ratio		0.8		1.70			1.18		1.32		1.05
Debt to equity ratio		19.2		31.6			25.1		26.6		26.2
Interest coverage ratio		15.6		14.2			15.9		16.9		16.5
Average cost of debt		5.2%		4.8%			4.7%		4.6%		5.4%
Net debt per Trust Unit		3.97		7.77			5.07		5.75		6.78
Tax Pools (Consolidated)
Canadian Oil And Gas Property Expense (COGPE)		825.0		879.0			426.0		425.0		424.0
Canadian Exploration Expense (CEE)		9.8		79.8			61.5		–		23.7
Canadian Development Expense (CDE)		156.0		109.5			60.9		41.2		11.1
Capital Cost Allowance (CCA)		325.1		281.8			126.0		108.0		101.2
Losses Available For Carry Forward		3.6		3.6			–		11.8		24.8
Unit issue expenses		24.9		37.5			17.3		12.5		12.2

(1)

Excludes derivative liabilities and assetsand future income tax assets

PRIMEWEST ENERGY TRUSTANNUAL REPORT 2005–MANAGEMENT’S DISCUSSION AND ANALYSIS

FIVE YEAR OPERATING SUMMARY

		2005		2004		2003		2002		2001
Average Daily Production
Natural gas (mmcf/day)		178.2		145.1		134.1		113.5		104.8
Crude oil (bbls/day)		6,861		8,282		8,116		9,239		10,033
Natural gas liquids (bbls/day)		3,797		3,107		2,855		2,030		2,273
Total (BOE/day)		40,351		35,578		33,316		30,189		29,774
Average Selling Prices (Cdn$)
Natural gas ($/mcf)	$	8.43	$	6.61	$	6.05	$	4.55	$	6.16
Crude oil ($/bbl)		49.05		36.83		33.94		33.53		32.21
Natural gas liquids ($/bbl)		55.92		43.69		35.34		26.56		30.96
Total ($/BOE)	$	50.81	$	39.35	$	35.63	$	29.16	$	34.80
Benchmark Prices
Monthly AECO Spot (Cdn$/mcf)	$	8.04	$	6.79	$	6.70	$	4.07	$	6.30
W.T.I. (US$/bbl)	$	56.56	$	41.40	$	31.04	$	26.08	$	25.97
Operating Margin ($/BOE)
Revenues	$	51.21	$	39.50	$	35.52	$	29.11	$	34.93
Royalties		(11.73)		(9.20)		(8.38)		(5.13)		(6.73)
Operating expenses		(7.94)		(6.83)		(6.53)		(5.52)		(5.42)
Operating margin ($/BOE)	$	31.54	$	23.47	$	20.61	$	18.46	$	22.78
Reserves Summary(1,2)
Crude oil (mmbbls)		23.6		23.9		22.9		24.5		28.5
Natural gas liquids (mmbbls)		18.1		18.3		11.9		10.2		9.5
Natural gas (bcf)		677.3		677.9		432.2		418.5		413.7
Total BOE (mmBOE)		154.6		155.2		106.8		104.4		107.0
Net Asset Value ($ millions, except per Trust Unit amounts)
Reserves (10% discount)(3)	$	2,684.0	$	1,714.4	$	904.6	$	923.0	$	872.6
Market value of Viking Energy Royalty Trust Units		-		91.0		-		-		-
Hedging mark-to-market		(11.5)		0.1		(0.5)		(13.6)		50.5
Unproved lands and reclamation fund		160.5		114.2		44.2		44.2		56.5
Long-term debt and working capital		(267.9)		(378.5)		(255.9)		(225.7)		(224.4)
Total net asset value	$	2,565.1	$	1,541.2	$	692.4	$	727.9	$	755.2
Per Trust Unit – Diluted	$	30.64	$	19.15	$	13.74	$	18.52	$	22.82
Reserve Life Index(2) (years)		11.0		10.3		9.8		9.5		10.0

(1)

Company Interest reserves.

(2)

Total Proved plus Probable used for 2005, 2004 and 2003, all prior years used Established.

(3)

Company Interest Proved plus Probable reserves.

