Primewest Energy Trust 40F 2006 Annual report | PWI Filing

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

MANAGEMENT’S DISCUSSION AND ANALYSIS

THE FOLLOWING IS MANAGEMENT’S DISCUSSION AND ANALYSIS (MD&A) AS AT FEBRUARY 23, 2006, OF PRIMEWEST ENERGY TRUST’S (REFERRED TO HEREINAFTER AS PRIMEWEST OR THE TRUST) OPERATING AND FINANCIAL RESULTS FOR THE YEAR ENDED DECEMBER 31, 2005, THE CORRESPONDING PERIOD IN THE PRIOR YEAR AS WELL AS INFORMATION AND OPINIONS CONCERNING THE TRUST’S OUTLOOK BASED ON CURRENTLY AVAILABLE INFORMATION. THIS DISCUSSION SHOULD BE READ IN CONJUNCTION WITH THE TRUST’S AUDITED CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEARS ENDED DECEMBER 31, 2005 AND 2004, TOGETHER WITH ACCOMPANYING NOTES.


Financial($ millions, except per BOE⁽¹⁾ and Per Trust Unit amounts)	2005		2004		Change (%)
Gross revenue, net of transportation expense	$	749.7	$	513.7	46
Per BOE		50.90		39.45	29
Cash flow from operations		414.1		266.8	55
Per BOE		28.11		20.49	37
Per Trust Unit – Basic ⁽²⁾		5.46		4.49	22
Per Trust Unit – Diluted ⁽³⁾		5.16		4.33	19
Royalty expense		172.8		119.8	44
Per BOE		11.73		9.20	28
Operating expense		117.0		88.9	32
Per BOE		7.94		6.83	16
Cash general and administrative expense		22.9		19.0	21
Per BOE		1.56		1.46	7
Non-cash general and administrative expense⁽⁴⁾		5.4		4.1	32
Per BOE		0.37		0.32	16
Interest expense⁽⁵⁾		28.3		20.6	37
Per BOE		1.92		1.58	22
Net income		207.5		105.4	97
Per Trust Unit – Basic⁽²⁾		2.73		1.77	54
Per Trust Unit – Diluted ⁽³⁾		2.66		1.77	50
Distributions to Unitholders		276.6		196.1	41
Per Trust Unit⁽⁶⁾		3.66		3.30	11
Net debt⁽⁷⁾		323.7		552.0	(41)
Per Trust Unit⁽⁸⁾		3.97		7.77	(48)

(1)

All calculations required to convert natural gas to a crude oil equivalent (BOE) have been made using a ratio of 6,000 cubic feet of natural gas to one barrel of crude oil. BOE’s may be misleading, particularly if used in isolation. The BOE conversion ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not necessarily represent a value equivalency at the wellhead.

(2)

The basic per Trust Unit calculation includes the weighted average Trust Units outstanding and Trust Units issuable upon exchange of the outstanding Exchangeable Shares of PrimeWest Energy Inc. (Exchangeable Shares).

(3)

The diluted per Trust Unit calculation includes the weighted average Trust Units outstanding, Trust Units issuable upon exchange of the outstanding Exchangeable Shares, the deemed conversion of the Convertible Unsecured Subordinated Debentures (Debentures) and Trust Units issuable pursuant to the Long-Term Incentive Plan (LTIP). Interest expense incurred on the Debentures is added back to net income and to cash flow for the diluted per Trust Unit calculation.

(4)

Non-cash general and administrative expense has been restated to reflect the change in method of accounting for its unit-based compensation. See note 3 to the Consolidated Financial Statements.

(5)

Interest expense includes the interest on the Debentures.

(6)

Based on Trust Units outstanding at the Record Date.

(7)

Net debt is long-term debt including Debentures less working capital, excluding financial derivative assets and liabilities and current future income tax assets.

(8)

The net debt per Trust Unit calculation includes outstanding Trust Units, Trust Units issuable upon exchange of the outstanding Exchangeable Shares and Trust Units issuable pursuant to the LTIP at the end of the period.


Daily Production Volumes	2005		2004		Change (%)
Daily sales volume
Natural gas (mmcf/day)	178.2		145.1		23
Crude oil (bbls/day)	6,861		8,282		(17)
Natural gas liquids (bbls/day)	3,797		3,107		22
Total (BOE/day)	40,351		35,578		13
Realized Commodity Prices (Cdn$)		2005		2004	Change (%)
Natural gas ($/mcf)^{(1) (2)}		8.43		6.61	28
Without hedging		8.75		6.70	31
Crude oil ($/bbl)⁽¹⁾		49.05		36.83	33
Without hedging		58.48		44.46	32
Natural gas liquids ($/bbl)		55.92		43.69	28
Total ($/BOE)⁽¹⁾		50.81		39.35	29
Without hedging		53.82		41.51	30

(1)

Includes realized hedging losses.

(2)

Excludes sulphur.

Forward-Looking Information

This annual report contains forward-looking or outlook information with respect to PrimeWest.

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

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

In particular, this annual report, and the documents incorporated by reference, contain forward-looking statements pertaining to the following:

The quantity and recoverability of our reserves;

The timing and amount of future production;

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

Operating and other costs;

Business strategies and plans of management;

Supply and demand for oil and natural gas;

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

Our treatment under governmental regulatory regimes;

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

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

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

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

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

Drilling plans;

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

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

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

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

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

The emergence of accretive growth opportunities; and

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

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

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

The cost of expanding our property holdings;

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

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

The impact of increasing competition;

Our ability to obtain financing on acceptable terms; and

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

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

Volatility in market prices for oil and natural gas;

The impact of weather conditions on seasonal demand;

Risks inherent in our oil and natural gas operations;

Uncertainties associated with estimating reserves;

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

Incorrect assessments of the value of acquisitions;

Geological, technical, drilling and processing problems;

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

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

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

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

Fluctuation in foreign exchange or interest rates;

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

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

Stock market volatility and market valuations;

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

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

The need to obtain required approvals from regulatory authorities; and

The other factors discussed under Risk Factors contained this annual report.

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

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

All figures reported in Canadian dollars unless otherwise stated.

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

Evaluation of Disclosure Controls and Procedures

The Chief Executive Officer, Don Garner, and the Chief Financial Officer, Dennis Feuchuk, evaluated the effectiveness of PrimeWest’s disclosure controls and procedures as of December 31, 2005, and concluded that PrimeWest's disclosure controls and procedures were effective to ensure that information PrimeWest is required to disclose:

In its annual filings, interim filings or other reports (each as defined in National Instrument 52-109 of the Canadian Securities Administrators) filed or submitted by it under provincial securities legislation is recorded, processed, summarized and reported within the time periods specified in the provincial securities legislation and to ensure that information required to be disclosed by PrimeWest in its annual filings, interim filings or other reports filed or submitted under provincial securities legislation is accumulated and communicated to PrimeWest’s management, including its chief executive officer and chief financial officer, as appropriate to allow timely decisions regarding required disclosure; and

In its annual filings, interim filings or other reports with the United States Securities and Exchange Commission (SEC) in the United States under the Securities Exchange Act of 1934 (Exchange Act) is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms, and to ensure that information required to be disclosed by PrimeWest in the reports that it files under the Exchange Act is accumulated and communicated to PrimeWest’s management, including its principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.

The evaluation took into consideration PrimeWest’s Communications and Disclosure Policy and the functioning of its executive officers, board of directors and board committees. In addition, the evaluation covered PrimeWest’s processes, systems and capabilities relating to regulatory filings, public disclosures and the identification and communication of material information.

Changes to Internal Controls Over Financial Reporting

There were no changes to PrimeWest’s internal control over financial reporting since September 30, 2005 that have materially affected, or are reasonably likely to materially affect PrimeWest’s internal control over financial reporting.

Non-GAAP Measures

This annual report contains the following measurements that are not defined by Canadian Generally Accepted Accounting Principles (GAAP):

Cash flow from operations on a total and per Trust Unit basis;

Distributions per Trust Unit; and

Net debt per Trust Unit.

These measurements do not have any standardized meaning prescribed by GAAP and are, therefore, unlikely to be comparable to similar measures presented by other entities.

Cash flow from operations is calculated from the Trust’s cash flow statement as cash flow from operating activities before changes in working capital. Cash flow from operations per Trust Unit on a basic basis is calculated by dividing cash flow by the weighted average number of Trust Units outstanding plus Trust Units issuable upon the exchange of the outstanding Exchangeable Shares of PrimeWest Energy Inc. (Exchangeable Shares). Cash flow from operations per Trust Unit on a diluted basis is calculated using cash flow and adding back the interest expense on the Convertible Unsecured Subordinated Debentures (Debentures), divided by the diluted weighted average number of Trust Units outstanding in the period. The diluted weighted average number of Trust Units outstanding consists of the weighted average Trust Units plus Trust Units issuable upon the exchange of outstanding Exchangeable Shares and includes the Trust Units issuable pursuant to the conversion of the Debentures, and Trust Units issuable pursuant to PrimeWest’s Long-Term Incentive Plan (LTIP). Cash flow from operations is a key performance indicator of PrimeWest’s ability to generate cash and finance operations and pay monthly distributions.

Distributions per Trust Unit disclose the cash distributions accrued in 2005 based on the number of Trust Units outstanding on the Record Date.

Net debt per Trust Unit is calculated as long-term debt, including Debentures, less working capital, excluding financial derivative assets and liabilities and current future income tax assets divided by the number of Trust Units outstanding and Trust Units issuable upon the exchange of outstanding Exchangeable Shares and Trust Units issuable pursuant to the LTIP at December 31, 2005.

