PrimeWest Energy Trust
TSX : PWI.UN
TSX : PWX
TSX : PWI.DB.A
TSX : PWI.DB.B
NYSE : PWI
TSX : PWI.DB.C

PrimeWest Energy Trust

May 02, 2007 17:38 ET

PrimeWest Energy Trust Announces First Quarter 2007 Results

CALGARY, ALBERTA--(CCNMatthews - May 2, 2007) - PRIMEWEST ENERGY TRUST (TSX:PWI.UN) (TSX:PWX) (TSX:PWI.DB.A) (TSX:PWI.DB.B) (TSX:PWI.DB.C) (NYSE:PWI) (PRIMEWEST OR THE TRUST) TODAY ANNOUNCES INTERIM OPERATING AND FINANCIAL RESULTS FOR THE QUARTER ENDED MARCH 31, 2007. UNLESS OTHERWISE NOTED, ALL FIGURES CONTAINED IN THIS REPORT ARE IN CANADIAN DOLLARS.

First Quarter 2007 Highlights:

- Distributions in the first quarter were $0.75 per Trust Unit representing a payout ratio of approximately 72% of funds flow from operations compared to fourth quarter 2006 distributions of $0.75 per Trust Unit, which represented a payout ratio of approximately 74% of funds flow from operations.

- Funds flow from operations for the first quarter was $93.8 million ($1.04 per Trust Unit) compared to $84.6 million ($1.01 per Trust Unit) in the previous quarter and $101.3 million ($1.25 per Trust Unit) in the first quarter of 2006.

- First quarter 2007 production averaged 41,748 BOE per day, compared to the fourth quarter 2006 rate of 41,386 BOE per day. The increase in volumes is mainly due to the incremental volumes from development capital exceeding natural decline. PrimeWest expects full year 2007 production volumes to average between 39,000 - 40,000 BOE per day which includes the planned divestitures of approximately 1,000 BOE per day in the second quarter of 2007.

- Development capital expenditures in the first quarter were $71.5 million with drilling, completion and tie-in expenditures of $57.4 million resulting in 26 gross wells (18.7 net) being drilled with a cased success rate of 100%.

- On January 11, 2007, PrimeWest issued 6,420,000 Trust Units for net proceeds of $142.4 million and Series III Convertible Unsecured Subordinated Debentures which bear interest at 6.5% for net proceeds of $192.0 million.

- Net debt to annualized first quarter 2007 funds flow from operations was approximately 1.9 times at March 31, 2007, compared to net debt to annualized fourth quarter 2006 funds flow from operations of 2.4 times at December 31, 2006.

Subsequent Event

- Mr. Dennis Feuchuk, Vice President Finance and Chief Financial Officer tendered his resignation effective July 6, 2007. Mr. Douglas Fraser will assume the role of Vice President Finance and Chief Financial Officer effective June 1, 2007.

MANAGEMENT'S DISCUSSION AND ANALYSIS AS OF MAY 2, 2007

The following is management's discussion and analysis (MD&A) of PrimeWest's operating and financial results for the three months ended March 31, 2007, compared with the preceding quarter and the corresponding period in the prior year as well as information and opinions concerning the Trust's future outlook based on currently available information.

Forward-Looking Information

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

Certain statements contained in this quarterly 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 this quarterly report. These statements speak only as of the date of this quarterly report.

In particular, this quarterly report contains 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 there from;

- 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 quarterly report 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 in this quarterly 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;

- Tax treatment of the trust and its subsidiaries;

- 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 in this quarterly report.

These factors should not be construed as exhaustive. The forward-looking statements contained in this quarterly report are expressly qualified by this cautionary statement. Except as may be required by applicable securities laws we undertake no obligation to publicly update or revise any forward-looking statements.

All figures reported in Canadian dollars unless otherwise stated.

Production figures stated are 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 March 31, 2007, and concluded that PrimeWest's disclosure controls and procedures were effective to ensure that information PrimeWest is required to disclose:

- In its annual filings and interim filings (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 and interim filings 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 December 31, 2006, which have materially affected, or are reasonably likely to materially affect PrimeWest's internal control over financial reporting.

Non-GAAP Measures

This MD&A contains the following measurements that are not defined by Canadian Generally Accepted Accounting Principles (GAAP):

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

- Distributions per Trust Unit; and

- Net debt per Trust Unit.

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

Funds flow from operations is measured as cash flow from operating activities before changes in non-cash working capital. Funds flow from operations does not represent operating cash flows or operating profits for the period and should not be viewed as an alternative to cash flow from operating activities calculated in accordance with GAAP. Funds flow from operations is a key performance indicator of PrimeWest's ability to generate cash and finance operations and pay monthly distributions.

Funds flow from operations per Trust Unit on a basic basis is calculated by dividing funds flow from operations by the weighted average number of Trust Units outstanding plus Trust Units issueable upon the exchange of the outstanding Exchangeable Shares of PrimeWest Energy Inc. (Exchangeable Shares). Funds flow from operations per Trust Unit on a diluted basis is calculated using funds flow from operations 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 issueable upon the exchange of outstanding Exchangeable Shares and includes the Trust Units issueable pursuant to the conversion of the Debentures, and Trust Units issueable pursuant to the Long-Term Incentive Plan (LTIP).

Distributions per Trust Unit disclose the cash distributions accrued in the period based on the number of Trust Units outstanding on the applicable record dates.

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 and liabilities divided by the number of Trust Units outstanding and Trust Units issueable upon the exchange of outstanding Exchangeable Shares and Trust Units issueable pursuant to the LTIP at March 31, 2007.

Business Strategy

PrimeWest Energy Trust is an Alberta based conventional oil and natural gas royalty trust actively managed to generate monthly cash distributions for the holders of Trust Units (Unitholders). The Trust's operations are focused in the Western Canada Sedimentary Basin and Montana, North Dakota and Wyoming in the United States. 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 MD&A, along with a discussion of our performance for the three months ended March 31, 2007, and our goals for 2007 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 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 approximately 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 (U.S. Secured Notes), Pounds Sterling denominated Senior Secured Notes (U.K. Secured Notes) and Debentures. Our diversified debt instruments help to reduce our reliance on the bank syndicate. PrimeWest's commodity hedging strategy is designed to reduce the volatility of cash flow by providing some near term downside price protection. Hedging a portion of our production protects acquisition economics and our capital structure and provides partial protection against short-term declines in commodity prices. Since 2003, PrimeWest has followed a strategy of maintaining a distribution payout ratio within 70-90% of funds flow from operations, calculated on an annual basis, recognizing that during periods of volatile commodity prices the payout ratio may move out of this range. The Board of Directors of PrimeWest considers a variety of factors in establishing the monthly distribution level including, but not limited to: commodity price outlook, cash flow forecast, capital development plans, debt levels, tax considerations and competitive industry distribution practices. Further, the October 31 proposals discussed under Taxation of the Trust, have created additional uncertainty with respect to the payout ratio. At this time, PrimeWest is unable to predict what payout ratio it will maintain in the future.

The first quarter 2007 payout ratio (being the ratio of distributions paid or declared to funds flow from operations) was approximately 72% of funds flow from operations. Retained cash flow was utilized to fund a part of the Trust's capital spending program. PrimeWest's ratio of net debt to annualized first quarter funds flow from operations was approximately 1.9 times at March 31, 2007.

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. 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 issued and outstanding.

Corporate Governance

PrimeWest is 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 dated March 15, 2007, for its upcoming annual general meeting and is available on our website at www.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.



Financial Highlights
Three Months Ended
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$ Millions, except per BOE (1) and
per Trust Unit amounts Mar 31, 2007 Dec 31, 2006 Mar 31, 2006
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Gross revenue 189.7 173.6 191.1
per BOE 50.49 45.59 55.79
Funds flow from operations 93.8 84.6 101.3
per BOE 24.98 22.23 29.57
per Trust Unit - basic (2) 1.04 1.01 1.25
per Trust Unit - diluted (3) 0.98 1.00 1.22
Royalty expense 40.0 33.7 44.7
per BOE 10.65 8.86 13.04
Operating expense 38.9 39.6 32.7
per BOE 10.36 10.40 9.54
General and administrative expense
(G&A) 9.3 8.6 6.7
per BOE 2.47 2.27 1.97
Interest expense (4) 12.2 13.0 4.6
per BOE 3.25 3.42 1.34
Distributions to Unitholders 67.6 62.3 86.8
per Trust Unit (5) 0.75 0.75 1.08
Net debt (6) 716.3 820.8 364.5
per Trust Unit (7) 7.81 9.74 4.42
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(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 represent a value equivalency at the wellhead.

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

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

(4) Interest expense includes the interest on the Debentures.

(5) Based on Trust Units outstanding at the record dates for distributions
during the period.

(6) Net debt is long-term debt including the Debentures adjusted for working
capital, excluding current derivative and future income tax assets and
liabilities.

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


Operating Highlights

Three Months Ended
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Daily Production Volumes Mar 31, 2007 Dec 31, 2006 Mar 31, 2006
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Natural gas (mmcf/day) 169.4 169.9 166.0
Crude oil (bbls/day) 9,071 8,950 6,867
Natural gas liquids (bbls/day) 4,443 4,127 3,525
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Total (BOE per day) 41,748 41,386 38,062
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Total BOE 3,757,320 3,807,512 3,425,580
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Average Realized Sales Prices
Three Months Ended
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Mar 31, 2007 Dec 31, 2006 Mar 31, 2006
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Natural gas ($/Mcf) (1) 7.79 6.79 9.09
Crude oil ($/bbl) 58.23 55.13 57.09
Natural gas liquids ($/bbl) 53.78 52.52 59.34
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Total Oil Equivalent ($/BOE) 50.00 45.03 55.44
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Realized derivative gains/(losses)
($/BOE) 1.60 2.99 (0.27)
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Net realized price ($/BOE) 51.60 48.02 55.17
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(1) Excludes sulphur.

Funds Flow From Operations Reconciliation

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$ Millions
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Fourth quarter 2006 funds flow from
operations $ 84.6
Volumes (1.9)
Commodity prices 18.3
Net hedging change from prior
quarter (6.7)
Operating expenses 0.7
Royalties (6.3)
Site restoration and reclamation 1.5
Interest 0.3
Other 3.3
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First quarter 2007 funds flow from operations $ 93.8
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The above table includes non-GAAP measurements. (Refer to section regarding Non-GAAP Measurements)

A key performance driver for the Trust is funds flow from operations, which directly affects PrimeWest's ability to pay monthly distributions. Funds flow from operations 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 expense, site restoration and reclamation expenditures, interest expense, general and administrative (G&A) expense, derivative gains or losses, royalties and currency exchange rates. Some of these factors such as commodity prices, the currency exchange rate and royalties are uncontrollable from PrimeWest's perspective. Other factors that are to a certain extent controllable by PrimeWest are production levels and operating expense, as well as interest and G&A expense.



Reconciliation of Non-GAAP Measure

Three Months Ended
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$ Millions Mar 31, 2007 Dec 31, 2006 Mar 31, 2006
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Funds flow from operations $ 93.8 $ 84.6 $ 101.3
Change in non-cash working capital (3.3) 8.5 23.2
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Cash flow from operating activities $ 90.5 $ 93.1 $ 124.5
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Selected Canadian and U.S. Financial Results

Prior to 2006, PrimeWest had focused on oil and natural gas plays in Western Canada. In July 2006, PrimeWest acquired U.S. assets. The following table provides selected financial results from PrimeWest's Canadian and U.S. operations for the three months ended March 31, 2007.