MANAGEMENT’S DISCUSSION AND ANALYSIS–PRIMEWEST ENERGY TRUSTANNUAL REPORT 2005

FIVE YEAR TRADING, PERFORMANCE AND DISTRIBUTION SUMMARY

					2005
					Q1					Q2							Q3							Q4				Full Year						2004					2003				2002				2001
Units Issued and Outstanding
Period end (000s)								72,238						76,520							78,412					79,666					79,666					69,886					48,752				37,005				31,492
Exchangeable Shares Issued and Outstanding
Period end (000s)								1,226						1,221							1,221					1,219					1,219					1,294					3,041				5,179				4,068
Converted to Trust Units								637						654							671					688					688					652					1,347				1,940				1,294
Exchange ratio at period end								0.51956						0.53538							0.54957					0.56399					0.56399					0.50408					0.44302				0.37454				0.31799
TSX Unit Price ($)
High					$			32.00		$				31.68			$				36.42			$		37.68		$			37.68			$		28.35			$		28.15		$		29.56		$		42.16
Low					$			26.15		$				28.35			$				30.86			$		30.55		$			26.15			$		22.18			$		23.40		$		23.60		$		23.80
Close					$			28.99		$				30.66			$				36.40			$		35.90		$			35.90			$		26.62			$		27.56		$		25.40		$		25.44
Average daily traded volume								269,714						202,225							183,469					199,849					213,656					233,579					192,678				123,455				156,122
Market capitalization at end of       period  ($ millions)																															2,885					1,878					1,381				989				834
Total return for Canadian      Unitholders during period																															51.4%					9.7%					28.0%				19.5%				(5.8%)
NYSE Unit Price (US$)
High					$			26.60		$				25.59			$				31.37			$		32.57		$			32.57			$		22.98			$		21.48		$		16.69				n/a
Low					$			21.30		$				22.50			$				25.15			$		25.71		$			21.30			$		16.00			$		15.97		$		15.62				n/a
Close					$			23.96		$				25.05			$				31.33			$		30.92		$			30.92			$		22.18			$		21.27		$		16.16				n/a
Average daily traded volume								536,170						377,264							445,338					480,603					458,853					402,694					169,269				39,276				n/a
Total return for U.S. Unitholders      during period																															56.6%					18.5%					55.3%				n/a				n/a
Distribution Summary ($ millions, except per Trust Unit amounts)
Cash distributed to Unitholders					$		63.8			$			66.5			$				70.1			$			76.2		$		276.6			$			196.1		$			192.6		$		158.0		$		234.4
Per Trust Unit					$		0.90			$			0.90			$				0.90			$			0.96		$		3.66			$			3.30		$			4.32		$		4.80		$		9.84
Percentage paid out							80%						70%							66%						58%				67%						74%					89%				92%				109%
Cumulative cash distributions					$		1,031.5			$			1,098.0			$				1,168.1			$			1,244.3		$		1,244.3			$			967.7		$			771.5		$		578.9		$		420.9
Per Trust Unit					$		44.44			$			45.34			$				46.24			$			47.20		$		47.20			$			43.54		$			40.24		$		35.92		$		31.12
	Distribution History ($ per Trust Unit)
				2005								2004													2003										2002									2001
	Funds paid in:	Cdn$				US$						Cdn$							US$						Cdn$				US$						Cdn$					US$				Cdn$				US$
	Q1	$	0.90			$			0.74		$				0.82			$				0.62					1.20		$			0.81			$		1.20			$		0.75		$		2.40		$		1.56
	Q2		0.90						0.72						0.75							0.55					1.20					0.87					1.20					0.77				2.56				1.66
	Q3		0.90						0.76						0.83							0.64					0.96					0.70					1.20					0.77				2.64				1.71
	Q4		0.96						0.82						0.90							0.74					0.96					0.73					1.20					0.76				2.04				1.31
	Total for year	$	3.66			$			3.04		$				3.30			$				2.55					4.32		$			3.12			$		4.80			$		3.05		$		9.64		$		6.24
	% Tax-deferred		25%						18.75%						45%							55%					42%					100%					45%					100%				33%				n/a
	Exchange Rate  (US$/Cdn$)	$	0.829								$				0.769										$		0.715								$		0.637							$		0.646