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

Business Strategy

PrimeWest Energy Trust is a conventional oil and natural gas royalty trust actively managed to generate monthly cash distributions for Unitholders. The Trust’s operations are focused in Canada, with its assets concentrated in the Western Canada Sedimentary Basin. PrimeWest is one of North America’s largest natural gas-weighted energy trusts.

Maximizing total return to Unitholders, in the form of cash distributions and appreciation in unit price, is PrimeWest’s overriding objective. Our strategies for asset management and growth, financial management and corporate governance are outlined in this annual report along with a discussion of our performance in 2005 and our goals for 2006 and beyond.

We believe that PrimeWest can maximize total return to Unitholders by continuing to develop our core properties, making opportunistic acquisitions that emphasize value creation, exercising disciplined financial management which broadens access to capital while minimizing risk to Unitholders, and complying with strong corporate governance principles to protect the interests of all stakeholders.

Asset Management and Growth

PrimeWest has a strategy to focus expansion efforts on existing Canadian core areas and pursue depletion optimization strategies within those core areas to maximize asset value. We make every effort to obtain operatorship of our asset base and maintain high working interests in core areas. We currently maintain operatorship of 80% of our assets, which allows us to use existing infrastructure and synergies within our core areas. We believe this high level of control can translate into cost efficiencies and timing of capital outlays and projects. The current size of the Trust gives us the ability and critical mass to make acquisitions of significant size, while being able to add value by transacting smaller acquisitions.

Financial Management

PrimeWest strives to maintain a prudent debt position, to allow us to fund smaller acquisitions and to fund ongoing development activities without tapping the capital markets. Our long-term debt is comprised of bank credit facilities through a bank syndicate, U.S.-dollar-denominated Senior Secured Notes (Secured Notes) and the Debentures. Our diversified debt instruments help to reduce our reliance on the bank syndicate. PrimeWest’s commodity hedging approach is intended to help to stabilize cash flow, reduce volatility and, when applicable protect near-term acquisition economics.

Since August 2003, PrimeWest has followed a strategy of maintaining a distribution payout ratio of approximately 70-90% of cash flow, calculated on an annual basis. The strength in commodity prices has increased the Trust’s cash flow from operations available for distribution to Unitholders. The Board of Directors of PrimeWest will continue to consider a variety of factors in establishing the monthly distribution level. These factors include, but are not limited to: commodity price outlook, cash flow forecast, capital development plans, debt levels, tax considerations and competitive industry distribution practices.

The 2005 payout ratio was approximately 67% of annual operating cash flow. The retained cash flow was utilized to fund the Trust’s capital spending program and repay debt. PrimeWest’s net debt to cash flow ratio was 0.8 times at December 31, 2005 using 2005 annual cash flows.

PrimeWest’s dual listing on the Toronto Stock Exchange (TSX) and New York Stock Exchange (NYSE) provides increased liquidity and a broadened investor base. The NYSE listing enables U.S. Unitholders to conveniently trade in our Trust Units, and allows us to access the U.S. capital markets in the future. Our status as a corporation for U.S. tax purposes simplifies tax reporting for our U.S. Unitholders.

For eligible Canadian and U.S. Unitholders, PrimeWest offers participation in the conventional Distribution Reinvestment Plan (DRIP), which represents a convenient way to maximize an investment in PrimeWest. Canadian residents may also participate in the Optional Trust Unit Purchase Plan (OTUPP) and the Premium Distribution Plan (PREP). For alternate investment requirements, PrimeWest also has Exchangeable Shares and Debentures available, which permit participation in PrimeWest without the ongoing tax implications associated with receiving a distribution.

Corporate Governance

PrimeWest remains committed to high standards of corporate governance and upholds the rules of the governing regulatory bodies under which it operates. Full disclosure of our compliance with existing corporate governance rules and regulations is contained in the Trust’s Management Proxy Circular and is available on our website atwww.primewestenergy.com. PrimeWest actively monitors the corporate governance and disclosure environment to ensure compliance with current and future requirements.

Our high standards of corporate governance are not limited to the boardroom. At the field level, PrimeWest proactively manages environmental, health and safety issues. We place a great deal of importance on community involvement and maintaining good relationships with landowners.

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

Financial and Operating Highlights

Production in 2005 averaged 40,351 BOE/day, up by 13% from the 2004 level of 35,578 BOE/day, as a result of the Calpine acquisition in the third quarter of 2004 and development capital volume additions, partially offset by minor asset divestments transacted in December 2004 and natural production declines.

Operating margin increased to $31.54/BOE for 2005, up by 25% from 2004 primarily due to higher commodity prices throughout the year, offset by the impact of the commodity hedging program as well as higher operating costs and royalties in 2005.

Distributions of $3.66 per Trust Unit in 2005 compared to $3.30 per Trust Unit in 2004. The distribution level was increased in December 2005 by 20% from $0.30 per Trust Unit monthly to $0.36 per Trust Unit monthly. PrimeWest’s payout ratio for 2005 was approximately 67% compared to the 2004 payout ratio of 74%. The 2005 lower payout ratio reflects the increases in cash flow due to increased commodity prices and retention of cash to fund development capital opportunities as well as reducing outstanding bank debt.

Capital development program of $185.6 million added 14.7 mmBOE of Proved plus Probable reserves (including technical revisions) on a Company Interest basis at an average of $12.63/BOE of reserves added, which excludes $4.22/BOE for future development capital. The capital development program replaced 100% of the 2005 production on a Proved plus Probable basis by reinvesting approximately 45% of cash flow from operations.

PrimeWest’s Reserve Life Index (RLI) at year-end 2005 is 11.0 years on a Company Interest Proved plus Probable basis. (Refer to the Disclosure of Oil and Natural Gas Reserves section later in this annual report for reserve definitions).

Operating expenses were 32% higher in 2005 than in 2004, reflecting higher production volumes and higher industry-wide cost pressures. On a unit of production basis, operating expenses were 16% higher than in 2004 at $7.94/BOE versus $6.83/BOE.

Cash general and administrative expense (G&A) increased $3.9 million over 2004 reflecting increases in labour costs, information technology expenses, office rent and property taxes associated with additional staffing and office space requirements resulting from the 2004 Calpine asset acquisition.

Interest expense during 2005 was 37% higher than in 2004 due to a higher average net debt balance and higher interest rates during the year resulting from the issuance of the Debentures in the third quarter of 2004 to acquire the Calpine assets.

The Distribution Reinvestment, Premium Distribution and Optional Trust Unit Purchase Plans contributed $55.7 million of equity capital to be reinvested in the capital development program and to repay debt.

Outlook 2006

PrimeWest expects 2006 production volumes to average approximately 38,000–39,000 BOE/day. Full-year operating costs are expected to be approximately $8.00/BOE. PrimeWest expects to invest approximately $275 million in its 2006 capital development program, with the focus primarily in the core areas of Caroline, Columbia, Wilson Creek, Crossfield and Brant Farrow.

Cash Flow Reconciliation


($ millions)
2004 cash flow from operations	$	266.8
Production volumes		67.3
Commodity prices		184.8
Net hedging change		(16.1)
Operating expense		(28.1)
Royalties		(53.0)
Interest expense		(7.7)
Other		0.1
2005 cash flow from operations	$	414.1
The above table includes non-GAAP measurements (refer to discussion on non-GAAP measures on page 24).

The key performance driver for the Trust is cash flow from operations, which directly affects PrimeWest’s ability to pay monthly distributions. Cash flow is generated through the production and sale of crude oil, natural gas and natural gas liquids, and is dependent on production levels, commodity prices, operating expenses, interest expenses, G&A expenses, hedging gains or losses, royalties and currency exchange rates. Some of these factors, such as commodity prices, the currency exchange rate and royalties, are uncontrollable by PrimeWest. Factors that are, to a certain extent, controllable by PrimeWest are production levels and operating expenses, as well as interest and G&A expense.

Capital Spending


($ millions)		2005		2004
Land and lease acquisitions	$	17.6	$	8.3
Geological and geophysical		7.6		8.2
Drilling and completions		106.5		69.8
Equipping and tie-in		26.5		12.1
Compression and processing		9.1		4.7
Gas gathering		3.9		4.4
Production facilities		11.5		15.8
Capitalized G&A expense		2.9		1.8
Development capital	$	185.6	$	125.1
Corporate/property acquisitions		2.7		807.4
Dispositions		(20.6)		(99.5)
Head office equipment		4.2		4.6
Total	$	171.9	$	837.6

Capital expenditures, including development, acquisitions and divestments, totalled approximately $171.9 million in 2005, versus $837.6 million in 2004. PrimeWest’s property acquisitions in 2004 included the Calpine oil and natural gas assets.

PrimeWest’s 2005 capital development program totalled $185.6 million (2004 – $125.1 million). PrimeWest drilled 132 gross (62.8 net) wells with a success rate of 98.5%. The capital program focused on the core areas of Caroline, Columbia, Wilson Creek, Valhalla and Brant Farrow. The development program added 10.7 mmBOE of Company Interest Proved reserves and 14.7 mmBOE of Company Interest Proved plus Probable reserves, including technical revisions.


		2005	2004
Development Program
Proved reserve additions (mmBOE)⁽¹⁾		10.7		7.7
Average cost ($/BOE)⁽²⁾⁽³⁾	$	22.25	$	16.59
Proved plus Probable reserve additions (mmBOE)⁽¹⁾		14.7		9.1
Average cost ($/BOE)⁽²⁾⁽³⁾	$	16.85	$	16.91
Acquisition Program⁽⁴⁾
Proved reserve additions (mmBOE)		(0.5)		42.4
Average cost ($/BOE)^{(1) (4)}	$	(35.8)	$	16.57
Proved plus Probable reserve additions (mmBOE)		(0.6)		53.2
Average cost ($/BOE)^{(1) (4)}	$	(29.83)	$	13.20

(1)

Proved and Proved plus Probable reserve additions in 2004 exclude the impact of economic factors.