Three Months Ended Mar 31, 2007
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$ Millions, except production volumes and
per unit prices (2) Canada U.S. Total
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Daily Production Volumes
Natural gas (mmcf/day) 168.5 0.9 169.4
Crude oil (bbls/day) 6,718 2,353 9,071
Natural gas liquids (bbls/day) 4,394 49 4,443
Total daily sales (BOE per day) 39,193 2,555 41,748
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Three Months Ended Mar 31, 2007
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Pricing (1)
Natural gas ($/Mcf) 7.80 7.40 7.79
Crude oil ($/bbl) 58.17 58.41 58.23
Natural gas liquids ($/bbl) 54.0 34.53 53.78
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Revenues (1)
Natural gas 118.2 0.6 118.8
Crude oil 35.1 12.4 47.5
Natural gas liquids 21.3 0.2 21.5
Royalties (37.4) (2.6) (40.0)
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Expenses
Operating 35.4 3.5 38.9
G&A 8.6 0.7 9.3
Depletion, depreciation and amortization 62.0 4.9 66.9
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Capital expenditures
Development and head office 60.8 11.8 72.6
Acquisition of oil and gas properties 9.8 1.7 11.5
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(1) Net of transportation expense. Excludes derivative gains and losses.

(2) Comparative segmented information is not provided for the three months
ended March 31, 2006, as the U.S. assets were acquired in July, 2006.

Quarterly Performance - Selective Measures

The table below highlights PrimeWest's performance for the first quarter
ended March 31, 2007, and the preceding seven quarters through 2005.

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2007 2006 2005
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$ Millions, except per
Trust Unit Amounts Q1 Q4 Q3 Q2 Q1 Q4 Q3 Q2
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Net Revenues 126.0 158.4 160.7 134.8 170.0 237.1 101.7 155.3
Net Income 5.5 9.6 64.0 65.7 68.9 101.5 27.3 54.7
Funds Flow from
Operations 93.8 84.6 91.4 86.8 101.3 128.6 105.1 92.8
Net income per Trust
Unit - basic 0.06 0.11 0.78 0.81 0.85 1.27 0.35 0.74
Net income per Trust
Unit - diluted 0.06 0.11 0.76 0.79 0.83 1.23 0.35 0.72
Funds flow per Trust
Unit - basic 1.04 1.01 1.11 1.06 1.25 1.61 1.34 1.26
Funds flow per Trust
Unit - diluted 0.98 1.00 1.09 1.03 1.22 1.56 1.29 1.18
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Net revenues are impacted primarily by commodity prices, production volumes, royalties and realized and unrealized gains or losses on derivatives.

The non-cash items, which include depletion, depreciation and amortization (DD&A), unit-based compensation, future income taxes, unrealized foreign exchange gains or losses and changes in unrealized gains or losses on derivatives will not affect PrimeWest's ability to pay a monthly distribution.



Capital Expenditures
Three Months Ended
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$ Millions Mar 31, 2007 Dec 31, 2006 Mar 31, 2006
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Land and lease acquisitions $ 1.1 $ 1.6 $ 3.4
Geological and geophysical 2.5 0.7 1.5
Drilling and completions 49.0 38.8 53.5
Investment in facilities
Equipping and tie-in 8.4 9.2 15.6
Gas gathering and compression 6.8 2.9 1.2
Production facilities 2.3 2.7 4.7
Capitalized G&A 1.4 1.3 1.4
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Development capital 71.5 57.2 81.3
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Acquisition of oil and gas assets 11.5 0.4 0.2
Dispositions - (0.1) (3.1)
Leasehold improvements, furniture
and equipment 1.1 0.5 1.3
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Net capital expenditures $ 84.1 $ 58.1 $ 79.7
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During the first quarter of 2007, PrimeWest's development capital expenditures totalled $71.5 million, compared to $57.2 million invested in the fourth quarter of 2006 and $81.3 million in the first quarter of 2006. Of the $71.5 million total, $57.4 million or 80.3% was invested in drilling, completions and tie-ins, which contribute to new reserve additions and help offset natural production decline. PrimeWest drilled 26 gross wells (18.7 net) with a 100% cased success rate.

In March 2007, PrimeWest acquired an additional working interest in its assets in the Columbia area for $9.8 million. Annualized production from the acquisition is expected to be approximately 190 BOE per day.

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.

Development Capital Update - Canada and U.S.

PrimeWest's four key development plays are Conventional Development, Tight Gas, U.S. Oil assets and Coalbed Methane (CBM).

Conventional Development

PrimeWest continues to invest in development opportunities at our conventional plays, which include key properties at: Valhalla, Laprise, Wilson Creek, and Crossfield/Lone Pine Creek. Development expenditures during the first quarter totalled $46.1 million, including $30.6 million for drilling and completions, $2.2 million for land and seismic and $13.3 million for equipping, tie-in and facilities. A total of 23 gross wells were drilled during the quarter.

The following provides a description of the Wilson Creek, Crossfield/Lone Pine Creek, Valhalla and Laprise areas, which are major properties in our conventional development play.

Wilson Creek

In the Wilson Creek area, PrimeWest drilled 9 operated wells in the first quarter of 2007, targeted at various formations including Edmonton, Belly River, Glauconitic, Mannville, and Rock Creek. Capital expenditures at Wilson Creek were $15.6 million, including $12.3 million for drilling and completions, $3.2 million for equipping, tie-in and facilities and $0.1 for land and seismic.

Crossfield/Lone Pine Creek

Crossfield/Lone Pine Creek development targets deeper prospects in the Leduc and Nisku pools. First quarter development capital expenditures at Crossfield/Lone Pine Creek were $7.0 million.

Valhalla and Laprise

Valhalla provides the Trust with low-risk downspacing and infill drilling opportunities in the Montney and Doig formations with additional multi-zone natural gas targets in the Gething and Halfway formations. PrimeWest invested $3.5 million for drilling and completions and tie-ins and drilled two wells in the quarter.

At Laprise, PrimeWest invested $8.1 million in drilling and completions, $1.2 million on seismic and $4.0 million on equipping, tie-in and facilities. Five wells were drilled during the first quarter of 2007.

Tight Gas Plays

PrimeWest's Tight Gas plays (Caroline, Columbia, Harlech, Edson and Ferrier) are located in west central Alberta, and target the deeper Viking, Mannville and Cardium sandstones. Tight Gas wells are characterized by high initial production rates that quickly level off at a lower more stabilized rate and production of high heat content, liquids-rich gas.

PrimeWest continued its development program in its Tight Gas plays in the first quarter 2007. Capital expenditures for the three months ended March 31, 2007, included $12.7 million for drilling and completions, equipping, tie-in and facilities. Two gross wells were drilled and completed during the quarter and three wells were re-completed.

U.S. Oil Assets

In 2006, PrimeWest acquired producing oil and gas assets located in Montana, North Dakota and Wyoming. The acquisition established a new operating area within the Williston Basin, providing considerable waterflood and development drilling potential. The major fields acquired were Flat Lake, Dwyer and Goose Lake in Montana; Rival, Grenora, Alexander, Wiley, Glenburn and Sherwood in North Dakota; and Rocky Point in Wyoming.

Expenditures in the first quarter of $11.8 million included $9.8 million for drilling, completions and tie-ins, $1.0 million for seismic and $1.0 million on capital workovers. Two wells were drilled and four were completed in the first quarter.

Coalbed Methane

CBM is an emerging resource play in Western Canada. PrimeWest has approximately 124,000 net acres of land on the developing Horseshoe Canyon CBM trend. PrimeWest is in the preliminary assessment stage of its CBM assets and successes in 2006 resulted in the first booking of CBM reserves at year end. Commencement on commercial development of the CBM will be contingent on the natural gas price. PrimeWest incurred minimal expenditures in the CBM play during the first quarter of 2007.



Daily Production Volumes

Three Months Ended
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Daily Production Volumes Mar 31, 2007 Dec 31, 2006 Mar 31, 2006
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Natural gas (mmcf/day) 169.4 169.9 166.0
Crude oil (bbls/day) 9,071 8,950 6,867
Natural gas liquids (bbls/day) 4,443 4.127 3,525
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Total (BOE per day) 41,748 41,386 38,062
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PrimeWest's production volumes averaged 41,748 BOE per day in the first quarter of 2007, compared to 41,386 BOE per day in the fourth quarter 2006. The 1% increase in volumes is mainly due to the continued success with the Canadian drilling program. Incremental volumes resulting from PrimeWest's capital development expenditures offset volume reductions due to natural decline.

For the three months ended March 31, 2007, production volumes increased by approximately 10% when compared to the same period in 2006 due to the acquisition of the U.S. assets early in the third quarter of 2006 and to incremental volumes from development capital exceeding natural decline.

Production Outlook

PrimeWest expects full year 2007 production volumes to average between 39,000 - 40,000 BOE per day in 2007.



Commodity Prices

Three Months Ended
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Benchmark Prices Mar 31, 2007 Dec 31, 2006 Mar 31, 2006
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Natural gas
NYMEX (US$/mcf) 6.96 6.62 9.08
AECO (C$/mcf) 7.46 6.36 9.27
Crude oil WTI (US$/bbl) 58.27 60.21 63.48
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Benchmark Commodity Prices

The following table sets forth benchmark historical and estimated future
commodity prices.

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Past Four Next Four Quarters
Quarters (Actual) (Forward Markets)(1)
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Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1
2006 2006 2006 2007 2007 2007 2007 2008
----------------------------------------------------------------------------
Natural gas AECO
(C$/mcf) 6.27 6.03 6.36 7.46 7.81 8.12 8.96 9.81
Crude oil WTI
(US$/bbl) 70.70 70.48 60.21 58.27 67.48 69.14 69.73 69.96
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(1) As at March 31, 2007.

Average Realized Sales Prices

Three Months Ended
----------------------------------------------------------------------------
Mar 31, 2007 Dec 31, 2006 Mar 31, 2006
----------------------------------------------------------------------------
Natural gas ($/Mcf) (1)(2) 8.01 7.38 9.13
Without derivatives 7.79 6.79 9.09
Crude oil ($/bbl)(1) 61.54 57.72 54.51
Without derivatives 58.23 55.13 57.09
Natural gas liquids ($/bbl) 53.78 52.52 59.34
----------------------------------------------------------------------------
Total Oil Equivalent ($/BOE) (1) 51.60 48.02 55.17
Without derivatives 50.00 45.03 55.44
----------------------------------------------------------------------------
Realized derivative gains/(losses)
included in prices above ($/BOE) 1.60 2.99 (0.27)
----------------------------------------------------------------------------

(1) Includes derivatives gains/losses.

(2) Excludes sulphur.


Realized natural gas prices increased by 15% in the first quarter of 2007 compared to the previous quarter, excluding the effect of derivatives.

Natural gas prices began to recover from earlier softness by late January as weather turned cold again in North America. Record cold temperature during February resulted in a larger than normal withdrawal of gas volume from storage. By March end, the U.S. gas storage level has fallen to around 1.5 Tcf, below the level of last year. Even though current gas storage is still higher than the average of the last 5 years, the significant storage overhang that had burdened the gas market since last October has been lifted. Going forward, weather will continue to play an important role in determining gas supply and demand balances, as will the increased LNG import, and the impact of reduced Canadian supply.

First quarter realized crude oil prices were 6% higher than the previous quarter, excluding the effect of derivatives. The crude oil market started the New Year in a similar trend as natural gas, driven down by the concerns for build up in inventory that was caused partially by warm weather. A combination of colder temperatures later on in the quarter, OPEC quota reduction and geopolitical events have resulted in oil price recovery above the US $60/Bbl level by the end of March.



Sales Revenue

Three Months Ended
----------------------------------------------------------------------------
Revenue ($ Millions) Mar 31, % of Dec 31, % of Mar 31, % of
(1) (2) (3) 2007 Total 2006 Total 2006 Total
----------------------------------------------------------------------------
Natural gas $ 118.8 63 $ 106.1 62 $ 135.8 72
Crude oil 47.5 25 45.4 26 35.3 19
Natural gas liquids 21.5 12 19.9 12 18.8 9
----------------------------------------------------------------------------
Total $ 187.8 $ 171.4 $ 189.0
----------------------------------------------------------------------------

(1) Excludes sulphur.