PRIMEWEST ENERGY TRUSTANNUAL REPORT 2005–MANAGEMENT’S DISCUSSION AND ANALYSIS

THREE YEAR DISTRIBUTION HISTORY

2003	Distribution per Trust Unit(1) Cdn$	Distribution Per Trust Unit(1) US$
January	$  0.40	$ 0.2600
February	0.40	0.2700
March	0.40	0.2800
April	0.40	0.2890
May	0.40	0.2990
June	0.40	0.2870
July	0.32	0.2300
August	0.32	0.2300
September	0.32	0.2400
October	0.32	0.2460
November	0.32	0.2400
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	0.1830
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
2005
January	0.30	0.2468
February	0.30	0.2438
March	0.30	0.2486
April	0.30	0.2406
May	0.30	0.2370
June	0.30	0.2424
July	0.30	0.2458
August	0.30	0.2501
September	0.30	0.2532
October	0.30	0.2531
November	0.30	0.2516
December	0.36	0.2587
Total 2005	$  3.66	$  2.9717

(1)

Monthly information refers to the month in which the distributions are declared with payment being made on or about the 15^th day of the following month.

MANAGEMENT’S DISCUSSION AND ANALYSIS–PRIMEWEST ENERGY TRUSTANNUAL REPORT 2005

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 later 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 the taxable portion, or other income, as it is regarded under Canadian tax law in box 26 and the return of capital portion in box 42. The 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 the cost base (ACB) of the Units. On dispos ition, the cost base should be reduced by the accumulated value of returned capital, resulting in a capital gain or loss for tax purposes.

For 2005, 25% of the distributions paid to Canadian residents were deemed a tax-deferred return of capital, and 75% was deemed taxable as other income. For the tax year 2006, PrimeWest’s distributions payable to Canadian residents are estimated to be 80% taxable and 20% 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, U.S. 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. U.S. 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. U.S. investors are cautioned that the administrative protocol required to apply for the refund is burdensome, and they will require the ass istance of their broker or tax advisor.

Alternatively, U.S. Unitholders may elect to claim a portion of the Canadian tax withheld on distributions paid during 2005 as a deduction against income, or, subject to certain restrictions, as a credit against their U.S. tax liability. U.S. Unitholders wishing to claim a foreign tax credit must complete IRS Form 1116, “Foreign Tax Credit” as an attachment to the Form 1040.

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 U.S. Unitholders compared to those in Canada. For Unitholders resident in the United States, the taxability of distributions is derived using U.S. tax rules, which permit the deduction of Crown royalties and accounting-based depletion. In the case of a U.S. 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 U.S. Unitholders should receive a CRA Form NR-4 from t he Trust’s transfer agent, Computershare Trust Company of Canada. U.S. Unitholders who hold their Units beneficially should receive an IRS Form 1099-DIV or similar document from their bank or brokerage firm. As a result of the foregoing rules, in the case of a U.S. resident, 81.25% of the distributions paid by PrimeWest during 2005 should be treated as a “qualified dividend” with the remaining 18.75% treated as a tax-deferred return of capital. 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.

PRIMEWEST ENERGY TRUSTANNUAL REPORT 2005–MANAGEMENT’S DISCUSSION AND ANALYSIS

PREMIUM DISTRIBUTION, DISTRIBUTION REINVESTMENT AND OPTIONAL TRUST UNIT PURCHASE PLAN

PrimeWest offers a number of attractive and economical options for Unitholders to maximize their investment in PrimeWest, including a Premium Distribution (PREP), Conventional 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.

Canadian Unitholders

The Premium Distribution (PREP), Distribution Reinvestment (DRIP) and Optional Trust Unit Purchase Plans (OTUPP) provide eligible holders of Trust Units that are resident in Canada the opportunity to either receive a premium cash payment in lieu of the cash distribution declared payable by PrimeWest or accumulate additional Trust Units at a 5% discount to the weighted average market price. Participants that are resident in Canada may also purchase additional Trust Units at the same 5% discount by investing additional sums within the limits and subject to the terms of the Plan.

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 Trust 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 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 that 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.

United States Unitholders

The DRIP plan is now available to Unitholders resident in the United States and provides the opportunity to accumulate additional Trust Units at a 5% discount to the Average Market Price.Unitholders that are resident in the United States are not eligible to receive the premium cash payment under the PREP or to make optional cash payments under the OTUPP to purchase additional Trust Units pursuant to the Plan.