(2)

Under National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities, the implied methodology to be used to calculate finding, development and acquisition (FD&A) costs includes the change during the current year in estimated future development costs (FDC). The average cost per BOE from Company Interest Proved reserves additions includes the change in the current year FDC of $4.91/BOE ($0.35/BOE for 2004) and the average cost per BOE from Company Interest Proved plus Probable reserve additions, including the change in the current year FDC of $4.22/BOE ($3.17/BOE for 2004).

(3)

The aggregate of the costs incurred under the capital development program in 2005 and the estimated FDC generally will not reflect total finding and development costs related to reserve additions for that year.

(4)

Net of dispositions.

Investment in drilling, completions and tie-in represented 72% of development capital that contributed to new reserve additions in 2005. Investment in facilities totalled $24.5 million, representing 13% of development capital, on projects related to debottlenecking, increasing capacity or other activities that contribute to future production volumes.

In 2006, PrimeWest plans to invest approximately $275 million in its capital development programs.

Given that production volumes will decline naturally over time as oil or natural gas reservoirs are depleted, PrimeWest is continually striving to offset this natural decline, and add to reserves in an effort to sustain cash flows. Investment in activities such as development drilling, workovers and recompletions can add incremental production volumes and reserves.

[mdafinal002.gif] Capital is allocated on the basis of anticipated rate of return on projects undertaken. At PrimeWest, every capital project is measured against economic evaluation criteria prior to approval. These criteria include expected return, risks and further development opportunities.

Assets

Since inception, PrimeWest has focused on the conventional oil and natural gas plays of the Western Canada Sedimentary Basin. Within this focused area, we have a diversified suite of assets producing from multiple geological zones and stretching from northeast B.C. across much of Alberta. We believe this diversity reduces risks to overall corporate production and cash flow, while the core area focus allows us to capitalize on our existing technical knowledge in each of the major properties.

Reserves and Production

Company Interest Reserves – Forecast Prices and Costs

The following table sets forth a reconciliation of light, medium and heavy crude oil, natural gas, natural gas liquids and total BOE of the Company Interest reserves of PrimeWest for the year ended December 31, 2005. The table is derived from the January 23, 2006 report (the GLJ Report) of the independent reserve evaluators, GLJ Petroleum Consultants Ltd. (GLJ), using forecast price and cost estimates, and reconciled to December 31, 2004. PrimeWest’s Company Interest reserves include working interest and royalty reserves receivable. This definition is consistent with the basis on which reserves were reported in prior years. See further discussion of reserves definitions and National Instrument 51-101 (NI 51-101) under Disclosure of Oil and Gas Reserves – Standards of Disclosure for Oil and Gas Activities below.

Forecast prices are based on the consultants’ average price projections from GLJ, Sproule Associates Limited and McDaniel & Associates Consultants Ltd., all of which are effective January 1, 2006.


	Light, Medium and Heavy Crude Oil (mbbls)				Natural Gas (bcf)
	Proved Producing	Total Proved	Probable	Proved plus Probable	Proved Producing	Total Proved	Probable	Proved plus Probable
Dec. 31, 2004	19,052	19,765	4,138	23,903	450.2	529.2	148.7	677.9
Capital Additions⁽¹⁾	303	399	620	1,019	17.9	23.9	19.8	43.7
Improved Recovery⁽²⁾	474	501	189	690	10.6	23.7	2.0	25.7
Technical Revisions	806	760	(149)	611	10.1	1.3	(3.5)	(2.2)
Acquisitions	0	0	0	0	0.2	0.2	0	0.2
Dispositions	(57)	(57)	(15)	(72)	(2.6)	(2.6)	(0.4)	(3.0)
Economic Factors	0	0	0	0	0	0	0	0
Production	(2,504)	(2,504)	0	(2,504)	(65.0)	(65.0)	0	(65.0)
Dec. 31, 2005	18,073	18,864	4,783	23,646	421.4	510.7	166.6	677.3

Columns may not add due to rounding.

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


	Natural Gas Liquids (mbbls)					Total (mmBOE)
	Proved Producing		Total Proved	Probable	Proved plus Probable	Proved Producing	Total Proved	Probable	Proved plus Probable
Dec. 31, 2004	11,739		13,988	4,282	18,270	105.8	121.9	33.3	155.2
Capital Additions⁽¹⁾	462		675	564	1,239	3.7	5.1	4.4	9.5
Improved Recovery⁽²⁾	327		741	59	801	2.6	5.2	0.6	5.8
Technical Revisions	(243)		(549)	(267)	(816)	2.2	0.4	(1.0)	(0.6)
Acquisitions	0		0	0	0	0	0	0	0
Dispositions	(36)		(36)	(4)	(40)	(0.5)	(0.5)	(0.1)	(0.6)
Economic Factors	0		0	0	0	0	0	0	0
Production	(1,386)		(1,386)	0	(1,386)	(14.7)	(14.7)	0	(14.7)
Dec. 31, 2005	10,864	13,434		4,634	18,068	99.2	117.4	37.2	154.6

Columns may not add due to rounding.

(1)

Capital additions include exploration discoveries and drilling extensions.

(2)

Improved recovery includes infill drilling and improved recovery.

Net Reserves – Forecast Prices and Costs

The following table sets forth a reconciliation of PrimeWest’s Net Reserves for the year ended December 31, 2005 derived from the GLJ Report using forecast price and cost estimates. These year-end reserves are reconciled to December 31, 2004 reserves. PrimeWest’s Net Reserves include working interest reserves plus royalties receivable less royalties payable, as stipulated by NI 51-101. All data in the following tables was provided by GLJ.


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

Columns may not add due to rounding.


	Associated and Non-Associated Gas (bcf)				Natural Gas Liquids (mbbls)
	Proved Producing	Total Proved	Probable	Proved plus Probable	Proved Producing	Total Proved	Probable	Proved plus Probable
Dec. 31, 2004	358.2	420.4	117.6	538.0	8,308	9,911	3,008	12,919
Capital Additions⁽¹⁾	14.0	17.9	14.6	32.6	306	416	374	790
Improved Recovery⁽²⁾	8.2	18.5	1.4	19.9	219	528	36	563
Technical Revisions	5.8	(0.2)	(2.4)	(2.7)	(152)	(381)	(196)	(577)
Discoveries	0.1	0.9	0.3	1.2	0	45	18	63
Acquisitions	0.1	0.1	0.0	0.2	0	0	0	0
Dispositions	(1.9)	(1.9)	(0.3)	(2.2)	(24)	(24)	(3)	(27)
Economic Factors	1.3	1.1	0.4	1.5	(12)	(22)	(3)	(25)
Production	(49.5)	(49.5)	0	(49.5)	(977)	(977)	0	(977)
Dec. 31, 2005	336.4	407.2	131.7	539.0	7,668	9,495	3,234	12,729

Columns may not add due to rounding.


	Natural Gas from Coal (mmcf)				Total (mmBOE)
	Proved Producing	Total Proved	Probable	Proved plus Probable	Proved Producing	Total Proved	Probable	Proved plus Probable
Dec. 31, 2004	0	0	0	0	85.3	97.9	26.2	124.1
Capital Additions⁽¹⁾	0	226	395	621	2.9	3.8	3.4	7.2
Improved Recovery⁽²⁾	177	386	113	499	2.0	4.1	0.5	4.6
Technical Revisions	37	38	11	48	1.2	(0.1)	(0.7)	(0.8)
Discoveries	0	0	0	0	0.0	0.2	0.1	0.3
Acquisitions	0	0	0	0	0.0	0.0	0.0	0.0
Dispositions	0	0	0	0	(0.4)	(0.4)	(0.1)	(0.5)
Economic Factors	0	0	0	0	0.5	0.4	0.1	0.6
Production	(44)	(44)	0	(44)	(11.4)	(11.4)	0.0	(11.4)
Dec. 31, 2005	171	606	518	1,124	80.2	94.6	29.5	124.1

Columns may not add due to rounding.

(1)

Capital additions include exploration discoveries and drilling extensions.

(2)

Improved recovery includes infill drilling and improved recovery.

Reserves and Future Net Revenues

The following tables provide reserves data and a breakdown of reserves on a Company Interest, Gross and Net basis and the net present value of future net revenues using consultant’s average pricing.


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

Columns may not add due to rounding.


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

Columns may not add due to rounding.

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


	Total (mBOE)
Reserves Category	Company Interest	Gross	Net
Proved
Developed Producing	99,162	95,778	80,214
Developed Non-Producing	7,724	7,697	6,106
Undeveloped	10,535	10,517	8,292
Total Proved	117,422	113,993	94,612
Probable	37,181	36,474	29,450
Total Proved plus Probable	154,603	150,466	124,062

Columns may not add due to rounding.