(2) Net of transportation expenses.

(3) Excludes impact of derivatives.


First quarter 2007 revenues were 10% higher than the previous quarter mainly due to the increases in realized crude oil and natural gas prices.

First quarter 2007 revenues were relatively flat compared to the same period in 2006, due to lower natural gas prices offset by increases to crude oil prices and crude oil volumes.

Approximately 68% of PrimeWest's production on an energy equivalent basis is natural gas; therefore, the Trust has greater sensitivity to changes in natural gas prices than crude oil prices.

Financial Derivatives

As part of our risk management strategy PrimeWest uses financial instruments to manage commodity prices. These instruments are commonly referred to as "hedges." The purpose of the hedging program is to reduce volatility in cash flows and to protect acquisition economics against the unpredictable commodity price environment. PrimeWest did not elect to adopt hedge treatment for accounting purposes.

PrimeWest also entered into a financial swap which converts the interest and principal payments associated with the U.K. Senior Notes into Canadian dollars from pounds sterling. The pounds sterling debt and interest payable are converted to Canadian dollars at the foreign currency exchange rate in effect at the period end date.

PrimeWest's derivatives are marked-to-market at the end of each reporting period with the resulting change in the gain or loss from the prior period reflected in earnings for that period. The unrealized gain is a point-in-time measurement of PrimeWest's hedging position at the end of the period. The magnitude of the gain or loss will fluctuate with changes to commodity prices.

The table below provides a summary of net realized and unrealized gains and losses on financial derivatives for the three months ended March 31, 2007 and 2006.



Three Months Ended March 31, 2007
----------------------------------------------------------------------------
Foreign
($ millions except per BOE) Oil Gas Exchange Total
----------------------------------------------------------------------------
Realized gains on derivatives $ 2.7 $ 3.3 $ - $ 6.0
Unrealized losses on
derivatives (5.9) (23.4) (2.2) (31.5)
----------------------------------------------------------------------------
Total losses on derivatives $ (3.2) $ (20.1) $ (2.2) $ (25.5)
----------------------------------------------------------------------------
Realized gains on derivatives
per BOE $ 0.72 $ 0.88 $ - $ 1.60
Unrealized losses in
derivatives per BOE $ (1.57) $ (6.23) $ (0.58) $ (8.38)
----------------------------------------------------------------------------

Three Months Ended March 31, 2006
----------------------------------------------------------------------------
Foreign
($ millions except per BOE) Oil Gas Exchange Total
----------------------------------------------------------------------------
Realized gains/(losses) on
derivatives $ (1.6) $ 0.7 $ - $ (0.9)
Unrealized gains on
derivatives 0.5 21.7 - 22.2
----------------------------------------------------------------------------
Total gains/(losses) on
derivatives $ (1.1) $ 22.4 $ - $ 21.3
----------------------------------------------------------------------------
Realized gains/(losses) on
derivatives per BOE $ (0.46) $ 0.19 $ - $ (0.27)
----------------------------------------------------------------------------
Unrealized gains on
derivatives per BOE $ 0.13 $ 6.34 $ - $ 6.47
----------------------------------------------------------------------------


The following table sets forth the approximate percentage of future anticipated production volumes hedged at March 31, 2007, net of anticipated royalties, reflecting full production declines with no offsetting additions.



----------------------------------------------------------------------------
Production Volumes Hedged
(%) Q2 2007 Q3 2007 Q4 2007 Q1 2008 Q2 2008 Q3 2008
----------------------------------------------------------------------------
Crude Oil 66 64 60 39 27 14
Natural Gas 63 62 51 49 31 16
----------------------------------------------------------------------------

A listing of derivative contracts in place at March 31, 2007, follows:

Crude Oil

----------------------------------------------------------------------------
Period Volume (bbls/d) Type WTI Price (US$/bbl)
----------------------------------------------------------------------------
Apr - Jun 07 500 Costless Collar 50.00/80.00
Apr - Jun 07 500 Costless Collar 55.00/91.30
Apr - Jun 07 500 Costless Collar 55.00/90.08
Apr - Jun 07 500 Costless Collar 60.00/95.40
Apr - Jun 07 500 Costless Collar 65.00/93.90
Apr - Jun 07 1300 Costless Collar 70.00/84.25
Apr - Jun 07 500 Costless Collar 55.00/75.00
Apr - Jun 07 500 Costless Collar 60.00/73.45
Apr - Jun 07 500 Costless Collar 60.00/70.25
Apr - Jun 07 500 Costless Collar 60.00/75.65
Jul - Sep 07 500 Costless Collar 60.00/92.75
Jul - Sep 07 500 Swap 75.20
Jul - Sep 07 500 Costless Collar 65.00/92.60
Jul - Sep 07 900 Costless Collar 70.00/83.25
Jul - Sep 07 500 Costless Collar 55.00/77.80
Jul - Sep 07 500 Costless Collar 60.00/75.10
Jul - Sep 07 500 Costless Collar 60.00/73.20
Jul - Sep 07 500 Costless Collar 60.00/75.03
Jul - Sep 07 500 Costless Collar 60.00/71.25
Jul - Sep 07 500 Costless Collar 60.00/75.70
Oct - Dec 07 500 Costless Collar 60.00/90.25
Oct - Dec 07 500 Swap 74.58
Oct - Dec 07 500 Costless Collar 65.00/91.35
Oct - Dec 07 800 Costless Collar 70.00/82.10
Oct - Dec 07 500 Costless Collar 55.00/78.25
Oct - Dec 07 500 Costless Collar 60.00/76.60
Oct - Dec 07 500 Costless Collar 60.00/75.20
Oct - Dec 07 500 Costless Collar 60.00/76.60
Oct - Dec 07 500 Costless Collar 60.00/75.05
Jan - Mar 08 500 Costless Collar 55.00/78.00
Jan - Mar 08 500 Costless Collar 60.00/77.10
Jan - Mar 08 500 Costless Collar 60.00/76.60
Jan - Mar 08 500 Costless Collar 60.00/70.00
Jan - Mar 08 500 Costless Collar 60.00/75.10
Jan - Mar 08 500 Costless Collar 60.00/75.25
Apr - Jun 08 500 Costless Collar 60.00/77.35
Apr - Jun 08 500 Costless Collar 60.00/70.00
Apr - Jun 08 500 Costless Collar 60.00/75.95
Apr - Jun 08 500 Costless Collar 60.00/75.10
Jul - Sep 08 500 Costless Collar 60.00/75.05
Jul - Sep 08 500 Costless Collar 60.00/75.25

Natural Gas

----------------------------------------------------------------------------
Period Volume (mmcf/d) Type AECO Price (C$/mcf)
----------------------------------------------------------------------------
Apr - Jun 07 5.0 3 Way 6.33/7.39/11.24
Apr - Jun 07 5.0 Costless Collar 6.33/10.64
Apr - Jun 07 5.0 Costless Collar 6.33/10.23
Apr - Jun 07 5.0 Costless Collar 5.28/9.34
Apr - Jun 07 5.0 Costless Collar 6.33/11.39
Apr - Jun 07 5.0 Costless Collar 6.33/11.66
Apr - Jun 07 10.0 Swap 7.71
Apr - Jun 07 10.0 Swap 7.74
Apr - Jun 07 5.0 Swap 8.17
Apr - Jun 07 5.0 Swap 7.10
Apr - Jun 07 5.0 Swap 7.41
Apr - Jun 07 5.0 Costless Collar 6.86/8.55
Apr - Jun 07 5.0 Costless Collar 6.86/8.55
Jul - Sep 07 5.0 Costless Collar 6.33/11.61
Jul - Sep 07 5.0 Costless Collar 6.33/10.87
Jul - Sep 07 5.0 Costless Collar 5.28/10.02
Jul - Sep 07 5.0 Costless Collar 6.33/12.05
Jul - Sep 07 5.0 Costless Collar 6.33/12.45
Jul - Sep 07 10.0 Swap 7.90
Jul - Sep 07 10.0 Swap 7.90
Jul - Sep 07 5.0 Swap 8.33
Jul - Sep 07 5.0 Costless Collar 6.33/8.81
Jul - Sep 07 5.0 Swap 7.64
Jul - Sep 07 5.0 3 Way 6.33/7.39/9.29
Jul - Sep 07 5.0 Costless Collar 6.86/9.18
Oct - Dec 07 5.0 Costless Collar 7.39/12.28
Oct - Dec 07 5.0 Costless Collar 5.28/12.66
Oct - Dec 07 5.0 Costless Collar 7.39/12.77
Oct - Dec 07 5.0 Costless Collar 7.39/13.40
Oct - Dec 07 10.0 Costless Collar 7.39/9.84
Oct - Dec 07 10.0 Costless Collar 7.39/10.29
Oct - Dec 07 5.0 Costless Collar 7.39/9.71
Oct - Dec 07 5.0 Costless Collar 7.39/10.76
Oct - Dec 07 5.0 Costless Collar 7.39/10.60
Jan - Mar 08 5.0 Costless Collar 6.33/12.71
Jan - Mar 08 5.0 Costless Collar 8.44/15.67
Jan - Mar 08 10.0 Costless Collar 7.39/12.40
Jan - Mar 08 10.0 Costless Collar 7.39/11.61
Jan - Mar 08 5.0 Costless Collar 7.39/11.56
Jan - Mar 08 5.0 Costless Collar 7.39/11.61
Jan - Mar 08 5.0 Costless Collar 7.39/12.55
Jan - Mar 08 5.0 Costless Collar 7.39/12.87
Apr - Jun 08 10.0 Costless Collar 7.39/8.97
Apr - Jun 08 5.0 Costless Collar 6.33/9.76
Apr - Jun 08 5.0 Costless Collar 7.39/8.91
Apr - Jun 08 5.0 3 Way 6.33/7.39/10.13
Apr - Jun 08 5.0 Costless Collar 7.39/8.97
Apr - Jun 08 5.0 Costless Collar 7.39/9.50
Jul - Sep 08 5.0 Costless Collar 7.39/9.39
Jul - Sep 08 5.0 Costless Collar 7.39/9.50
Jul - Sep 08 5.0 3 Way 6.33/7.39/10.97


A 3-way option is similar to a traditional collar, except that PrimeWest has resold the put at a lower price. Utilizing the first 3-way natural gas contract above as an example, PrimeWest has sold a call at $11.24, purchased a put at $7.39, and resold the put at $6.33. Should the market price drop below $7.39, PrimeWest will receive $7.39 until the price is less than $6.33, at which time PrimeWest will then receive market price plus $1.06. However, should market prices rise above $11.24, PrimeWest will receive a maximum of $11.24. Should the market price remain between $7.39 and $11.24, PrimeWest will receive the market price.



Foreign Exchange

----------------------------------------------------------------------------
Amount
Period Pounds Sterling (000's) Type Price
----------------------------------------------------------------------------
Principal 63,000 $2.0748 Cdn per Pounds
Apr -Jun 2016 Interest 34,474 Swap Sterling 1.00
----------------------------------------------------------------------------


Royalties

PrimeWest pays Crown, freehold and overriding royalties to the owners of mineral rights with whom PrimeWest holds leases. These royalties vary for each property and product. The Crown royalty system is based on a sliding scale structure that increases the royalty rates as commodity prices rise. Because of the sliding scale Crown royalty system, future changes to commodity prices will result in changes to royalty rates and expenses. In certain situations, the Crown grants royalty "holidays" which eliminate royalties on specific wells.