Please contact the brokerage firm that holds your account to determine if they permit participation in the DRIP. 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.

Additional Information

We invite you to participate in these programs by completing the enrollment form on the PrimeWest website atwww.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 toll-free at 1-800-564-6253, or the Investor Relations group at PrimeWest toll-free at 1-877-968-7878, or via e-mail atinvestor@primewestenergy.com.

MANAGEMENT’S DISCUSSION AND ANALYSIS–PRIMEWEST ENERGY TRUSTANNUAL REPORT 2005

DEFINITIONS

AECO

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

ARTC

Means the Alberta royalty tax credit.

Cash Distribution Date

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

Circular

Refers to the Trust’s Management Proxy Circular, dated March 15, 2006.

Company Interest

Refers to, in relation to PrimeWest’s interest in production or Reserves, its working interest (operating or non operating) share before deduction of royalties and including royalty interests of PrimeWest and the Trust.

Credit Facility

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

Distributable Income

Refers to all amounts received by the Trust in respect of the Royalty, ARTC, the gross overriding royalties held by the Trust direct and other income, less certain expenses and other deductions.

EDGAR

Means the Electronic Data Gathering, Analysis and Retrieval System on which submissions by companies and others required by law to file forms with the U.S. Securities and Exchange Commission are filed and accessible at www.sec.gov.

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.

GAAP

Means Generally Accepted Accounting Principles.

General and Administrative Costs

The amount in aggregate representing all expenditures and costs incurred by or in respect of PrimeWest in the management and administration of PrimeWest.

GLJ

Means GLJ Petroleum Consultants, Ltd.

GLJ Report

Means the reserve report dated January 23, 2006, prepared by GLJ, evaluating the light and medium oil, heavy oil and associated and non-associated gas reserves attributable to properties owned by the Trust as at December 31, 2005.

Gross

Refers to the Trust’s “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; or in relation to wells, the total number of wells in which PrimeWest has an interest; or in relation to properties, the total area of properties in which PrimeWest has an interest.

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 its working interest.

NI 51-101

Means National Instrument 51-101, Standards of Disclosure for Oil and Gas Activities of the Canadian Securities Commissions.

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.

Production

Refers to recovering, gathering, treating, field or plant processing and field storage of oil and natural gas.

Production Costs

Costs incurred to operate and maintain wells and related equipment and facilities, including applicable operating costs of support equipment and facilities and other cost of operating and maintaining those wells and related equipment and facilities. Lifting costs become part of the cost of oil and natural gas produced.

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.

SEDAR

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

Standard and Poors (S&P)

Refers to Standard and Poors, a division of the McGraw-Hill Companies, Inc.

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

Unproved Properties

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

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.

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

PRIMEWEST ENERGY TRUSTANNUAL REPORT 2005–MANAGEMENT’S DISCUSSION AND ANALYSIS

PRIMEWEST 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.

Effective January 1, 2006, PrimeWest Gas Corp. amalgamated into PrimeWest Energy Inc.

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 Agreement. 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.

MANAGEMENT’S DISCUSSION AND ANALYSIS–PRIMEWEST ENERGY TRUSTANNUAL REPORT 2005

CORPORATE INFORMATION

Registrar and Transfer Agent

Computershare Trust Company of Canada

Toll-free:  1-800-564-6253

Auditors

PricewaterhouseCoopers, LLP

Calgary, Alberta

Engineering Consultants

GLJ Petroleum Consultants Ltd.

Calgary, Alberta

Legal Counsel

Stikeman Elliott, LLP

Calgary, Alberta

Trust Units

The Toronto Stock Exchange:  PWI.UN

The New York Stock Exchange:  PWI

Exchangeable Shares

The Toronto Stock Exchange:  PWX

Convertible Debentures

The Toronto Stock Exchange:  

Series I Debentures:  PWI.DB.A

Series II Debentures:  PWI.DB.B

For More Information

General Inquiries:  (403) 234-6600

Investor Relations

Toll-free:  1-877-968-7878

Fax:  (403) 699-7477

Email:  investor@primewestenergy.com

For additional information, please visit our website at:

www.primewestenergy.com