	Net Present Values of Future Net Revenue ($ millions)
	Before Future Income Tax Expenses Discounted at (%)					After Future Income Tax Expenses Discounted at (%)
Reserves Category	0%	5%	10%	15%	20%	0%	5%	10%	15%	20%
Proved
Developed Producing	3,241.2	2,387.1	1,935.7	1,656.2	1,464.1	3,241.2	2,387.1	1,935.7	1,656.2	1,464.1
Developed Non-Producing	265.0	178.6	140.3	118.2	103.5	265.0	178.6	140.3	118.2	103.5
Undeveloped	277.7	179.8	128.9	97.9	76.9	277.7	179.8	128.9	97.9	76.9
Total Proved	3,783.8	2,745.5	2,204.9	1,872.3	1,644.6	3,783.8	2,745.5	2,204.9	1,872.3	1,644.7
Probable	1,259.7	701.0	479.0	365.0	295.7	1,259.7	701.0	479.0	365.0	295.7
Total Proved plus Probable	5,043.6	3,446.6	2,684.0	2,237.2	1,940.4	5,043.6	3,446.6	2,684.0	2,237.2	1,940.4

Columns may not add due to rounding .

Daily Production Volumes


2005		2004		Change (%)
Natural gas (mmcf/day)	178.2		145.1	23
Crude oil (bbls/day)	6,861		8,282	(17)
Natural gas liquids (bbls/day)	3,797		3,107	22
Total (BOE/day)	40,351		35,578	13
Gross overriding royalty volumes included above (BOE/day)	1,338		1,440	(7)

All production information is reported before the deduction of Crown and freehold royalties.

The 13% increase in daily average production year-over-year is due in part to the acquisition of the Calpine assets in the third quarter of 2004, combined with production additions from 2005 development activity, offset partially by the asset divestment in December 2004 and the natural decline of production. Based on 2005 production statistics, natural production decline is estimated at approximately 17%. During 2005, approximately 2,900 BOE/day of annualized incremental production was brought on-stream from development activities to help offset natural decline. Approximately 2,200 BOE/day of new production remained “behind pipe”, or awaiting tie-in to production facilities, at the end of 2005.

PrimeWest expects production for full-year 2006 to be 38,000–39,000 BOE/day. This estimate incorporates PrimeWest’s expected natural decline rate, production volume shut-ins due to scheduled plant turnarounds at Crossfield, Caroline and Edson (estimated to affect approximately 600 BOE/day on a full-year average basis), the reinstatement effective January 1, 2006 of the Maximum Rate Limitation (MRL) on wells in the Cecil area and others, all offset by production additions from the 2006 capital development program.

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

Commodity Prices


Average Benchmark Prices		2005	2004		Change (%)
Natural Gas
NYMEX (US$/mcf)	$	8.55	$	6.09	40
AECO (Cdn$/mcf)	$	8.48	$	6.79	25
Crude oil – W.T.I. (US$/bbl)	$	56.56	$	41.40	37


Average Realized Sales Prices⁽¹⁾ (Cdn$)		2005		2004	Change (%)
Natural gas ($/mcf)⁽²⁾	$	8.43	$	6.61	28
Crude oil ($/bbl)	$	49.05	$	36.83	33
Natural gas liquids ($/bbl)	$	55.92	$	43.69	28
Total ($/BOE)	$	50.81	$	39.35	29
Realized hedging loss included in prices above ($/BOE)	$	(3.01)	$	(2.16)	(39)

(1)

Includes realized hedging losses.

(2)

Excludes sulphur.

The selling price that PrimeWest realized from its 2005 production, net of hedging impact, was 29% higher than in 2004. The commodity hedging program resulted in a reduction of PrimeWest’s 2005 average realized price by $3.01/BOE, compared to a reduction of $2.16/BOE in 2004. This hedging impact reflects the amount of additional revenue foregone by PrimeWest as a result of its hedging program, through which the price of a portion of its production was capped at certain price levels in exchange for downward price protection. PrimeWest utilizes financial hedges as part of its financial strategy to reduce the impact of commodity price volatility and to improve the predictability of cash flow from operations.

The Canadian and U.S. currency exchange rate is another factor that has an impact on the price PrimeWest realizes from its production. Since Canadian prices of oil and natural gas are influenced by benchmark prices that are set in U.S. dollars, a stronger Canadian dollar will translate into lower realized prices and revenues when expressed in Canadian dollars. During 2005, the Canadian dollar exchange rate increased by approximately 3% versus the U.S. dollar, from US$0.831 at December 31, 2004 to US$0.858 at December 31, 2005. The stronger Canadian dollar during 2005 negatively impacted PrimeWest’s Canadian realized prices and revenue receipts.

Crude Oil Prices

Continued growth in global oil demand combined with supply concerns resulted in strong crude oil prices in 2005. On the demand side, robust economic growth in Asia, notably in China and India, together with a strong consumer economy in the U.S. have increased worldwide oil consumption. Supply disruptions occurred in various parts of the world, due to political uncertainty and natural disasters, such as hurricanes Katrina and Rita, which shut down a large volume of production in the Gulf of Mexico. Within OPEC, the excess production capacity that once existed among most members was reduced by the increased demand. In 2005 Saudi Arabia, Kuwait and the United Arab Emirates were the only OPEC member countries with meaningful spare capacity that could be used to offset supply disruptions. As a result, oil prices fluctuated throughout 2005 in response to world events and weather condit ions. During 2005, oil went from US$43.45/bbl at the beginning of the year to a historical high of US$69.81/bbl on August 30, 2005, before dropping to US$61.04/bbl by year-end.

The forward price of crude oil as at December 31, 2005 indicated a rising trend over the next 12 months to approximately US$64.00/bbl by 2006 year-end. Key factors that are expected to influence prices in 2006 include: potential slowdown in worldwide demand growth, particularly in China and India, as a response to higher prices; attempts by OPEC to influence prices by adjusting production quotas; the ability of Iraq to restore more of its oil export capability and the rate and magnitude of production growth from OPEC and non-OPEC producers.

The netbacks for Canadian companies and energy trusts that produce a heavier grade of crude oil were negatively affected by a wide price differential versus lighter, sweet crude in 2005. As the majority of crude production coming into the markets worldwide was of heavier and more sour quality, the discount versus lighter oil remained at a high level throughout 2005, as heavy-oil refining capacity was reaching full utilization. In addition, the realized price for heavy oil producers was negatively affected by an increase in the price of condensate, a natural gas by-product that is widely used as a diluent to blend heavier crude oil for pipeline transport.

Approximately 32% of PrimeWest’s crude oil production is made up of medium to slightly heavy grades. These products do not require any diluent blending and attract a better pricing differential than heavier crude oil production.

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

Natural Gas Prices

PrimeWest’s average realized natural gas price in 2005 increased by 28% to $8.43/mcf from a 2004 average of $6.61/mcf. At the beginning of 2005, the outlook for natural gas prices was markedly bearish due to mild winter weather and a decline in heating demand. The natural gas storage level at the end of the 2005 winter season was higher than at the end of the 2004 winter season, which had also experienced a warmer than normal winter. Over the ensuing summer, this year-on-year storage overhang was gradually worked off by the increased natural gas demands in response to hotter temperatures. The impact of Hurricanes Katrina and Rita turned a surplus storage position into deficit, causing a run-up of natural gas prices to approximately US$15.00/mmbtu by early December. Prices began to soften in the latter part of December due to unseasonably warm weather. At 2005 year-end, North American natural gas storage levels were approaching the five-year average. Forward natural gas prices as of December 31, 2005 reflected a bullish trend, but have softened with the warm weather in early 2006.

Key factors expected to influence prices in 2006 include: the speed of the restoration of shut-in Gulf of Mexico production; North American weather patterns during the upcoming summer and winter seasons; the ability of producers in Canada and the U.S. to replace and add to production levels through increased drilling; the continued growth of natural gas demand in the electricity sector; and the impact of government regulations and conservation efforts in response to higher natural gas prices.

Sales Revenue


Revenue ($ millions)⁽¹⁾		2005	% of Total		2004	% of Total	Change (%)
Natural gas⁽²⁾	$	548.0	73	$	351.0	69	56
Crude oil		122.8	16		111.7	22	10
Natural gas liquids		77.5	11		49.7	9	56
Total	$	748.3		$	512.4
Hedging loss included above	$	(44.3)		$	(28.2)

(1)

Net of transportation expense.

(2)

Excludes sulphur.

PrimeWest’s revenues from the sale of commodities for 2005 were $748.3 million compared to $512.4 million in the previous year, including the effect of hedging. Higher commodity prices along with increases in natural gas sales volumes were the major contributors to the increased revenue in 2005.

If the pricing environment softens in 2006, and the Canadian dollar remains strong, oil and natural gas revenues will be negatively impacted. Since approximately 73% of PrimeWest’s revenues are derived from natural gas, the Trust has greater sensitivity to changes in natural gas prices than crude oil prices.

2005 Hedging Results

As part of our financial management strategy, PrimeWest uses a consistent commodity hedging approach. The purposes of the hedging program are to reduce volatility in cash flows, to protect acquisition economics against the unpredictable commodity price environment and to protect our capital structure when commodity prices cycle downwards, while at the same time retaining exposure to pricing upside. PrimeWest’s hedging policy reflects a willingness to forfeit a portion of the pricing upside in return for protection against a significant downturn in prices.


		Crude Oil ($/bbl)			Natural Gas ($/mcf)				BOE ($/BOE)
		2005	2004		2005			2004	2005		2004
Unhedged price	$	58.48	$	44.46	$	8.75	$	6.70	$	53.82	$	41.51
Hedging loss		(9.43)		(7.63)		(0.32)		(0.09)		(3.01)		(2.16)
Realized price	$	49.05	$	36.83	$	8.43	$	6.61	$	50.81	$	39.35

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


	2005 Hedging Loss			2004 Hedging Loss
	% Hedged	$ millions		% Hedged		$ millions
Crude oil	60	$	23.6		58	$	23.1
Natural gas	55		20.7		54		5.1
Total		$	44.3			$	28.2

The table below shows the production volumes hedged at December 31, 2005.