Three Months Ended
----------------------------------------------------------------------------
$ Millions, except per BOE Mar 31, 2007 Dec 31, 2006 Mar 31, 2006
----------------------------------------------------------------------------
Royalty expense $ 40.0 $ 33.7 $ 44.7
Per BOE $ 10.65 $ 8.86 $ 13.04
Royalties as a % of sales revenues 21.3% 19.7% 23.5%
----------------------------------------------------------------------------

Operating Expenses

Three Months Ended
----------------------------------------------------------------------------
$ Millions, except per BOE Mar 31, 2007 Dec 31, 2006 Mar 31, 2006
----------------------------------------------------------------------------
Operating expense $ 38.9 $ 39.6 $ 32.7
Per BOE $ 10.36 $ 10.40 $ 9.54
----------------------------------------------------------------------------


First quarter 2007 operating expense totalled $38.9 million, a decrease of 2% from $39.6 million in the fourth quarter 2006. On a per BOE basis operating expenses decreased slightly from the previous quarter.

Year over year operating expense and operating expense per BOE increased in the first quarter of 2007 compared to the same period in 2006 due to the impact of the U.S. assets on operating costs, which are higher than the Canadian assets' operating costs, and to the impact of inflationary pressures on the prices of goods and services.



Operating Expense Outlook

PrimeWest anticipates that its full year operating expense will be
approximately $10.00 per BOE.

Operating Margin

Three Months Ended
----------------------------------------------------------------------------
$ per BOE Mar 31, 2007 Dec 31, 2006 Mar 31, 2006
----------------------------------------------------------------------------
Sales price and other revenue (1) $ 50.49 $ 45.17 $ 55.95
Royalties $ (10.65) $ (8.86) $ (13.04)
Operating expense $ (10.36) $ (10.40) $ (9.54)
----------------------------------------------------------------------------
Operating margin before realized
derivative gains/(losses) $ 29.48 $ 25.91 $ 33.37
Realized derivative gain/loss $ 1.60 $ 3.34 $ (0.27)
----------------------------------------------------------------------------
Operating margin after realized
derivative gains/(losses) $ 31.08 $ 29.25 $ 33.10
----------------------------------------------------------------------------

(1) Includes sulphur.


Operating margin is an important measure of our business because it gives an indication of the amount of cash flow PrimeWest realizes per BOE that is produced, before head office expenses and financing charges.

The operating margin per BOE increased in the first quarter of 2007 compared to the previous quarter mainly due to an increase in realized commodity prices partially offset by higher royalties.

First quarter 2007 operating margin was lower than the same period in 2006 due to lower natural gas prices and increases in operating costs partially offset by lower royalties.



General & Administrative Expense

Three Months Ended
----------------------------------------------------------------------------
$ Millions, except per BOE Mar 31, 2007 Dec 31, 2006 Mar 31, 2006
----------------------------------------------------------------------------
G&A expense $ 9.3 $ 8.6 $ 6.7
Per BOE $ 2.47 $ 2.27 $ 1.97
----------------------------------------------------------------------------


G&A expense in the first quarter of 2007 increased by 8% compared to the previous quarter mainly due to the increase in the amount of the semi-annual Unit Appreciation Rights (UARs) grant under the LTIP.

First quarter 2007 G&A expense was 39% higher when compared to the first quarter of 2006 due to increases in labour costs, audit fees, costs associated with the Denver office, and reductions in overhead recoveries. G&A expense per BOE for the three months ended March 31, 2007, was 25% higher than the same period in the prior year due to higher G&A expense offset partially by increases to production volumes.

Included in G&A expense for the three ended March 31, 2007, was $1.7 million relating to the (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 G&A expense is $0.3 million for the three months ended March 31, 2007, related to the Special Employee Retention Plan (SERP). See note 15 to the Consolidated Financial Statements in the 2006 Annual Report.



Interest Expense

Three Months Ended
----------------------------------------------------------------------------
$ Millions, except per
Trust Unit Amounts and Cost
of Debt Mar 31, 2007 Dec 31, 2006 Mar 31, 2006
----------------------------------------------------------------------------
Interest expense $ 12.2 $ 13.0 $ 4.6
Period end net debt level (1) $ 716.3 $ 820.8 $ 364.5
Debt per Trust Unit $ 7.81 $ 9.74 $ 4.42
Average cost of debt% 5.8% 5.9% 5.0%
----------------------------------------------------------------------------

(1) Excludes derivative and future income tax assets and liabilities
included in current assets and liabilities.


Interest expense, representing interest on bank debt, the U.S. Secured Notes, the U.K. Secured Notes and the Debentures decreased in the first quarter of 2007 compared to the fourth quarter of 2006 due to the decrease in the average net debt balance as proceeds from the January equity offering were used to repay a portion of the outstanding credit facility.

Interest expense was higher for the three months ended March 31, 2007, compared to the same period in 2006 due to higher average debt balances resulting from additional borrowing against the credit facility to finance the U.S. asset acquisition in the third quarter of 2006.

The average cost of debt was higher for the three months ended March 31, 2007,compared to the same period in 2006, primarily due to an increase in banker's acceptance rates which are the basis for calculating interest on the Canadian portion of the credit facility. The drawdown under the U.S. portion of the credit facility, to acquire the U.S. assets in 2006, which bears interest at the London Inter Bank Offer Rate (LIBOR), which is higher than the Canadian rate, also increased the average cost of debt.

Foreign Exchange

The foreign exchange gain of $2.1 million for the three months ended March 31, 2007, resulted from the translation of the U.S. dollar denominated Secured Notes, the U.K. Secured Notes and related interest payable into Canadian dollars.



Depletion, Depreciation and Amortization

Three Months Ended
----------------------------------------------------------------------------
$ Millions, except per BOE Mar 31, 2007 Dec 31, 2006 Mar 31, 2006
----------------------------------------------------------------------------
Depletion, depreciation and
amortization $ 66.9 $ 68.5 $ 53.9
Per BOE $ 17.82 $ 17.98 $ 15.75
----------------------------------------------------------------------------


The DD&A rate for the three months ended March 31, 2007, increased by 13% when compared to the same period in the prior year due to an increase in future development costs which are included in the calculation of DD&A. The increase in future development costs reflects the high level of activity throughout the industry which has resulted in increased capital costs. The DD&A rate will fluctuate from one period to the next depending on the amount and type of capital spending and the amount of reserves added. Expenditures on maintenance capital, land and seismic do not contribute to reserve additions and may cause DD&A rates per BOE to increase disproportionately.

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 clean up. The fund is used to pay for such costs as they are incurred. The 2007 contribution rate remains unchanged from 2006 at $0.50 per BOE resulting in $1.7 million being contributed to the fund in the first quarter. Additional contributions will be made to the fund in 2007 to accommodate the recent increase in expenditures.

As at March 31, 2007, the site reclamation fund contained a balance of $0.5 million.

The abandonment and reclamation costs incurred in the first quarter 2007 were $3.8 million, compared to $1.9 million for the same period in 2006, and $5.3 million for the previous quarter.



Income and Capital Taxes

Three Months Ended
----------------------------------------------------------------------------
$ Millions, except per BOE Mar 31, 2007 Dec 31, 2006 Mar 31, 2006
----------------------------------------------------------------------------
Income and capital taxes $ 0.2 $ 1.6 $ 0.6
Future income tax recovery $ (16.3) $ (4.5) $ (0.7)
----------------------------------------------------------------------------
Total $ (16.1) $ (2.9) $ (0.1)
----------------------------------------------------------------------------


The future income tax recovery for the three months ended March 31, 2007, increased to $16.3 million from $4.5 million in the previous quarter and $0.7 in the first quarter of 2006 due to a reduction in net income before taxes.



Net Income

Three Months Ended
----------------------------------------------------------------------------
$ Millions Mar 31, 2007 Dec 31, 2006 Mar 31, 2006
----------------------------------------------------------------------------
Net income $ 5.5 $ 9.6 $ 68.9
----------------------------------------------------------------------------


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 DD&A, the unrealized gain or loss on derivatives and future income taxes.

Net income for the three months ended March 31, 2007, of $5.5 million was 43% lower than the previous quarter's net income of $9.6 million primarily due to increases in the change in unrealized loss on derivatives of $37.0 million, debt issue costs of $8.0 million relating to the debentures issued in January and a lower realized gain on derivatives of $6.7 million. These losses were partially offset by increases to the foreign exchange gain of $20.6 million and future income tax recoveries of $11.8 million.

Net income for the first quarter of 2007 was $5.5 million compared to $68.9 million in the same period of 2006 primarily due to the change in unrealized loss on derivatives of $53.7 million, increases to interest expense of $7.6 million, debt issue costs of $8.0 million and DD&A of $13.0 million partially offset by increases to future income tax recoveries of $15.6 million.



Liquidity & Capital Resources

Long-Term Debt

As at
----------------------------------------------------------------------------
$ Millions Mar 31, 2007 Dec 31, 2006 Mar 31, 2006
----------------------------------------------------------------------------
Long-term debt $ 716.3 $ 619.4 $ 321.6
Deficit (1) $ - $ 201.4 $ 42.9
----------------------------------------------------------------------------
Net debt $ 716.3 $ 820.8 $ 364.5
Market value of Trust Units and
Exchangeable Shares outstanding
(2)(3) $ 2,070.8 $ 1,805.9 $ 2,681.7
----------------------------------------------------------------------------
Total capitalization $ 2,787.1 $ 2,626.7 $ 3,046.2
----------------------------------------------------------------------------
Net debt as a % of total
capitalization 26% 31% 12%
----------------------------------------------------------------------------

(1) Excludes derivative and future income tax assets and liabilities
included in current assets or liabilities.

(2) Based on March 31, 2007, Trust Unit closing price of $22.72 and
March 15, 2007, exchange ratio of 0.65910:1.

(3) Excludes the Debentures.


Long-term debt is comprised of senior bank credit facilities, the U.S. Secured Notes, the U.K. Secured Notes and the Debentures of $233.3 million, $144.3 million, $143.0 million and $231.8 million respectively. $36.1 million relating to the U.S. Secured Notes was included in working capital as a current portion of long-term debt. In addition to amounts outstanding under the bank credit facility, PrimeWest has outstanding letters of credit in the amount of $2.9 million (2006 - $6.8 million).

The indebtedness under the senior credit facilities, the U.S. Secured Notes and the U.K. Secured Notes is supported by a borrowing base of $750 million and is comprised of Canadian revolving facilities having a borrowing limit of $220.5 million, the U.S. bank revolving credit facilities having a borrowing limit of Cdn $255.0 million, the U.S. Secured Notes valued at $143.8 million based on a U.S. dollar exchange rate of U.S. $0.87 and the U.K. Secured Notes valued at Cdn $130.7 million.

On January 11, 2007, PrimeWest issued $200 million of Series III Convertible Unsecured Debentures for net proceeds of $192.0 million. The Debentures bear interest at 6.5 % payable semi-annually at January 31 and July 31 commencing July 31, 2007. The Debentures are convertible at any time at the option of the debenture holder into PrimeWest Trust units at a conversion price of $26.25 per Trust unit prior to maturity on January 31, 2012. The Debentures may be redeemed in whole or in part at the option of the Trust at a price of $1,050 per Debenture after February 1, 2010, and on or before January 31, 2011, and at a price of $1,025 per Debenture after February 1, 2011, and on or before January 31, 2012. On redemption or maturity the Trust may opt to satisfy its obligations to repay the principal by issuing PrimeWest Trust Units.

At March 31, 2007, PrimeWest's net debt to annualized first quarter cash flow was approximately 1.9 times compared to 2.4 times annualized fourth quarter 2006 cash flow at December 31, 2006. Net debt as a percentage of total capitalization was 26% at March 31, 2007, compared to 31% at December 31, 2006.

Unitholders' Equity

At March 31, 2007, the Trust had 90,378,337 Trust Units outstanding. In addition, PrimeWest had 1,161,568 Exchangeable Shares outstanding that are exchangeable into a total of 765,589 Trust Units using the March 15, 2007, exchange ratio of 0.65910:1.

On January 11, 2007, PrimeWest issued 6,420,000 Trust Units for net proceeds of $142.4 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. During the first quarter of 2007, PrimeWest issued 206,971 Trust Units under the DRIP for $4.3 million, 305,278 Trust Units for $6.4 million pursuant to the PREP and 173,868 Trust Units for $3.6 million pursuant to the OTUPP.