2006	Q1	Q2	Q3	Q4	Full Year
Crude oil (bbls/day)	4,000	3,000	2,000	2,000	2,750
Natural gas (mmcf/day)	79	42	42	42	51
2007
Crude oil (bbls/day)	500	500	0	0	250
Natural gas (mmcf/day)	14	0	0	0	4

A summary of hedging contracts in place as at December 31, 2005 is available under note 17 to the Consolidated Financial Statements.

PrimeWest’s derivatives are marked-to-market with the resulting gain or loss reflected in earnings for the reporting period.

The 2005 income statement includes an unrealized loss of $11.6 million on derivatives resulting from the change in the mark-to-market valuation of the derivative financial instruments during the period. The loss was comprised of a $6.6 million gain for crude oil hedges, an $18.3 million loss for natural gas hedges and a $0.1 million gain for electrical power hedges.

For the year ended December 31, 2005 the cash impact of contract settlements was a $43.5 million loss, comprised of a $23.6 million loss in crude oil, a $20.7 million loss in natural gas, and a $0.8 million gain on electrical power.

Royalties

Royalties are paid by PrimeWest to the owners of mineral rights with whom PrimeWest holds leases. PrimeWest has mineral leases with the Crown (provincial and federal governments) and freeholders (individuals or other companies).


($ millions, except per BOE)		2005	2004		Change (%)
Royalty expense	$	172.8	$	119.8	44
Per BOE	$	11.73	$	9.20	28
Royalties as a percentage of sales revenues
With hedge revenue		23%		23%
Excluding hedge revenue		22%		22%

Royalty expenses as a percentage of sales have remained constant when compared to the previous year.

The Crown royalty system is based on a sliding scale structure that increases the royalty rates as commodity prices rise until a maximum rate is achieved. Because of the sliding scale Crown royalty system, future changes to commodity prices will result in changes to royalty rates and expenses.

Operating Expenses


($ millions, except per BOE)		2005		2004	Change (%)
Operating expense	$	117.0	$	88.9	32
Per BOE	$	7.94	$	6.83	16

Operating expenses for 2005 increased by $28.1million or 32% over 2004 mainly due to the increase in volumes resulting from the Calpine asset acquisition, which occurred in the third quarter of 2004.

The increase in operating costs per BOE is due mainly to the effects of inflationary pressures on the price of industry-related goods and services, due to the increased demand resulting from the current commodity price environment. Operating issues at the Valhalla plant and Boundary Lake pipeline repairs and clean-up costs also contributed to the increase in operating costs per BOE.

Operating Margin


($/BOE)		2005		2004	Change (%)
Sales price and other revenue⁽¹⁾	$	51.70	$	40.13	29
Transportation expense		(0.49)		(0.63)	(22)
Royalties		(11.73)		(9.20)	28
Operating expense		(7.94)		(6.83)	16
Operating margin	$	31.54	$	23.47	34

(1)

Includes hedging and sulphur.

Operating margins increased by 34% from 2004 on a per BOE basis. The increase in 2005 from 2004 is primarily due to higher sales prices, offset by higher per unit operating expenses and higher royalties. Operating margin measures the level of cash flow per BOE at the field level and before head office expenses.

G&A Expense


($ millions, except per BOE)		2005		2004 restated	Change (%)
Cash G&A expense	$	22.9	$	19.0	21
Per BOE		1.56		1.46	7
Non-cash G&A expense		5.4		4.1	32
Per BOE	$	0.37	$	0.32	16

Cash G&A expense increased by 21% in 2005 from 2004, primarily due to higher staff levels resulting in increased employee costs, office rent, property taxes and information technology expenditures. These increases are primarily attributable to the Calpine asset acquisition, which occurred in the third quarter of 2004. The increases were partially offset by overhead recoveries resulting from increases to capital expenditures and operating expenses.

Included in non-cash G&A expense is $3.6 million relating to the Unit Appreciation Rights (UARs), granted under the LTIP. UARs in the Trust are similar to stock options in a corporation. The program rewards employees based on total Unitholder return, which is comprised of cumulative distributions on a reinvested basis plus growth in Unit price. No benefit accrues to the UARs until the Unitholders have first achieved a 5% total annual return from the time of grant. PrimeWest continues to pay for the exercise of UARs in Trust Units. Also included in non-cash G&A expense is $1.8 million related to the Special Employee Retention Plan (SERP). See note 18 to the Consolidated Financial Statements.

Interest Expense


($ millions, except per Trust Unit)		2005		2004	Change (%)
Interest expense	$	28.3	$	20.6	37
Period end net debt level	$	323.7	$	552.0	(41)
Debt per Trust Unit	$	3.97	$	7.77	(48)
Average cost of debt		5.2%		4.8%

Interest expense, representing interest on bank debt, the Secured Notes and the Debentures, increased to $28.3million in 2005 from $20.6 million in 2004 due to higher average debt balances in 2005 compared to 2004, mainly resulting from the issuance of the Debentures to finance the Calpine acquisition. The Debentures also increased the average cost of debt with interest rates of 7.50% and 7.75% for the Series I and Series II Debentures, respectively.

Net debt at December 31, 2005 was 41% lower than at December 31, 2004 due to the repayment of $111.0 million of the bank credit facility and to the conversion of $186.2 million (net of accretion expense of $1.0 million) of Debentures into Trust Units.

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

Foreign Exchange Gain

The foreign exchange gain of $4.6million resulted mainly from the translation of the U.S. dollar-denominated Secured Notes and related interest payable into Canadian dollars.

Depletion, Depreciation and Amortization (DD&A)


($ millions, except per BOE amounts)		2005		2004	Change (%)
Depletion, depreciation and amortization	$	230.2	$	197.3	17
Per BOE	$	15.63	$	15.15	3

The 2005 DD&A rate of $15.63/BOE is higher than the 2004 rate of $15.15/BOE mainly due to the impact of the Calpine asset acquisition.

Gain on Sale of Marketable Securities

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

Site Reclamation and Restoration Reserve

Since the inception of the Trust, PrimeWest has maintained a site reclamation fund to pay for future costs related to well abandonment and site cleanup. The fund is used to pay for such costs as they are incurred. The reclamation and abandonment costs incurred in 2005 were $8.7million, compared to $4.6 million in 2004.

The 2005 contribution rate for the fund was unchanged from 2004 at $0.50/BOE, which is expected to be sufficient to meet expenditure requirements for the future. As at December 31, 2005, the site reclamation fund had a balance of $9.2 million.

Net Asset Value

Net asset value (NAV) measures the net worth of PrimeWest by subtracting the value of debt from the estimated economic value of its underlying assets – primarily crude oil, natural gas and natural gas liquids reserves. The value placed on these reserves is the pre-tax present value of future net cash flows, discounted at 10%, as independently assessed by GLJ as at January 1, 2006. The present value of reserves reflects provisions for royalties, operating costs, future capital costs and site reclamation and abandonment costs, but is prior to deductions for income taxes, interest expense and G&A expense.

This calculation is a “snapshot” in time and is heavily dependent upon future commodity price expectations when the “snapshot” is taken. Accordingly, the NAV as at January 1, 2006 may not reflect fairly the equity market trading value of PrimeWest. It is also significant to note that NAV declines as reserves are produced and net operating cash flow is distributed to Unitholders. Value is delivered to Unitholders through such monthly distributions.


As at December 31 ($ millions, except per Trust Unit amounts)	2005 Consultants' Average		2004 Consultants’ Average
ASSETS
Present value of future net cash flow discounted at 10%⁽¹⁾⁽³⁾	$	2,684.0	$	1,714.4
Market value of Viking Energy Royalty Trust Units		-		91.0
Mark-to-market value of hedging contracts		(11.5)		0.1
Fair value of unproved lands		151.3		103.9
Reclamation fund		9.2		10.3
	$	2,833.0	$	1,919.7
LIABILITIES
Debt and working capital surplus⁽²⁾		(267.9)		(378.5)
Net asset value	$	2,565.1	$	1,541.2
Outstanding Trust Units – millions, diluted		83.7		80.5
Net asset value per Trust Unit	$	30.64	$	19.15

(1)

Company Interest Proved plus Probable reserves.

(2)

Debt excludes Debentures.

(3)

Refer to Summary of Oil and Natural Gas Reserves and Net Present Values of Future Net Revenues table under the section Disclosure of Oil and Natural Gas Reserves on page 45.


Price Assumptions	2005 Consultants’ Average		2004 Consultants’ Average
Edmonton Par Oil – Cdn$/bbl
2005	$	-	$	50.37
2006	$	67.64	$	47.46
2007	$	66.40	$	43.88
2008	$	60.89	$	40.89
2009	$	56.83	$	39.20
2010	$	54.25	$	-

Spot Gas at AECO-C – Cdn$/mcf
2005	$	-	$	6.79
2006	$	10.93	$	6.52
2007	$	9.88	$	6.25
2008	$	8.48	$	5.95
2009	$	7.59	$	5.79
2010	$	7.23	$	-

The NAV calculation is based on the above reference prices as of December 31, 2005 and 2004 and is highly sensitive to changes in price forecasts over time as well as in the exchange rate. In addition, the year-over-year change is impacted by the cash distributions made throughout the year, which totalled $276.6 million or $3.66 per Trust Unit in 2005. Also, the NAV calculation assumes a “blow down” scenario whereby existing reserves are produced without being replaced by acquisitions and development. A major cornerstone of PrimeWest’s strategy is to replace reserves through accretive acquisitions and capital development.

Income and Capital Taxes


($ millions)		2005		2004 restated	Change (%)
Income and capital taxes	$	2.8	$	3.3	(15)
Future income tax recovery		(14.8)		(34.3)	(57)
Total	$	(12.0)	$	(31.0)	(61)

The decrease in the future income tax recovery is due to the increase in net income resulting primarily from higher oil and natural gas revenues.

Net Income

($ millions)

2005

2004

restated

Change (%)

Net income

207.5

105.4

Cash flow from operations, as opposed to net income, is the primary measure of performance for an energy trust. The generation of cash flow is critical to the ability of an energy trust to continue to sustain the monthly distribution of cash to Unitholders.

Conversely, net income is an accounting measure impacted by both cash and non-cash items. The largest non-cash items impacting PrimeWest’s net income are the unrealized gains or losses on derivatives, foreign exchange gains or losses, DD&A and future income taxes.

Net income of $207.5 million in 2005 was higher than 2004 net income of $105.4 million primarily due to the increase in net oil and natural gas revenues resulting from increases to commodity prices and production volumes. Increases to operating expenses, DD&A, the unrealized loss on derivatives and lower future income tax recovery had a negative impact on net income.

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

Liquidity and Capital Resources


($ millions)		2005		2004	Change (%)
Long-term debt	$	354.2	$	656.3	(46)
Working capital surplus⁽¹⁾		(30.5)		(104.3)	(71)
Net debt		323.7		552.0	(41)
Market value of Trust Units and Exchangeable Shares outstanding⁽²⁾		2,884.7		1,877.7	54
Total capitalization	$	3,208.4	$	2,429.7	32
Net debt as a % of total capitalization		10%		23%

(1) Working capital surplus excludes financial derivative assets and liabilities and current future income tax assets.

(2) Based on December 31, 2005 Trust Unit closing price of $35.90 and exchangeable share ratio of 0.56399:1.

Long-term debt is comprised of bank credit facilities, Secured Notes and 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. 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 attributed to the Secured Notes valued at $156.3 million based on the agreed U.S. dollar exchange rate at the time of last renewal. In addition to the amounts outstanding under the bank credit facility, PrimeWest has outstanding letters of credit in the amount of $6.6 million (2004 – $4.9 million). The credit facility revolves until June 30, 2006, by which time the lenders will have conducted their annual borrowing base review.

The Secured Notes in the amount of US$125 million have a final maturity date 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.

PrimeWest issued the 7.5% (Series I) and 7.75% (Series II) Debentures in the third quarter of 2004 for proceeds of $150.0 million and $100.0 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 a conversion price of $26.50 per Trust Unit. PrimeWest has the option to redeem the Series II Debentures at a price of $1,050 per Series II Debenture after December 31, 2007 and on or before December 31, 2008, at a price of $1,025 per Debenture after December 31, 2008 and on or before December 31, 2009, and after December 31, 2009 and before maturity at a price of $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.

PrimeWest’s net debt at December 31, 2005 was lower than at December 31, 2004 due to the conversion of $114.3 million of Series I and $72.9 million of Series II Debentures, offset by accretion of $1.0 million. In addition, cash flow from operations in excess of distributions allowed for the repayment of $111.0 million of the bank credit facility.

Unitholders’ Equity

The Trust had 79,666,352 Trust Units outstanding at December 31, 2005 compared to 69,886,111 Trust Units at the end of 2004. In addition, there were 1,219,335 Exchangeable Shares (see below) outstanding at year-end, exchangeable into a total of 687,693 Trust Units. The weighted average number of Trust Units, including those issuable by the exchange of Exchangeable Shares, was 75,808,919 Trust Units for the twelve month period ended December 31, 2005 compared to 59,482,034 in 2004.

During the year, 487,421 Trust Units were issued to employees pursuant to the LTIP.

During 2005, PrimeWest issued 262,347 Trust Units under the DRIP for $7.9 million (2004 – 268,677 Trust Units, $6.5 million), 932,142 Trust Units for $27.4 million pursuant to the PREP (2004 – 1,311,462 Trust Units, $32.0 million) and 704,806 Trust Units for $20.4 million pursuant to the OTUPP (2004 - 894,167 Trust Units, $21.5 million).

The DRIP gives Canadian and U.S. Unitholders the opportunity to reinvest their monthly distributions at a 5% discount to the volume-weighted average market price of the Trust Units. As an alternative to the DRIP component of the Plan, the PREP allows eligible Canadian Unitholders to elect to receive a premium cash distribution of up to 102% of the cash that the Unitholder would otherwise have received on the distribution date, subject to proration in certain events. The OTUPP gives Canadian Unitholders an opportunity to purchase additional Trust Units directly from PrimeWest at the same 5% discount. The DRIP and PREP components are mutually exclusive. Participation in the OTUPP requires enrolment in either the DRIP or PREP.

These plan components benefit Unitholders by offering alternatives to maximize their investment in PrimeWest, while providing the Trust with an inexpensive method of raising additional capital. The Trust expects interest in these plans in 2006 to be similar to 2005. Proceeds from these plans are used for debt reduction of PrimeWest’s credit facility and to help fund ongoing capital development programs.

For additional information or to join these plans, contact the Plan Agent for the DRIP, OTUPP and PREP, Computershare Trust Company of Canada, at 1-800-564-6253, or visit PrimeWest’s website at www.primewestenergy.com.

Exchangeable Shares

Exchangeable Shares were issued in connection with both the Venator Petroleum Company Ltd. acquisition in April 2000 and the Cypress Energy Inc. acquisition in March 2001. These shares were issued to provide a tax-deferred rollover of the adjusted cost base from the shares being exchanged to the Exchangeable Shares.

In 2005, 94,340 (2004 – 94,340) Exchangeable Shares were issued pursuant to the Special Employee Retention Plan (SERP). See note 18 to the Consolidated Financial Statements.

The Exchangeable Shares do not receive cash distributions. In lieu of receiving cash distributions, the number of Trust Units that the exchangeable shareholder will receive upon exchange increases each month based on the distribution amount divided by the market price of the Trust Units on the 15th day of each month.

At December 31, 2005, there were 1,219,335Exchangeable Shares outstanding. The exchange ratio was 0.56399:1 Trust Units for each Exchangeable Share at year end.

For purposes of calculating basic per Trust Unit amounts, these Exchangeable Shares have been assumed to be exchanged into Trust Units at the current exchange ratio.

Cash Distributions

Since August 2003, PrimeWest has followed a strategy of targeting a distribution payout ratio within 70-90% of cash flow, calculated on an annual basis. The recent strength in commodity prices has increased the Trust’s cash flow from operations available for distribution to Unitholders. The Board of Directors of PrimeWest will continue to consider a variety of factors in establishing the monthly distribution level. These factors include, but are not limited to: commodity price outlook, cash flow forecast, capital development plans, debt levels, taxability considerations and competitive industry distribution practices.

Cash distributions for 2005 were $276.6million or $3.66per Trust Unit, representing a payout ratio of approximately 67%, versus 2004 amounts of $196.1 million or $3.30 per Trust Unit, representing a payout ratio of approximately 74%.

Distribution payments to U.S. Unitholders are subject to a 15% Canadian withholding tax, which is deducted from the distribution amount prior to deposit into accounts.

Cash Flow Sensitivities


	Increase to Annual Cash Flow $/Trust Unit⁽¹⁾
Crude oil price (US$1.00/bbl WTI increase)	$	0.03
Natural gas price ($0.10/mcf increase)	$	0.06
Exchange rate (US$0.01 decrease)	$	0.09
Short-term interest rate (1% decrease)	$	0.02
Production (1,000 BOE/day increase)	$	0.20

(1)

Without the effect of hedging and assuming no change in operating costs and royalty costs.

The figures in the above table are provided for directional information only and are based on the number of Trust Units outstanding as at December 31, 2005. Should changes to the commodity price, interest rate, exchange rate or production levels noted above take place, it should not be assumed that a corresponding change would be made to the distribution level.

Contractual Obligations

PrimeWest enters into many contractual obligations as part of conducting day-to-day business. Material contractual obligations include debt obligations, office lease rental commitments that run from 2006 through 2009 and various pipeline transportation commitments that run through 2011. The details of the timing of these contractual obligations are included in the following table.


	Payments Due by Period
As at December 31, 2005 ($ millions)	Total	Less than 1 Year	1-3 Years	4-5 Years	More than 5 Years
Long-term debt obligations	$ 298.4	$ -	$ 225.7	$ 72.7	$ -
Debentures	57.6	-	-	33.6	24.0
Office lease rental obligations	11.4	3.7	6.9	0.8	-
Pipeline transportation obligations	11.5	7.2	3.7	0.5	0.1
Derivative liability	11.5	11.3	0.2	-	-
Total contractual obligations	$ 390.4	$ 22.2	$ 236.5	$ 107.6	$ 24.1

As part of PrimeWest’s 2002 internalization transaction, which closed on November 6, 2002, PrimeWest agreed to issue 377,360 Exchangeable Shares to certain executive officers pursuant to the SERP. On November 6, 2004 and 2005, 94,340 Exchangeable Shares were issued to those officers. An additional 94,340 shares will be issued on November 6, 2006 and 2007. For the 12 months ended December 31, 2005, $1.8 million was recorded in non-cash G&A expense related to the SERP.