These plan components benefit Unitholders by offering alternatives to maximize their investment in PrimeWest, while providing the Trust with a relatively inexpensive method of raising additional capital. 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 the DRIP, OTUPP and PREP plans, contact the Plan Agent, 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 certain acquisitions and as part of PrimeWest's management internalization transaction. Exchangeable shares continue to be issued to certain Executive Officers pursuant to a Special Employee Retention Plan (SERP) instituted as part of the management internalization transaction.

The Exchangeable Shares do not receive cash distributions. In lieu of receiving 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 that month.

At March 31, 2007, there were 1,161,568 Exchangeable Shares outstanding. The exchange ratio on these shares was 0.65910:1 Trust Units for each Exchangeable Share as at March 31, 2007. For purposes of calculating basic per Trust Unit amounts, it is assumed that the Exchangeable Shares have been exchanged into Trust Units at the current exchange ratio.

Cash Distributions

Cash distributions to Unitholders are at the discretion of the Board of Directors and can fluctuate depending on the cash flow generated from operations and other factors. The cash flow available for distribution is dependent upon many factors including commodity prices, production levels, debt levels, capital spending requirements, and factors in the overall industry environment.

The Board of Directors targets a long-term distribution payout ratio that is a percentage of cash flow from operations. However, the actual distribution payout ratio may vary from such targets due to fluctuations in commodity prices and their impact on cash flow forecasts, as well as other factors. The current distribution payout ratio is targeted to be approximately 70-90% of annual funds flow from operations. The October 31, 2006, proposals by the federal government to change the way royalty trusts and income funds are taxed has created additional uncertainty with respect to the payout ratio. At this time, PrimeWest is unable to predict what payout rate it will maintain in the future. In the first quarter of 2007, cash distributions totalled $67.6 million, or $0.75 per Trust Unit representing a payout ratio of approximately 72% of funds flow from operations, compared to $62.3 million, or $0.75 per Trust Unit (74% payout ratio) in the previous quarter and $86.7 million or $1.08 per Trust unit (84% payout ratio) in the first quarter of 2006.

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

Contractual Obligations

PrimeWest enters into many contractual obligations as part of conducting day-to-day business. Material contractual obligations include debt obligations, lease rental commitments that run from 2007 through 2024 and various pipeline transportation commitments that run through 2013. The details of the timing of these contractual obligations are included in the following table.



As at March 31, 2007 Payments due by period
----------------------------------------------------------------------------
Less than More than
$ Millions Total 1 year 1-3 years 4-5 years 5 years
----------------------------------------------------------------------------
Long-term debt obligations 520.6 36.1 305.4 36.1 143.0
Debentures 238.4 - 23.7 14.7 200.0
Interest (1) 94.3 15.8 26.3 17.6 34.6
Lease rental obligations 83.5 3.8 5.1 9.6 65.0
Pipeline transportation
obligations 4.8 3.7 0.8 0.3 -
----------------------------------------------------------------------------
Total contractual
obligations 941.6 59.4 361.3 78.3 442.6
----------------------------------------------------------------------------

(1) Includes interest on the U.S. Secured Notes, U.K. Secured Notes and the
Debentures assuming foreign exchange rates in effect as at March 31,
2007.


As part of PrimeWest's 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, 2005 and 2006, 94,340 Exchangeable Shares were issued to those officers. An additional 94,340 Exchangeable Shares will be issued on November 6, 2007. For the three months ended March 31, 2007, $0.3 million has been recorded in G&A expenses related to the SERP.

In October 2006, PrimeWest entered into an agreement containing a new office lease rental commitment that runs from 2010 to 2024. Payments that will become due under this agreement will commence in mid-2010 at approximately $4.7 million per year and will escalate by approximately $0.2 million every three years until 2021, at which point they will increase by $0.1 million per year for the final three years of the term of the commitment. The agreement contains customary additional obligations regarding the responsibility of PrimeWest for tenant improvements.

Future Accounting Changes

The CICA has issued the following accounting standards which will be effective January 1, 2008: Section 3862 "Financial Instruments - Disclosures", Section 3863 "Financial Instruments - Presentation" and Section 1535 "Capital Disclosures."

These new accounting standards will require the Trust to provide additional disclosures relating to its financial instruments, including hedging instruments, and the Trust's capital. Section 3863 does not change the presentation guidance provided in Section 3861 "Financial Instruments - Disclosure and Presentation" which it replaces. It is not anticipated that the adoption of these new accounting standards will impact the amounts reported in the Trust's financial statements as they primarily relate to disclosure.

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 gas royalty trust sector and the conventional oil and gas producers 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 under two broad categories - "Commodity Price, Foreign Exchange and Interest Rate Risk" and "Operational and Other Business Risks." For additional information on Business Risks, including Risks Related to the Trust Structure and the Ownership of Trust Units, see PrimeWest's most recently filed Annual Information Form.

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 the Trust's control. Some of these factors include:

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

- World and North American economic conditions which influence the demand for both 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. dollar exchange rate that 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 among 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 actively monitored by the Board.

Beyond our hedging strategy, PrimeWest also mitigates risk by having a well-diversified marketing portfolio and by transacting with a number of counterparties and limiting exposure to each counterparty. For the first quarter of 2007 approximately 17% of natural gas production was sold to aggregators and 83% of production was sold into the Alberta and British Columbia 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 objective of our commodity risk management program is to reduce the volatility of our cash distributions, to lock in the economics on major acquisitions and to protect our capital structure when commodity prices cycle downwards. In the first quarter 2007, PrimeWest realized a $6.0 million gain from commodity hedges.

Taxation of the Trust

On October 31, 2006, the Minister of Finance (Canada) ("Finance") announced proposed changes to the taxation of certain publicly-traded trusts and partnerships and their unitholders. These changes, assuming they are enacted, would apply, in the case of trusts, to a trust that is resident in Canada for purposes of the Tax Act, holds one or more "non-portfolio properties", and the units of which are listed on a stock exchange or other public market (a "specified investment flow-through trust", or "SIFT trust"). In the case of a SIFT trust the units of which were already publicly traded on October 31, 2006, the proposed changes generally would not take effect until January 1, 2011, provided the trust experiences only "normal growth" and no "undue expansion" before then. On December 15, 2006, Finance issued guidelines with respect to what would be considered "normal growth" for this purpose, and on December 21, 2006, Finance released draft legislative proposals to implement the changes previously announced on October 31, 2006. On January 30, 2007, Finance confirmed the Government's intention to proceed with these proposals. The October 31, 2006 proposals, December 15, 2006 guidelines and December 21, 2006 draft legislation, are hereinafter collectively referred to as the "October 31 Proposals".

Until such time as the October 31 Proposals apply to the Trust, which is not expected to be until January 1, 2011, it is expected that:

- The Trust will continue not to be liable for any material amount of Canadian income tax;

- Returns on capital will generally be taxed as ordinary income or as dividends in the hands of a Unitholder who is resident in Canada for purposes of the Tax Act, and will be subject to withholding tax at a rate of 25% (subject to a reduction in such rate under the terms of an applicable tax treaty or convention) when paid to a non-resident Unitholder;

- Returns of capital paid to a Unitholder who is resident in Canada for purposes of the Tax Act generally will not be included in the Unitholder's income but will reduce the adjusted cost base of the Unitholder's Trust Units; and

- Returns of capital paid to a non-resident Unitholder will be subject to the special 15% Canadian withholding tax under Part XIII.2 of the Tax Act.

Pursuant to the October 31 Proposals, commencing January 1, 2011, the Trust will be subject to tax on its income from non-portfolio properties and taxable capital gains from dispositions of non-portfolio properties, that is paid or payable to Unitholders, at a rate of 31.5% (comparable to the projected combined federal and provincial corporate income tax rate in 2011), and distributions of such income to Unitholders will be treated as dividends paid by a taxable Canadian corporation. The Royalty and the shares and notes of PrimeWest will constitute "non-portfolio properties" of the Trust under the October 31 Proposals, with the result that virtually all of the Trust's income, including any taxable capital gains, would be subject to the 31.5% tax, and distributions of such income by the Trust to its Unitholders would be treated as dividends paid by a taxable Canadian corporation. Returns of capital by the Trust to its Unitholders would not be affected by the October 31 Proposals and would continue to be taxed in the same manner as under the current rules.

As noted above, the Trust could become subject to these changes before 2011 if it experiences growth, other than "normal growth", before that time. Under the December 15, 2006 guidelines, the Trust will be considered to have experienced only "normal growth" if its issuances of new equity (which for this purpose includes Trust Units and debt that is convertible into Trust Units, but does not include non-convertible debt) do not exceed, for each of the intervening periods set forth below, a safe harbour measured by reference to the Trust's market capitalization as of the end of trading on October 31, 2006 (measured solely by the value of the Trust's issued and outstanding publicly-traded Trust Units as of that date). The Trust's market capitalization as of October 31, 2006, was approximately $2.379 billion. The intervening periods and their respective safe harbour amounts are as follows:

- November 1, 2006 to December 31, 2007 - 40% of the Trust's market capitalization as of October 31, 2006;

- January 1, 2008 to December 31, 2008 - 20% of the Trust's market capitalization as of October 31, 2006;

- January 1, 2009 to December 31, 2009 - 20% of the Trust's market capitalization as of October 31, 2006;

- January 1, 2010 to December 31, 2010 - 20% of the Trust's market capitalization as of October 31, 2006.

The December 15, 2006 guidelines provide that these annual safe harbour amounts are cumulative, and that replacing debt that was outstanding as of October 31, 2006 with new equity, whether through a debenture conversion or otherwise, will not be considered growth for these purposes. In addition, an issuance of new equity will not be considered growth to the extent that the issuance is made in satisfaction of the exercise by another person of a right in place on October 31, 2006 to exchange an interest in a partnership, or a share of a corporation, for Trust Units.

Operational And Other Business Risks

PrimeWest is also exposed to a number of risks related to its activities within the oil and gas industry that 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 Performing regular and proactive
of oil and gas - includes well protective well, facility and
operations, processing and the pipeline maintenance supported by
physical delivery of commodities to telemetry, physical inspection and
market. diagnostic tools.

----------------------------------------------------------------------------

Commodity Price

Fluctuations in natural gas, crude Hedging. See page 9 of this
oil and natural gas liquids prices. quarterly report.

----------------------------------------------------------------------------

Transportation

Market risk related to the Diversifying the transportation
availability of transportation to systems on which we rely to get our
market and potential disruption in product to market.
delivery systems.

----------------------------------------------------------------------------

Natural Decline

Development risk associated with Diversifying our capital spending
capital enhancement activities program over a large number of
undertaken - the risk that capital projects so that large amounts of
spending on activities such as capital are not risked on any one
drilling, well completions, well activity. We also have a highly
workovers and other capital skilled technical team of geologists,
activities will not result in geophysicists and engineers working
reserve additions or in quantities to apply the latest technology in
sufficient to replace annual planning and executing capital
production declines. programs. Capital is spent only after
strict economic criteria for
production and reserve additions are
assessed.

----------------------------------------------------------------------------

Acquisitions

Acquisition risk associated with Continually scanning the marketplace
acquiring producing properties at for opportunities to acquire assets.
low cost to renew our inventory of Our technical acquisition specialists
assets. 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 period.

----------------------------------------------------------------------------

Reserves

Reserve risk in respect of the Contracting our reserves evaluation
quantity and quality of recoverable to a reputable third party
reserves. consultant, GLJ Petroleum Consultants
Ltd (GLJ). The Operations and
Reserves Committee of the Board of
Directors and PrimeWest review the
work and independence of GLJ. Our
strategy is to invest in mature,
longer life properties having a
higher proved producing component
where the reserve risk is generally
lower and cash flows are more stable
and predictable.