Quarterly Performance – Selected Measures


	2005 (Restated)⁽¹⁾				2004 (Restated)⁽¹⁾
($ millions, except per Trust Unit amounts)	Q4	Q3	Q2	Q1	Q4	Q3	Q2	Q1
Net revenues⁽²⁾	$ 236.4	$ 101.5	$ 155.3	$ 111.2	$ 158.2	$ 84.5	$ 84.9	$ 75.2
Net income	101.5	27.3	54.7	24.0	42.2	27.1	16.5	19.6
Cash flow	132.5	106.4	95.5	79.7	83.3	66.8	58.2	58.5
Net income per Trust Unit – Basic	1.27	0.35	0.74	0.34	0.59	0.44	0.30	0.39
Net income per Trust Unit – Diluted	1.23	0.35	0.72	0.34	0.58	0.44	0.30	0.39
Cash flow per Trust Unit – Basic	1.66	1.36	1.29	1.12	1.17	1.09	1.05	1.16
Cash flow per Trust Unit – Diluted	$ 1.60	$ 1.31	$ 1.21	$ 1.04	$ 1.07	$ 1.08	$ 1.05	$ 1.15

(1)

See note 3 to the Consolidated Financial Statements.

(2)

Net revenues equals revenues from the sale of crude oil, natural gas and natural gas liquids less Crown and other royalties plus unrealized gain or loss on derivatives, gain on sale of marketable securities and other income.

The above table highlights PrimeWest’s performance by selected measures for the quarter ended December 31, 2005, and the preceding seven quarters.

Net revenues are primarily impacted by commodity prices, production volumes and royalties. Net revenues are also impacted by non-cash items including the unrealized gain or loss on derivatives and the gain on sale of marketable securities.

Net income and net income per Trust Unit are secondary measures for a royalty trust because they include both cash and non-cash items. The non-cash items such as DD&A, future income taxes, unrealized foreign exchange gains or losses, and unrealized gains or losses on derivatives will not affect PrimeWest’s ability to pay a monthly distribution.

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

Annual Performance – Selected Measures


($ millions, except per Trust Unit amounts)		2005		2004 Restated⁽¹⁾		2003 Restated⁽¹⁾
Gross revenue (net of transportation expense)	$	749.7	$	513.7	$	434.6
Net income	$	207.5	$	105.4	$	102.7
Net income per Trust Unit – Basic	$	2.73	$	1.77	$	2.23
Net income per Trust Unit – Diluted	$	2.66	$	1.77	$	2.22
Total assets	$	2,131.9	$	2,240.9	$	1,690.5
Long-term financial liabilities⁽²⁾	$	394.8	$	696.6	$	269.8

(1)

See note 3 to the Consolidated Financial Statements.

(2)

Includes long-term debt, derivative liabilities and the asset retirement obligation.

The above table highlights selected performance measures for the years ended December 31, 2005, 2004 and 2003.

The increase in gross revenues net of transportation from $434.6 million in 2003 to $749.7 million in 2005 was due to increases in production volumes and realized commodity prices over the period. The increase in production volumes is mainly due to the Calpine asset acquisition in the third quarter of 2004.

Net income has increased from 2003 to 2005 due to increases in gross revenues (described above), offset by increases to royalties, operating expense, cash G&A expense and interest expense. Increases to non-cash expenses including DD&A and unrealized losses on derivatives, and reductions to future income tax recoveries have negatively impacted net income during the period. The increases to the operating and cash G&A expenses are due mainly to additional production volumes and staffing requirements resulting from corporate and asset acquisitions.

Total assets at December 31, 2004 exceed the balance at December 31, 2003 mainly due to the Calpine asset acquisition.

Long-term financial liabilities increased from $269.8 million at December 31, 2003 to $696.6 million at December 31, 2004 due primarily to the issuance of the Series I and Series II Debentures and the drawdown on the credit facility to finance the Calpine asset acquisition. The decrease in the liabilities from December 31, 2004 to December 31, 2005 is due to the conversion of $186.2 million of Debentures into Trust Units and to the repayment of $111.0 million of the bank credit facility.

Critical Accounting Estimates

PrimeWest’s financial statements have been prepared in accordance with GAAP. Certain accounting policies require that management make appropriate decisions with respect to the formulation of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. The following discussion reviews such accounting policies and is included in this annual report to aid the reader in assessing the critical accounting policies and practices of the Trust and the likelihood of materially different results being reported. PrimeWest’s management reviews its estimates regularly, but new information and changed circumstances may result in actual results or changes to estimated amounts that differ materially from current estimates.

The following assessment of significant accounting policies is not meant to be exhaustive. The Trust may realize different results from the application of new accounting standards proposed and/or implemented, from time to time, by various rule-making bodies.

Disclosure of Oil and Natural Gas Reserves

Disclosure in respect of the reserves of PrimeWest is for the year ended December 31, 2005 and is derived from the GLJ Report. Capitalized terms not otherwise defined in respect of PrimeWest’s reserves and production have the meaning provided for them in NI 51-101.

Proved oil and natural gas reserves are the estimated quantities of crude oil, natural gas liquids, including condensate, and natural gas that geological and engineering data demonstrate with reasonable certainty can be recovered in future years from known reservoirs under existing economic and operating conditions (i.e., prices and costs as of the date the estimate is made).

Proved reserves are those reserves that can be estimated with a high degree of certainty to be recoverable (i.e. it is likely that the actual remaining quantities recovered will exceed the estimated Proved reserves). In accordance with this definition, the level of certainty targeted by the reporting entity should result in at least a 90% probability that the quantities recovered will equal or exceed the estimated Proved reserves.

For Probable reserves, which are by definition less certain to be recovered than Proved reserves, NI 51-101 states that it must be equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated Proved plus Probable reserves. With respect to the consideration of certainty, in order to report reserves as Proved plus Probable, the level of certainty targeted by the reporting entity should result in at least a 50% probability that the quantities recovered will equal or exceed the sum of the estimated Proved plus Probable reserves.

The oil and natural gas reserve estimates are made using all available geological and reservoir data as well as historical production data. Estimates are reviewed and revised as appropriate. Revisions occur as a result of changes in prices, costs, fiscal regimes, reservoir performance or a change in PrimeWest’s plans. The effect of changes in Proved oil and natural gas reserves on the financial results and position of PrimeWest are described under the heading Full Cost Accounting for Oil and Natural Gas Activities.

In addition to the categorization of its reserves into “Gross” and “Net”, as required by NI 51-101, PrimeWest also uses the term “Company Interest’ to describe its reserves. Company Interest reserves include working interest and royalties receivable by PrimeWest, with no deduction of royalties payable. PrimeWest reported its reserves on a Company Interest basis prior to the implementation of NI 51-101 and PrimeWest continues to provide this disclosure for comparability purposes.

PrimeWest’s disclosure of reserves data and other oil and natural gas information is made in conformity with NI 51-101. There are differences between the requirements under NI 51-101 and those imposed by the SEC, including with respect to the disclosure of Proved Reserves, Probable Reserves and estimated future net cash flows from Reserves. Further information in this regard is set forth under the heading Statement of Reserves Data and Other Oil and Gas Information - General in PrimeWest’s Annual Information Form dated March 15, 2006.

FULL COST ACCOUNTING FOR OIL AND NATURAL GAS ACTIVITIES

PrimeWest adopted Canadian Institute of Chartered Accountants (CICA) Accounting Guideline 16 (AcG-16), “Oil and Gas Accounting – Full Costs” on January 1, 2004. The guideline requires 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 is 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.

DEPLETION EXPENSE

PrimeWest uses the full cost method of accounting for exploration and development activities. In accordance with this method of accounting, all costs associated with exploration and development activities, whether successful or not, are capitalized. The aggregate of net capitalized costs and estimated future development costs less estimated salvage values is amortized using the unit of production method based on estimated Proved oil and natural gas reserves. An increase in estimated Proved oil and natural gas reserves would result in a corresponding reduction in depletion expense. A decrease in estimated future development costs would result in a corresponding reduction in depletion expense.

FAIR VALUE OF DERIVATIVE INSTRUMENTS

As part of its financial management strategy, PrimeWest utilizes financial derivatives, including commodity prices hedges, to manage market risk. The purpose of hedging is to provide an element of stability to PrimeWest’s cash flow in a volatile commodity price environment. Effective January 1, 2004, PrimeWest adopted CICA Accounting Guideline 13, (AcG-13) “Hedging Relationships”.

The estimation of the fair value of certain hedging derivatives requires considerable judgment. The estimation of the fair value of commodity price hedges requires sophisticated financial models that incorporate forward price and volatility and that, when compared with PrimeWest’s outstanding hedging contracts, produce cash inflow or outflow variances over the contract period. The estimate of fair value for interest rate and foreign currency hedges is determined primarily through quotes from financial institutions.

ASSET RETIREMENT OBLIGATIONS

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 to be recorded when they are incurred rather than merely accumulated or accrued over the useful life of the respective asset.

PrimeWest, under the current policy, is required to provide for future removal and site restoration costs. PrimeWest must estimate these costs in accordance with existing laws, contracts and policies. These estimated costs are charged to earnings and the appropriate liability account over the expected service life of the asset. Contingent liabilities are charged to earnings when management is able to determine the amount and the likelihood of the future obligation.

LEGAL, ENVIRONMENTAL REMEDIATION AND OTHER CONTINGENT MATTERS

The Trust is required to both determine whether a loss is probable based on judgment and interpretation of laws and regulations and whether that loss can reasonably be estimated. When the loss is determined, it is charged to earnings. PrimeWest’s management must continually monitor known and potential contingent matters and make appropriate provisions through charges to earnings when warranted by circumstance.

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

INCOME TAX ACCOUNTING

The determination of the Trust’s income and other tax liabilities requires interpretation of complex laws and regulations. All tax filings are subject to audit and potential reassessment after the lapse of considerable time. Accordingly, the actual income tax liability may differ significantly from that estimated and recorded by management.