----------------------------------------------------------------------------

Environmental Health and Safety
(EH&S)

Environmental, health and safety Establishing and adhering to strict
risks associated with oil and gas guidelines for EH&S including
properties and facilities. training, proper reporting of
incidents, supervision and awareness.
PrimeWest has active community
involvement in field locations
including regular meetings with
stakeholders in the area. PrimeWest
carries adequate insurance to cover
property losses, liability and
business interruption.

These risks are reviewed regularly by
the Operations and Reserves
Committee of the Board.

----------------------------------------------------------------------------

Regulation, Tax and Royalties

Changes in government regulations Keeping informed of proposed changes
including reporting requirements, in regulations and laws to properly
income tax laws, operating practices, respond to and plan for the effects
environmental protection requirements that these changes may have on our
and royalty rates. operations.

----------------------------------------------------------------------------

Historical Liability to Unitholders
is Uncertain

Because of uncertainties in the law On July 1, 2004, a new statute
prior to July 1, 2004, relating to entitled the Income Trusts Liability
investments in trusts, there is a Act (Alberta) was proclaimed in
risk that a Unitholder could be held force, creating a statutory
personally liable for obligations of limitation on the liability of
the Trust. Unitholders of Alberta income
trusts such as PrimeWest. The
legislation provides that a
Unitholder is not, as beneficiary,
liable for any act, default,
obligation or liability of the Trust
that arises after July 1, 2004.
Similar legislation was proclaimed in
force in Ontario in December of 2004.


CONSOLIDATED BALANCE SHEETS
----------------------------------------------------------------------------
($ millions) Mar 31, 2007 Dec 31, 2006
----------------------------------------------------------------------------
ASSETS (unaudited)

Current Assets
Cash and cash equivalents $ 78.1 $ 22.0
Accounts receivable 99.8 104.5
Derivative assets (note 6) 0.8 23.5
Future income taxes 2.6 2.3
Prepaid expenses 17.7 19.6
Inventory 0.6 0.3
----------------------------------------------------------------------------
199.6 172.2
Cash reserved for site restoration and
reclamation 0.5 2.2
Other assets and deferred charges (note 2) 0.2 7.4
Derivative assets (note 6) 0.9 5.3
Property, plant and equipment 2,350.1 2,332.9
Goodwill 68.5 68.5
----------------------------------------------------------------------------
$ 2,619.8 $ 2,588.5
----------------------------------------------------------------------------
LIABILITIES AND UNITHOLDERS' EQUITY
Current Liabilities
Accounts payable and accrued liabilities $ 141.2 $ 143.3
Current portion of long-term debt (note 4) 36.1 186.4
Future income taxes - 8.7
Derivative liabilities (note 6) 4.4 -
Accrued distributions to Unitholders 18.9 18.1
----------------------------------------------------------------------------
200.6 356.5
Long-term debt (note 4) 716.3 619.4
Future income taxes 146.9 153.9
Asset retirement obligation (note 3) 92.6 91.5
----------------------------------------------------------------------------
1,156.4 1,221.3
UNITHOLDERS' EQUITY
Net capital contributions (note 5) 2,548.1 2,391.2
Capital issued but not distributed 3.6 2.7
Convertible Unsecured Subordinated Debentures 8.8 1.2
Contributed surplus (note 7) 13.5 11.9
Accumulated other comprehensive income 4.8 6.2
Deficit (note 8) (1,115.4) (1,046.0)
----------------------------------------------------------------------------
1,463.4 1,367.2
----------------------------------------------------------------------------
$ 2,619.8 $ 2,588.5
----------------------------------------------------------------------------
See notes to interim consolidated financial statements.


CONSOLIDATED STATEMENTS OF CASH FLOW
----------------------------------------------------------------------------
Three months ended ($ millions) Mar 31, 2007 Mar 31, 2006
----------------------------------------------------------------------------
OPERATING ACTIVITIES (unaudited) (unaudited)
Net income for the period $ 5.5 $ 68.9
Add/(deduct) items not involving cash from
operations:
Depletion, depreciation and amortization 66.9 53.9
Non-cash general and administrative 2.0 1.4
Non-cash foreign exchange (gain)/loss (2.1) 0.6
Unrealized loss/(gain) on derivatives 31.5 (22.2)
Future income tax recovery (16.3) (0.7)
Accretion of asset retirement obligation 1.6 0.7
Other non-cash items 0.5 0.6
Debt issue costs 8.0 -
Expenditures on site restoration and reclamation (3.8) (1.9)
----------------------------------------------------------------------------
Funds flow from operations 93.8 101.3
Change in non-cash working capital (3.3) 23.2
----------------------------------------------------------------------------
90.5 124.5
----------------------------------------------------------------------------
FINANCING ACTIVITIES
Proceeds from issue of Trust Units (net of costs) 146.0 5.7
Proceeds from issue of Debentures (net of costs) 192.0 -
Net cash distributions to Unitholders (55.8) (74.4)
Decrease in bank credit facilities (242.0) (26.0)
Change in non-cash working capital 7.1 (2.3)
----------------------------------------------------------------------------
47.3 (97.0)
----------------------------------------------------------------------------
INVESTING ACTIVITIES
Expenditures on property, plant and equipment (72.6) (82.6)
Acquisition of capital assets (11.5) (0.2)
Proceeds on disposal of property, plant and
equipment - 3.1
Decrease in cash reserved for future site
reclamation 1.7 0.1
Change in non-cash working capital 0.7 18.5
----------------------------------------------------------------------------
(81.7) (61.1)
----------------------------------------------------------------------------
Increase/(decrease) in cash and cash equivalents
for the period 56.1 (33.6)
Cash and cash equivalents, beginning of period 22.0 36.8
----------------------------------------------------------------------------
Cash and cash equivalents, end of period $ 78.1 $ 3.2
----------------------------------------------------------------------------

----------------------------------------------------------------------------
Cash interest paid $ 4.8 $ 2.7
----------------------------------------------------------------------------
Cash taxes paid $ 0.4 $ 0.7
----------------------------------------------------------------------------
Non-cash transactions - conversion of debentures
into Trust Units $ 0.1 $ 7.6
----------------------------------------------------------------------------
See notes to interim consolidated financial statements.


CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
----------------------------------------------------------------------------
Three months ended ($ millions, except per Trust
Unit amounts) Mar 31, 2007 Mar 31, 2006
----------------------------------------------------------------------------
REVENUES (unaudited) (unaudited)
Sales of crude oil, natural gas and natural gas
liquids $ 189.7 $ 192.0
Crown and other royalties (40.0) (44.7)
Realized gain/(loss) on derivatives 6.0 (0.9)
Change in unrealized (loss)/gain on derivatives (31.5) 22.2
Other income 1.8 1.4
----------------------------------------------------------------------------
126.0 170.0
----------------------------------------------------------------------------
EXPENSES
Operating 38.9 32.7
Transportation 1.8 1.9
General and administrative 9.3 6.7
Interest 12.2 4.6
Debt issue 8.0 -
Depletion, depreciation and amortization 66.9 53.9
Accretion of asset retirement obligation
(note 3) 1.6 0.7
Foreign exchange (gain)/loss (2.1) 0.7
----------------------------------------------------------------------------
136.6 101.2
----------------------------------------------------------------------------
Income before taxes for the period (10.6) 68.8
----------------------------------------------------------------------------
Income and capital taxes 0.2 0.6
Future income taxes recovery (16.3) (0.7)
----------------------------------------------------------------------------
(16.1) (0.1)
----------------------------------------------------------------------------
Net income for the period $ 5.5 $ 68.9
Other comprehensive income
Unrealized foreign exchange loss on translation
of self sustaining foreign operations (1.0) -
Tax effect on unrealized foreign exchange loss
on translation of self sustaining foreign
operations (0.4) -
----------------------------------------------------------------------------
Other comprehensive income $ (1.4) $ -
----------------------------------------------------------------------------
Comprehensive income $ 4.1 $ 68.9
----------------------------------------------------------------------------
Net income per Trust Unit - basic (note 5) $ 0.06 $ 0.85
Net income per Trust Unit - diluted (note 5) $ 0.06 $ 0.83
----------------------------------------------------------------------------
See notes to interim consolidated financial statements.


CONSOLIDATED STATEMENTS OF DEFICIT & ACCUMULATED COMPREHENSIVE INCOME
----------------------------------------------------------------------------
Three Months Ended ($ millions) Mar 31, 2007 Mar 31, 2006
----------------------------------------------------------------------------
(unaudited) (unaudited)
Deficit, beginning of period $ (1,046.0) $ (948.5)
Adoption of new financial instrument accounting
standard (net of income tax recovery of $0.1
million) (note2) (7.3) -
Net income 5.5 68.9
Distributions paid or declared (67.6) (86.8)
----------------------------------------------------------------------------
Deficit, end of period $ (1,115.4) $ (966.4)
----------------------------------------------------------------------------

Accumulated other comprehensive income,
beginning of period $ 6.2 $ -
Other comprehensive income, net of tax (1.4) -
----------------------------------------------------------------------------
Accumulated other comprehensive income, end of
period $ 4.8 $ -
----------------------------------------------------------------------------
Deficit and accumulated other comprehensive
income $ (1,110.6) $ (966.4)
----------------------------------------------------------------------------
See notes to interim consolidated financial statements.


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the three months ended March 31, 2007, all amounts (except per Trust Unit amounts) are expressed in millions of Canadian dollars unless otherwise indicated.

1. Significant Accounting Policies

These interim consolidated financial statements of PrimeWest have been prepared in accordance with Canadian generally accepted accounting principles. The specific accounting principles used are described in the annual consolidated financial statements of the Trust appearing on pages 65 and 66 of the Trust's 2006 Annual Report, with the exception of policies disclosed in note 2, and should be read in conjunction with these interim financial statements.

2. Changes in Accounting Policies

Financial Instruments, Hedging Activities and Comprehensive Income

Effective January 1, 2007, the Trust adopted CICA Handbook section 3855, "Financial Instruments - Recognition and Measurement," and CICA Handbook section 3861, "Financial Instruments - Disclosure and Presentation." The Trust has adopted these sections prospectively and the comparative interim consolidated financial statements have not been restated for these accounting policy changes. Adoption of section 3855 allows for the cumulative effect of the change in accounting policy to be booked as an adjustment to accumulated deficit with no restatement of prior periods. At January 1, 2007, $7.2 million in financing charges net of income tax recovery of $0.1 million were written off to the deficit. At January 1, 2007, other assets and deferred charges on the balance sheet was reduced to $0.2 million.

Effective January 1, 2007, the Trust adopted CICA Handbook section 1530, "Comprehensive Income." The Trust has adopted this section retroactively and prior periods have been restated. At January 1, 2007, the change in accounting policy resulted in an increase to accumulated other comprehensive income of $6.2 million net of tax (2006 - $0 million) and a decrease and elimination of the cumulative translation account of $6.2 million (2006 - $0 million).

Financial Instruments

All financial instruments must initially be recognized at fair value on the balance sheet. The Trust has classified each financial instrument into the following categories: held for trading financial assets and financial liabilities, loans or receivables, held to maturity investments, available for sale financial assets, and other financial liabilities. Subsequent measurement of the financial instruments is based on their classification. Unrealized gains and losses on held for trading financial instruments are recognized in earnings. Gains and losses, other than impairment losses, on available for sale financial assets are recognized in other comprehensive income and are transferred to earnings when the asset is de-recognized. The other categories of financial instruments are recognized at amortized cost using the effective interest rate method. Impairment losses are recorded in earnings when incurred.

Upon adoption and with any new financial instrument, an irrevocable election is available that allows entities to classify any financial asset or financial liability as held for trading, even if the financial instrument does not meet the criteria to designate it as held for trading. The Trust has not elected to classify any financial assets or financial liabilities as held for trading unless they meet the held for trading criteria. A held for trading financial instrument is not a loan or receivable and includes one of the following criteria:

- is a derivative, except for those derivatives that have been designated as effective hedging instruments;

- has been acquired or incurred principally for the purpose of selling or repurchasing in the near future; or

- is part of a portfolio of financial instruments that are managed together and for which there is evidence of a recent actual pattern of short-term profit taking.

For financial assets and financial liabilities that are not classified as held for trading, the transaction costs that are directly attributable to the acquisition or issue of a financial asset or financial liability are added to the fair value initially recognized for that financial instrument or expensed to earnings as incurred.

Derivative Instruments and Hedging Activities

Derivative instruments are utilized by the Trust to manage market risk against the volatility in commodity prices, foreign exchange rates and interest rate exposures. The Trust's policy is not to utilize derivative instruments for speculative purposes. The Trust may choose to designate derivative instruments as hedges. To date, the Trust has not elected to apply hedge accounting.

All derivative instruments are recorded on the balance sheet at fair value in either accounts receivable, other assets, accounts payable and accrued liabilities, or other long-term liabilities. Freestanding derivative instruments are classified as held for trading financial instruments. Gains and losses on these instruments are recorded in the change in unrealized gains and losses on derivatives in the consolidated statement of income and comprehensive income in the period they occur.

The Trust enters into commodity price contracts to hedge anticipated sales of crude oil and natural gas production to manage its exposure to price fluctuations. Gains and losses from these contracts are recognized in realized gains and losses on derivatives when the contracts are settled.

The Trust enters into cross currency swap agreements to hedge its fixed interest rate and foreign currency exposures on foreign currency denominated long-term debt. Gains and losses from these contracts are recognized in realized gains and losses on derivatives as the related interest payments are made.

Fair values of the derivatives are based on quoted market prices where available. The fair values of swaps and forwards are based on forward market prices. If a forward price is not available for a commodity based forward, a forward price is estimated using an existing forward price adjusted for quality or location.

Embedded Derivatives

Derivatives embedded in a host contract are classified as embedded derivatives. These derivatives are required to be recorded separately from the host contract when their economic characteristics and risks are not clearly and closely related to those of the host contract, the terms of the embedded derivatives are the same as those of a freestanding derivative and the combined contract is not classified as held for trading or designated at fair value. The Trust has selected January 1, 2004, as its transition date for accounting for any potential embedded derivatives.

Comprehensive Income

Comprehensive income consists of net income and other comprehensive income ("OCI"). OCI comprises the change in the unrealized foreign exchange gain / loss on translation of financial statements of self-sustaining foreign operations. Amounts included in OCI are shown net of tax. Accumulated other comprehensive income is a new equity category comprised of the cumulative amounts of OCI.

Foreign Currency Translation

The Trust has U.S. dollar operations, which are self-sustaining. The self-sustaining operations are translated into Canadian dollars using the current rate method. Under this method, assets and liabilities are translated using period end exchange rates with revenues and expenses translated using average rates for the period. Effective January 1, 2007, gains and losses arising on the translation of assets and liabilities are included in the comprehensive income account under Unitholder's equity.

Accounting Changes

Effective January 1, 2007, the Trust adopted the revised recommendations of CICA section 1506, "Accounting Changes."

The new recommendations permit voluntary changes in accounting policy only if they result in financial statements which provide more reliable and relevant information. Accounting policy changes are applied retrospectively unless it is impractical to determine the period or cumulative impact of the change. Corrections of prior period errors are applied retrospectively and changes in accounting estimates are applied prospectively by including these changes in earnings. The guidance was effective for all changes in accounting polices, changes in accounting estimates and corrections of prior period errors initiated in periods beginning on or after January 1, 2007.

Future Accounting Changes

The CICA has issued the following accounting standards which will be effective January 1, 2008: Section 3862 "Financial Instruments - Disclosures", Section 3863 "Financial Instruments - Presentation" and Section 1535 "Capital Disclosures."

These new accounting standards will require the Trust to provide additional disclosures relating to its financial instruments, including hedging instruments, and the Trust's capital. Section 3863 does not change the presentation guidance provided in Section 3861 "Financial Instruments - Disclosure and Presentation" which it replaces. It is not anticipated that the adoption of these new accounting standards will impact the amounts reported in the Trust's financial statements as they primarily relate to disclosure.

3. Asset Retirement Obligations

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



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

----------------------------------------------------------------------------
Asset Retirement Obligation $ Millions
----------------------------------------------------------------------------
Asset Retirement Obligation, December 31, 2006 $ 91.5
Liabilities incurred 3.3
Liabilities settled (3.8)
Accretion expense 1.6
----------------------------------------------------------------------------
Asset Retirement Obligation, March 31, 2007 $ 92.6
----------------------------------------------------------------------------
----------------------------------------------------------------------------


As at March 31, 2007, the undiscounted amount of estimated cash flows required to settle the obligation is $493.9 million. The estimated cash flow has been discounted using a credit-adjusted risk free rates ranging from 6.5% to 7.0% and an inflation rate of 2.0%. Although the expected period until settlement ranges from a minimum of 1 year to a maximum of 50 years, the expectation is that costs will be paid over an average of 34 years. These future asset retirement costs will be funded from the cash reserved for site restoration and reclamation.



4. Long-Term Debt

----------------------------------------------------------------------------
Mar 31, Dec 31, Mar 31, Dec 31, Mar 31, Dec 31,
Maturity 2007 2006 2007 2006 2007 2006
----------------------------------------------------------------------------
Canadian U.S. Dollar
Dollar Amounts Denominated Pounds Sterling
($ millions) ($ millions) (millions)

Bank credit
facilities $ 233.3 $ 477.3 $ 202.0 $ 202.0 - -
7.5%
debentures 2009 24.0 24.0 - - - -
U.S. secured
notes 2010 144.3 145.7 125.0 125.0 - -
7.75%
debentures 2011 14.9 15.0 - - - -
6.5%
debentures 2012 192.9 - - - - -
U.K. secured
notes 2016 143.0 143.8 - - 63.0 63.0
----------------------------------------------------------------------------
Total debt $ 752.4 $ 805.8
Current
portion of
long-term
debt $ 36.1 $ 186.4
--------------------------------------
Total of
long-term
debt $ 716.3 $ 619.4
--------------------------------------


On January 11, 2007, PrimeWest issued $200 million of Series III Convertible Unsecured Debentures for net proceeds of $192.0 million. The debt issue costs of $8.0 million were expensed to earnings. The Debentures bear interest at 6.5% payable semi-annually at January 31 and July 31 commencing July 31, 2007. The Debentures are convertible at any time at the option of the debenture holder into PrimeWest Trust units at a conversion price of $26.25 per Trust unit prior to maturity on January 31, 2012. The Debentures may be redeemed in whole or in part at the option of the Trust at a price of $1,050 per Debenture after February 1, 2010, and on or before January 31, 2011, and at a price of $1,025 per Debenture after February 1, 2011, and on or before January 31, 2012. On redemption or maturity the Trust may opt to satisfy its obligation to repay the principal by issuing PrimeWest Trust Units.

The Series III Convertible Debentures are presented on the balance sheet in their debt and equity components. The debt component represents the discounted present value of the semi-annual interest obligations and the principal payment due at maturity, using the rate of the interest that would have been applicable to a non-convertible debt instrument of comparable term and risk at the date of issue. The debt component increases over the term of the debenture to the full fair value of the outstanding debenture at maturity. The difference is reflected as accretion expense on the income statement. The equity component is presented in Unitholders Equity on the balance sheet. The equity component represents the value ascribed to the conversion right which remains a fixed amount over the term of the debenture. Upon conversion of the debenture into Trust Units, a proportionate amount of both the debt and equity components are transferred to Unitholders' capital.

The current portion of long-term debt includes $36.1 million relating to the U.S. Secured Notes payable on May 7, 2007.

5. Unitholders' Equity

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



----------------------------------------------------------------------------
Trust Units Number of Units $ Millions
----------------------------------------------------------------------------
Balance, December 31, 2006 83,256,610 $ 2,378.9
Issued pursuant to equity offering 6,420,000 142.4
Issued pursuant to Distribution Reinvestment
Plan 206,971 4.3
Issued pursuant to the Premium Distribution
Plan 305,278 6.4
Issued pursuant to Optional Trust Unit
Purchase Plan 173,868 3.6
Issued pursuant to Long-Term Incentive Plan 13,530 0.1
Conversion of Convertible Unsecured
Subordinated Debentures 1,886 0.1
Issued on exchange of Exchangeable Shares 191 -
Issued pursuant to Consolidation/Fractional
Units 2 -
----------------------------------------------------------------------------

Balance, March 31, 2007 90,378,336 $ 2,535.8
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The weighted average number of Trust Units and Exchangeable Shares outstanding for the three months ended Mar 31, 2007, was 89,973,920 (2006 -80,865,379). For purposes of calculating diluted net income per Trust Unit for the three months ended Mar 31, 2007, 539,045 Trust Units issueable pursuant to the LTIP were added to the weighted average number. The diluted net income per Trust Unit calculation for the three months ended March 31, 2007 does not include 9,068,178 of Trust Units issueable pursuant to the conversion of the Debentures as the impact on net income per Trust Unit was anti-dilutive. For purposes of calculating diluted net income per Trust Unit for the three months ended March 31, 2006, 1,956,148 Trust Units issueable pursuant to the conversion of the Debentures and 1,226,608 Trust Units issueable pursuant to the LTIP were added to the weighted average number.

On January 11, 2007, PrimeWest issued 6,420,000 Trust Units for net proceeds of $142.4 million.

Exchangeable Shares

The Exchangeable Shares are exchangeable into Trust Units at any time up to March 29, 2010 based on an exchange ratio that adjusts each time the Trust makes a distribution to its Unitholders. The exchange ratio, which was 1:1 on the date that the Exchangeable Shares were first issued, is based on the total monthly distribution, divided by the closing unit price on the distribution payment date. The exchange ratio effective March 15, 2007, was 0.65910:1.



----------------------------------------------------------------------------
Exchangeable Shares Number of Shares $ Millions
----------------------------------------------------------------------------
Balance, December 31, 2006 1,161,864 $ 12.3
Exchanged for Trust Units (296) -
----------------------------------------------------------------------------
Balance, March 31, 2007 1,161,568 $ 12.3
----------------------------------------------------------------------------
----------------------------------------------------------------------------


6.Financial Instruments and Risk Management

The Trust's financial instruments presented on the balance sheet consist of cash, accounts receivable, accounts payable and accrued liabilities, accrued distributions to Unitholders, derivative assets, derivative liabilities and long-term debt. Other than the long-term debt, the fair market value of these financial instruments approximate their carrying value due to the short-term to maturity and the risk management contacts are presented at fair value on the balance sheet. The fair value of long-term debt is disclosed in the following table.



----------------------------------------------------------------------------
Mar 31, Mar 31, Mar 31, Dec 31, Dec 31,
2007 2007 2007 2006 2006
----------------------------------------------------------------------------
Carrying(1) Carrying(1)
Face value value Fair value Face value value
Bank credit
facilities - - - 242.0 242.0
7.5% debentures 23.7 24.0 24.1 24.0 24.0
7.75% debentures 14.7 14.9 15.2 15.0 15.0
6.5% debentures 200.0 192.9 198.1 - -
----------------------------------------------------------------------------
Total Cdn $
denominated debt 238.4 231.8 237.4 281.0 281.0
----------------------------------------------------------------------------

Bank credit
facilities 202.0 202.0 202.0 202.0 202.0
U.S. $ denominated
debt - U.S. secured
notes 125.0 125.0 120.8 125.0 125.0
----------------------------------------------------------------------------
Total U.S. $
denominated debt 327.0 327.0 322.8 327.0 327.0
----------------------------------------------------------------------------
Pounds sterling
denominated debt
- U.K. secured
notes 63.0 63.0 60.9 63.0 63.0
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) Excludes equity component.