BUSINESS COMBINATIONS

Since inception, PrimeWest has grown considerably through combining with other businesses. PrimeWest uses the purchase method to account for its acquisitions. Under the purchase method, the acquiring company includes the fair value of the assets of the acquired entity on its balance sheet. The determination of fair value necessarily involves many assumptions. The valuation of oil and natural gas properties primarily involves placing a value on the oil and natural gas reserves. The valuation of oil and natural gas reserves entails the process described above under Proved, Probable and Proved Plus Probable Oil and Natural Gas Reserves, but also incorporates the use of economic forecasts that estimate future changes in prices and costs. This methodology is also used to value unproved oil and natural gas reserves. The valuation of these reserves, by their nature, is less certain than the valuation of Pr oved reserves.

GOODWILL

The process of accounting for the purchase of a company, described above, results in recognizing the fair value of the acquired company’s assets on the balance sheet of the acquiring company. Any excess of the purchase price over fair value is recorded as goodwill. Since goodwill results from the culmination of a process that is inherently imprecise, the determination of goodwill is also imprecise. In accordance with CICA section 3062, Goodwill and Other Intangible Assets, goodwill is not amortized but assessed periodically for impairment. The process of assessing goodwill for impairment necessarily requires PrimeWest to determine the fair value of its assets and liabilities. Such a process involves considerable judgment.

Recent Accounting Pronouncements Issued But Not Implemented

The following new or amended standards and guidelines were issued but not implemented by PrimeWest.

EXCHANGEABLE SHARE ACCOUNTING

In January 2005 the CICA issued Emerging Issues Committee (EIC) 151, “Exchangeable Securities Issued by Subsidiaries of Income Trusts.“ EIC 151 deals with the presentation of exchangeable securities on the balance sheet. The EIC states that exchangeable securities should be included as part of Unitholders’ equity only if the holders of the exchangeable securities are entitled to receive distributions of earnings economically equivalent to distributions received by units of the income trust and if the exchangeable securities ultimately are required to be exchanged for units of the income trust as a result of the passage of a fixed period of time. The Trust has reviewed the impact of the pronouncement and determined that it does not materially impact its Consolidated Financial Statements.

FINANCIAL INSTRUMENTS

In May 2005, the CICA issued the Handbook Section “Financial Instruments – Recognition and Measurement”. This Section establishes standards for recognizing and measuring financial assets, financial liabilities and non-financial derivatives. The new section will apply to interim and annual financial statements relating to fiscal years beginning on or after October 1, 2006. The Trust is reviewing the section and has yet to determine the impact on the Consolidated Financial Statements.

Business Risks

PrimeWest’s operations are affected by a number of underlying risks, both internal and external to the Trust. These risks are similar to those affecting others in both the conventional oil and natural gas royalty trust sector and the conventional oil and natural gas exploration and production sector. The Trust’s financial position, results of operations, and cash available for distribution to Unitholders are directly impacted by these factors. These factors are discussed below.

COMMODITY PRICE, FOREIGN EXCHANGE AND INTEREST RATE RISK

The two most important factors affecting the level of cash distributions available to Unitholders are the level of production achieved by PrimeWest, and the price received for its products. These prices are influenced in varying degrees by factors outside of the Trust’s control. These factors include:

World market forces, specifically the actions of OPEC and other large crude oil producing countries including Russia, and their implications for the supply of crude oil;

World and North American economic conditions, which influence the demand for crude oil and natural gas and the level of interest rates set by the governments of Canada and the U.S.;

Weather conditions that influence the demand for natural gas and heating oil;

The Canadian/U.S. currency exchange rate, which affects the price received for crude oil, as the price of crude oil is referenced in U.S. dollars;

Transportation availability and costs; and

Price differentials between world and North American markets based on transportation costs to major markets and quality of production.

To mitigate these risks, PrimeWest has an active hedging program in place based on an established set of criteria that has been approved by the Board of Directors. The results of the hedging program are reviewed against these criteria and the results are actively monitored by the Board.

Beyond the hedging strategy, PrimeWest also mitigates risk by having a diversified marketing portfolio, by transacting with a number of counterparties and by limiting exposure to each counterparty. In 2005, approximately 25% of the Trust’s natural gas production was sold to aggregators and 75% into the Alberta short-term or export long-term markets.

The contracts that PrimeWest has with aggregators vary in length. They represent a blend of domestic and U.S. markets and fixed and floating prices designed to provide price diversification to our revenue stream.

The primary objectives of our hedging program are to stabilize cash flow, reducing its volatility, to lock in the economics of major acquisitions and to protect our capital structure when commodity prices cycle downwards, while retaining some exposure to pricing upside. In 2005, PrimeWest recorded a loss of $44.3 million from commodity hedges ($0.54 per Trust Unit), while in 2004, PrimeWest recorded a loss of $28.2 million ($0.45 per Trust Unit) to our cash flow through various physical and financial hedging transactions.

OPERATIONAL AND OTHER BUSINESS RISKS

PrimeWest is also exposed to a number of risks related to its activities within the oil and natural gas industry that also have an impact on the amount of cash available to Unitholders. These risks and the manner in which PrimeWest seeks to mitigate these risks include, but are not limited to:

Risk

We Mitigate By

Production

Risk associated with the production of oil and natural gas – includes well operations, processing and the physical delivery of commodities to market.

Performing regular and proactive protective well, facility and pipeline maintenance supported by telemetry, physical inspection and diagnostic tools.

Commodity Price

Fluctuations in natural gas, crude oil and natural gas liquids prices.

Hedging. See note 17 to the Consolidated Financial Statements.

Transportation

Market risk related to the availability of transportation to market and potential disruption in delivery systems.

Diversifying the transportation systems on which we rely to get our product to market.

Natural Production Decline

Development risk associated with capital enhancement activities undertaken – the risk that capital spending on activities such as drilling, well completions, well workovers and other capital activities will not result in reserve additions or in added production in quantities sufficient to replace annual production declines.

Diversifying our capital spending program over a large number of projects so that excessive capital is not risked on any one activity. We also have a highly skilled technical team of geologists, geophysicists and engineers working to apply the latest technology in planning and executing capital programs. Capital is spent only after strict economic criteria for estimated production and reserve additions are met.

Acquisitions

Acquisition risk associated with acquiring producing properties at sufficiently low cost to renew our inventory of assets.

Continually scanning the marketplace for opportunities to acquire assets. Our technical acquisition specialists evaluate potential corporate or property acquisitions and identify areas for value enhancement through operational efficiencies or capital investment. All prospects are subjected to rigorous economic review against established acquisition and economic hurdle rates. In some cases, we may also hedge commodity prices to protect the acquisition economics in the near term.

Reserves

Reserve risk in respect of the quantity and quality of recoverable reserves estimated versus ultimately recovered.

Contracting our reserves evaluation to a reputable third-party consultant, GLJ. The work and independence of GLJ is reviewed by the Operations and Reserves Committee of the Board of Directors of PrimeWest. Our strategy is to invest in mature, longer-life properties having a higher proved producing component in which the reserve risk is generally lower and cash flows are more stable and predictable.

Environmental Health and Safety (EH&S)

Environmental, health and safety risks associated with oil and natural gas properties and facilities.

Establishing and adhering to strict guidelines for EH&S including training, proper reporting of incidents, supervision and awareness. PrimeWest has active community involvement in field locations including regular meetings with stakeholders in our operational areas. PrimeWest carries adequate insurance to cover property losses, liability and business interruption.

These risks are reviewed regularly by the Corporate Governance and EH&S Committee of the Board of Directors, which acts as PrimeWest’s Environmental, Health and Safety Committee.

Regulation, Tax and Royalties

Changes in government regulations, including reporting requirements, income tax laws, operating practices, environmental protection requirements and royalty rates.

Keeping informed of proposed changes in regulations and laws to properly respond to and plan for the effects that these changes may have on our operations.

Liability of Unitholders is Uncertain

There is no statutory protection for Unitholders from liabilities of the Trust arising prior to July 1, 2004.

Limiting the business of the Trust to the right to receive the net cash flow of PrimeWest Energy Inc. All of the oil and natural gas business operations of PrimeWest are conducted by PrimeWest Energy Inc. PrimeWest Energy Inc. has a vigorous EH&S program as well as significant insurance protection.

Income Taxes – Unitholders – 2005

For the 2005 taxation year, Canadian Unitholders of PrimeWest were paid $3.66 per Trust Unit in distributions. Of this distribution amount, 25% or $0.92 per Trust Unit is deemed a tax-deferred return of capital, and 75% or $2.74 per Trust Unit is taxable to Unitholders as other income (taxed at the same rate as interest income).

For Unitholders resident in the U.S., the taxability of distributions is calculated using U.S. tax rules, which allow for the deduction of Crown royalties and accounting-based depletion. Distributions are taxable as dividends with 81.25%of the 2005 distributions taxable as a “qualified dividend” and the remaining18.75% treated as a tax-deferred return of capital. A 15% withholding tax applies to distributions paid to U.S. Unitholders. Further details regarding the withholding tax is available on PrimeWest’s website at www.primewestenergy.com.

For Canadian and U.S. Unitholders, the tax-deferred return of capital portion reduces the Unitholder’s adjusted cost base for purposes of calculating a capital gain or loss upon ultimate disposition of their Trust Units. Unitholders contemplating a disposition may wish to consult the “Unitholder Info” section on PrimeWest’s website and use the adjusted cost base calculator.

PrimeWest recommends that all Unitholders contact their tax advisors to discuss tax-related issues.

Positive
Negative
Uncertain
Constraining
Legalese
Litigious
Readability	6th grade Avg

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

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