Commodity Price Risk Management

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

Foreign Exchange Rate Risk

The Trust is exposed to fluctuations in the Canadian /U.S. dollar exchange rate on the sale of commodities that are denominated in U.S. dollars or directly influenced by U.S. dollar benchmark prices. In addition, the Trust's 4.19% U.S. Secured Notes are denominated in U.S. dollars. The semi-annual interest payments and principal payments associated with the Senior Notes can be impacted by movement in the Canadian/U.S. dollar exchange rate. PrimeWest, through the use of a financial swap, has converted the U.K. Secured Notes from pounds sterling to Canadian dollar debt. This currency swap has fixed the aggregate principal value and annual interest payments on this Pounds Sterling 63.0 million debt at $130.7 million and $3.9 million respectively.

Impact on Financial Statements

The commodity price risk financial instruments and currency swaps have been recorded at fair value in current assets, other assets and current liabilities with the offset included in the unrealized gain or loss on derivatives on the income statement.

At March 31, 2007, $0.8 million was recorded as a current derivative asset related to crude oil. $0.9 million was recorded as a long-term asset comprised of a $5.3 million unrealized loss on natural gas, a $3.7 million unrealized gain on crude oil and a $2.5 million unrealized gain attributable to foreign exchange. $4.4 million was recorded as a current derivative liability related to crude oil.

For the three months ended March 31, 2007, the total unrealized loss on the statement of income was $31.5 million comprised of a $23.4 million loss related to natural gas, a $5.9 million loss related to crude oil and a $2.2 million loss related to foreign exchange.

The financial impact on the settlement of contracts during the first quarter of 2007 recorded in realized derivative gain on the income statement was a $6.0 million gain consisting of $3.3 million gain related to natural gas and a $2.7 million gain related to crude oil.

7. Contributed Surplus

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



----------------------------------------------------------------------------
$ Millions
----------------------------------------------------------------------------
Balance, December 31, 2006 $ 11.9
General and administrative expense - unit
appreciation rights 1.7
Unit Appreciation Rights exercised (0.1)
----------------------------------------------------------------------------
Balance, March 31, 2007 $ 13.5
----------------------------------------------------------------------------
----------------------------------------------------------------------------

8. Deficit

----------------------------------------------------------------------------
($ millions) Mar 31, 2007 Mar 31,2006
----------------------------------------------------------------------------
Accumulated income $ 510.3 $ 372.7
Accumulated distributions paid or declared (1,617.7) (1,331.1)
Accumulated dividends (8.0) (8.0)
----------------------------------------------------------------------------
$ (1,115.4) $ (966.4)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


PrimeWest is obligated by virtue of its Royalty and Trust Indenture to distribute to Unitholders a significant portion of its funds flow from operations. Funds flow from operations normally exceeds net income due to non-cash expenses such as DD&A, derivatives, unrealized foreign exchange gains/(losses) and accretion. These non-cash expenses result in a deficit despite PrimeWest distributing less than all of the funds flow from operations.

9. Segmented Information

The Trust's business activities are conducted through two business segments: Canadian oil and natural gas production and U.S. oil and natural gas production. Oil and natural gas production in Canada and the U.S. includes development and production of crude oil and natural gas reserves. The following table includes financial results from the U.S. operations for the period January to March 2007. Prior to July 2006, the Trust operated in only one segment.



Three Months Ended Mar 31, 2007
----------------------------------------------------------------------------
Inter
Segment
$ Millions Canada U.S. Elimination Total
----------------------------------------------------------------------------
Revenues
Gross production revenue 176.6 13.1 - 189.7
Realized gain in financial
derivatives 4.3 1.7 - 6.0
Royalties (37.4) (2.6) - (40.0)
Other income 1.7 0.1 - 1.8
----------------------------------------------------------------------------
145.2 12.3 - 157.5

Expenses
Operating 35.4 3.5 - 38.9
Transportation 1.8 - - 1.8
General and administrative 8.6 0.7 - 9.3
----------------------------------------------------------------------------
45.8 4.2 - 50.0
----------------------------------------------------------------------------
Earnings before interest, taxes and
DD&A and other non-cash items 99.4 8.1 - 107.5

Non-cash revenue
----------------------------------------------------------------------------
Unrealized loss on derivatives (31.5) - - (31.5)
----------------------------------------------------------------------------

Other expenses
DD&A 62.0 4.9 - 66.9
Interest 8.4 3.8 - 12.2
Debt issue costs 8.0 - - 8.0
Foreign exchange loss/(gain) (2.1) - - (2.1)
Accretion on asset retirement
obligation 1.5 0.1 - 1.6
Income and capital taxes - 0.2 - 0.2
Future income tax recovery (15.8) (0.5) - (16.3)
----------------------------------------------------------------------------
62.0 8.5 - 70.5
----------------------------------------------------------------------------
Net income for the year 5.9 (0.4) - 5.5
----------------------------------------------------------------------------

Selected Balance Sheet Items

Capital assets
Property, plant and equipment, net 1,992.6 357.5 - 2,350.1
Goodwill 68.5 - - 68.5

Capital expenditures
Corporate and capital acquisitions 9.8 1.7 - 11.5
Development 60.8 11.8 - 72.6

Working capital
Accounts receivable 95.9 5.3 (1.4) 99.8
Account payable and accrued
liabilities 125.4 17.2 (1.4) 141.2
Current portion of long-term debt 36.1 - - 36.1
Long-term debt 483.0 233.3 - 716.3
----------------------------------------------------------------------------
----------------------------------------------------------------------------


10. Long-Term Incentive Plan

Under the terms of the LTIP, the number of Trust Units that may be reserved for issuance pursuant to the exercise of Unit Appreciation Rights (UARs) granted to Directors and employees of PrimeWest is limited to 7.5% of the basic number of issued and outstanding Trust Units at any given time. Payouts under the plan are based on total Unitholder return, calculated using both the change in the Trust Unit price as well as cumulative distributions paid. The plan requires that a hurdle return of 5% per annum be achieved before payouts accrue. UARs have a term of up to six years and vest equally over a three-year period, except for those issued to the members of the Board, which vest immediately. PrimeWest has the option of settling payouts under the plan in PrimeWest Trust Units or in cash. To date, all payouts under the plan have been in the form of Trust Units.

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

PrimeWest recorded $1.7 million (2006 - $1.0 million) in general and administrative expense related to the Long-Term Incentive Plan for the three months ended March 31, 2007, using the fair value method of accounting.

PrimeWest used a lattice binomial pricing model to calculate the estimated fair value of outstanding UARs issued on or after January 1,2002. The following assumptions were used to arrive at the estimated fair value:



----------------------------------------------------------------------------
Weighted Average Assumptions: Mar 31, 2007 Mar 31, 2006
----------------------------------------------------------------------------
Risk-free interest rate 3.97% 3.84%
Expected volatility in Trust Unit price 26.6% 22.3%
Expected time until exercise 1.5 - 3.5 years 3.5 years
Expected forfeiture rate 13.3% 10.6%
Expected annual dividend yield zero zero
----------------------------------------------------------------------------

----------------------------------------------------------------------------

Summary of Changes in Unit Appreciation Weighted Average
Rights Number of UARS Strike Price
----------------------------------------------------------------------------
Balance outstanding at December 31, 2006 4,460,040 $ 31.96
Granted 1,723,535 23.45
Forfeited (43,305) (31.37)
Exercised (29,412) (27.58)
----------------------------------------------------------------------------
Balance outstanding at March 31, 2007 6,110,858 $ 29.58
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Summary of UARS Outstanding at March 31, 2007

----------------------------------------------------------------------------
UARs UARs
Issued & Vested and Range of
Year of Grant Outstanding "in the Money" Strike Prices Expiry Date
----------------------------------------------------------------------------
2002 grants 509,613 509,057 25.90 - 33.76 2008
2003 grants 618,253 615,635 25.92 - 32.24 2009
2004 grants 1,019,433 820,459 24.24 - 32.49 2010
2005 grants 1,156,332 392,798 28.90 - 43.17 2011
2006 grants 1,096,499 - 23.96 - 43.41 2012
2007 grants 1,710,728 75,998 22.30 - 26.56 2013
----------------------------------------------------------------------------
Total grants 6,110,858 2,413,947 22.30 - 43.41
----------------------------------------------------------------------------
----------------------------------------------------------------------------




TRADING PERFORMANCE

----------------------------------------------------------------------------
For the
quarter ended Mar 31/07 Dec 31/06 Sep 30/06 Jun 30/06 Mar 31/06
----------------------------------------------------------------------------
TSX Trust Unit
Prices (C$ per
Trust Unit)
High $ 23.37 $ 29.21 $ 35.42 $ 35.30 $ 38.14
Low $ 19.98 $ 20.87 $ 27.33 $ 30.62 $ 29.82
Close $ 22.72 $ 21.50 $ 27.35 $ 33.50 $ 32.98
----------------------------------------------------------------------------
Average daily
traded volume 255,263 391,293 225,732 258,294 249,527
----------------------------------------------------------------------------


----------------------------------------------------------------------------
For the
quarter ended Mar 31/07 Dec 31/06 Sep 30/06 Jun 30/06 Mar 31/06
----------------------------------------------------------------------------
NYSE Trust Unit
Prices (US$
per Trust Unit)
High $ 20.26 $ 25.94 $ 31.29 $ 30.91 $ 32.90
Low $ 17.01 $ 18.03 $ 24.45 $ 27.76 $ 25.25
Close $ 19.69 $ 18.47 $ 24.64 $ 29.98 $ 28.39
----------------------------------------------------------------------------
Average daily
traded volume 450,593 796,677 441,508 438,995 463,411
----------------------------------------------------------------------------
Number of Trust
Units
outstanding
including
(thousands of
Exchangeable
Shares
Trust Units) 91,144 83,257 82,719 81,439 80,627
----------------------------------------------------------------------------
Distribution
paid per Trust
Unit $ 0.75 $ 0.75 $ 0.90 $ 1.02 $ 1.08
----------------------------------------------------------------------------
----------------------------------------------------------------------------


CORPORATE INFORMATION Corporate Offices

Board of Directors Suite 5100, 150 Sixth Avenue S.W.
Calgary, Alberta Canada T2P 3Y6
Tel: (403) 234-6600
Harold P. Milavsky,(1,2) Chair Fax: (403) 699-7477
Barry E. Emes,(1,2) Toll-Free: 1-877-968-7878
Harold N. Kvisle,(3,4) Website: www.primewestenergy.com
Kent J. MacIntyre,(3,4) Email: investor@primewestenergy.com
Michael W. O'Brien,(1,2)
James W. Patek,(3,4)
W. Glen Russell,(3,4)
Peter Valentine,(1) Trust Units and Exchangeable Shares

The Toronto Stock Exchange(PWI.UN;PWX)
(1) Member of the Audit and The New York Stock Exchange (PWI)
Finance Committee
(2) Member of the Corporate Convertible Debentures
Governance & EH&S Committee
(3) Member of the Compensation The Toronto Stock Exchange
Committee Series I Debentures (PWI.DB.A)
(4) Member of the Operations & Series II Debentures (PWI.DB.B)
Reserves Committee Series III Debentures (PWI.DB.C)

Officers Registrar and Transfer Agent

Donald A. Garner Computershare Trust Company of Canada
President and Chief Toll-free in Canada: 1-800-564-6253
Executive Officer
Auditor
Ronald J. Ambrozy
Vice-President, Business Development PricewaterhouseCoopers LLP
Calgary, Alberta
Dennis G. Feuchuk
Vice-President, Finance and Chief Engineering Consultants
Financial Officer
GLJ Petroleum Consultants Ltd.
Timothy S. Granger Calgary, Alberta
Chief Operating Officer
Legal Counsel
Brian J. Lynam
Vice-President, Operations Stikeman Elliott LLP
Calgary, Alberta
Gord Haun
Vice President, Legal and General
Counsel


Contact Information