PWI Power Integrations

PrimeWest Energy Trust announces fourth quarter and full year 2003 results CALGARY, Feb. 20 /PRNewswire-FirstCall/ -- (TSX: PWI.UN, PWX; NYSE: PWI) -- PrimeWest Energy Trust (PrimeWest) today announced interim operating and financial results for thefourth quarter and year ended December 31, 2003. Unless otherwise noted, all figures contained in this report are in Canadian dollars. PRIMEWEST ENERGY TRUST ANNOUNCES FOURTH QUARTER AND FULL YEAR 2003 RESULTS. FINANCIAL HIGHLIGHTS - FOURTH QUARTER (millions of dollars except per BOE and per Trust Unit amounts) Three months ended ------------------------------------------------------------------------- Dec 31, 2003 Sep 30, 2003Dec 31, 2002 ------------------------------------------------------------------------- Net revenue $ 73.0 $ 77.2 $ 68.8 per BOE(1) 24.72 25.70 25.20 Cash flowfrom operations 43.2 51.8 41.6 per BOE 14.62 17.25 15.22 per Trust Unit(2) 0.86 1.11 1.12 Royalty expense 21.1 23.1 17.3 per BOE 7.13 7.70 6.32 Operating expenses 21.2 17.2 16.8 per BOE 7.18 5.73 6.16 G&A expenses - Cash 4.1 3.5 3.3 per BOE 1.37 1.15 1.21 G&A expenses - Non-cash 8.5 2.3 (0.1) per BOE 2.88 0.76 (0.03) Interest expense 4.1 4.0 3.2 per BOE 1.37 1.32 1.17 Distributions to unitholders 46.3 43.7 40.3 per Trust Unit(3) 0.96 0.96 1.20 Net debt(4) 255.9 233.4 225.7 per Trust Unit(5) 5.07 4.68 5.75 ------------------------------------------------------------------------- (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 1 barrel of crude oil (2) Weighted average Trust Units & exchangeable shares (3) Based on Trust Units outstanding at date of distribution (diluted) (4) Net debt is long-term debt & adjusted for working capital (5) Trust Units and exchangeable shares outstanding (diluted) at end of period OPERATING HIGHLIGHTS - FOURTH QUARTER Three months ended ------------------------------------------------------------------------- Dec 31, 2003 Sep 30, 2003 Dec 31, 2002 ------------------------------------------------------------------------- DAILY SALES VOLUMES Natural gas (mmcf/day) 126.9 131.4 114.2 Crude oil (bbls/day) 8,189 7,913 8,766 Natural gas liquids (bbls/day) 2,779 2,811 1,878 Total (BOE/day) 32,111 32,628 29,678 REALIZED COMMODITY PRICES (CDN $) Natural gas ($/mcf) 5.52 5.59 5.09 Without hedging 5.50 5.93 5.10 Crude oil ($/bbl) 31.27 32.65 33.26 Without hedging 33.43 34.40 36.42 Natural gas liquids ($/bbl) 34.49 33.06 32.48 ------------------------------------------------------------------------- Total ($ per BOE) 32.78 33.29 31.46 Without hedging 33.25 35.07 32.43 ------------------------------------------------------------------------- FOURTH QUARTER HIGHLIGHTS - Distributions payable for the quarter totaled $0.96 per unit representing $0.32 per unit paid in November, December and January. - Production averaged 32,111 barrels of oil equivalent (BOE) per day versus the third quarter rate of 32,628 BOE/day. - Operating costs were $7.18 per BOE in the fourth quarter, up from $5.73 per BOE in the third quarter. The increase is primarily due to a prior period adjustment of $1.7 million ($0.58 per BOE) for third party processing fees for excess production over and above PrimeWest's plant ownership levels. Costs were further impacted by workovers along with repairs and maintenance of approximately $1.0 million ($0.34 per BOE). - Cash flow from operations was $43.2 million ($0.86/unit) compared to $51.8 million ($1.11/unit) in the third quarter of 2003, primarily as a result of lower volumes and commodity prices and continued strengthening in the Canadian dollar, and the provision for aged receivables that are potentially uncollectible. - Fourth quarter debt levels were approximately 1.2 times annual cash flow, compared to 1.1 times at the end of the third quarter. Debt per unit is $5.07 at the end of the fourth quarter, versus $4.68 at the end of the third quarter. - The Premium Distributioncomponent of PrimeWest's Distribution Reinvestment and Optional Trust Unit Purchase Plan, launched in December, raised $3.4 million in its first month. SUBSEQUENT EVENTS - On January 27th, 2004, PrimeWest announced that it had agreed to make an offer to acquire all of the shares of Seventh Energy. Seventh Energy's Board and executive unanimously approved the transaction and have agreed to tender their approximately 24% ownership interest. The acquisition cost is expected to be $42.6 million comprised of the assumption of $8.3 million of debt and working capital and a cash payment of $34.3 million. To protect the transaction economics, PrimeWest hedged approximately 70% of Seventh Energy's gas production at a price of $6.18 per mcf for one year. PrimeWest's existing credit line will be used to fund the cash portion of the acquisition. The offer is currently set to expire on March 15, 2004. - On February 11, 2004 PrimeWest announced that in keeping with its strategy of targeting a payout ratio of between 70-90% of cash flow from operations, the March 15, 2004 distribution would be $0.25 Canadian per Trust Unit. The decision to lower the distribution payout is a result of our near term forecast of production, commodity prices and the U.S./Canadian dollar exchange rate. FINANCIAL AND OPERATING HIGHLIGHTS - FULL YEAR (millions of dollars except per BOE and per Trust Unit amounts) 2003 2002 Change (%) ------------------------------------------------------------------------- FINANCIAL Net revenue $ 329.9 $ 264.3 26 per BOE 27.14 23.98 14 Cash flow from operations 216.6 170.9 29 per BOE 17.82 15.51 17 per Trust Unit(2) 4.67 4.96 (4) Royalty expense 101.9 56.5 80 per BOE 8.38 5.13 63 Operating expenses 79.4 60.8 31 per BOE 6.53 5.52 18 G&A expenses - Cash 14.5 11.3 28 per BOE 1.20 1.02 18 G&A expenses - Non-cash 14.4 6.1 154 per BOE 1.19 0.55 131 Interest expense 15.1 10.8 40 per BOE 1.24 0.98 27 Management fees - Cash - 4.0 per BOE - 0.36 - Non-cash - 1.4 per BOE - 0.13 Distributionsto unitholders 192.6 158.0 22 per Trust Unit(3) 4.40 4.80 (8) Net debt(4) 255.9 225.7 12 per Trust Unit(5) 5.07 5.75 (13) ------------------------------------------------------------------------- (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 1 barrel of crude oil. (2) Weighted average Trust Units & exchangeable shares (3) Based on Trust Units outstanding at date of distribution (diluted) (4) Net debt is long-term debt & adjusted for working capital (5) Trust Units and exchangeable shares outstanding (diluted) at end of period OPERATING 2003 2002 Change (%) ------------------------------------------------------------------------- Daily sales volume Natural gas (mmcf/day) 134.1 113.5 18 Crude oil (bbls/day) 8,116 9,239 (12) Natural gas liquids (bbls/day) 2,855 2,030 41 ------------------------------------------------------------------------- Total (BOE/day) 33,316 30,189 10 ------------------------------------------------------------------------- ------------------------------------------------------------------------- FINANCIAL AND OPERATING HIGHLIGHTS - FULL YEAR - Production in 2003 averaged 33,316 BOE per day, up 10% from 2002 level of 30,189 BOE/day as a result of acquisition and development capital volume additions, offset by natural production declines. - Operating margin of $20.61 per BOE for 2003, up 13% from 2002 primarily due to higher commodity prices throughout the year, offset by higher operating costs in 2003, primarily associated with power costs, and third party processing fees. - Distributions of $4.40 per Trust Unit in 2003 compared to $4.80 in 2002 reflecting an increased number of units outstanding and lower payout ratio in 2003 compared to 2002. PrimeWest's payout ratio for 2003 was approximately 89%. - Hedging loss of $30.5 million ($2.51 per BOE) in 2003, compared to gains of $28.1 million ($2.55 per BOE) in 2002 and gains of $39.5 million in 2001. - Capital development program of $104.5 million added 7.9 million BOE of Proved plus Probable reserves on a Company Interest basis, excluding technical revisions, at $14.29/BOE, which includes an additional $1.06/BOE for future development capital. - In 2003, PrimeWest made a corporate acquisition as well as a number of property purchases for total expenditures of $230.9 million. - Operating expenses were 31% higher in 2003 compared to 2002, primarily as a result of higher power costs, third party processing fees, and increased volumes from acquisitions. - Net Interest Proved plus Probable reserves of 85.8 million BOE at December 31, 2003, represents an increase of 10% from 78.0 million BOE reported on a Net Established reserves basis as at December 31, 2002. PrimeWest's current Reserve Life Index (RLI) is 10.2 years on a Net Interest Proved plus Probable basis. (Refer to the "Reserves and Production" section later in this release for reserve definitions). - Net Interest Proved Producing reserves of 62.8 million BOE at December 31, 2003, represent an increase of 3% over the December 31, 2002 Net Interest Proved Producing reserves of 60.9 million BOE. Current Net Interest Proved Producing RLIis 7.5 years with total Net Interest Proved RLI at 8.2 years. - Company Interest Proved plus Probable reserves of 106.8 million BOE at December 31, 2003 represents an increase of 2% from 104.4 million BOE reported on a Company Interest Established reserves basis at December 31, 2002. PrimeWest's current Company Interest Proved plus Probable RLI is 9.8 years, compared with an RLI of 9.5 years on a Company Interest Established basis in 2002. (Refer to the "Reserves and Production" section later in this release for reserve definitions). - Company Interest Proved Producing reserves of 77.5 million BOE at December 31, 2003, represent an increase of 4% over the December 31, 2002 Company Interest ProvedProducing reserves of 74.7 million BOE. - Cash general and administrative expenses increased $3.2 million over 2002, reflecting higher salary costs as a result of hiring additional technical staff and one time costs associated with evaluating international opportunities. - Interest expense during 2003 is 40% higher compared to 2002 as a result of higher average debt levels throughout the year. - Raised $32.4 million from the Distribution Reinvestment, Premium Distribution and Optional Trust Unit Purchase Plans. Proceeds were used for the capital development program and to repay debt. - As a result of internalization of management in November, 2002 the Trust did not incur any management fees for 2003. In 2002, the Trust paid management fees of $5.4 million, for the period January to September of 2002. - Completed $125 million U.S. private placement debt financing of secured notes at a coupon rate of 4.19% and a seven year term. MANAGEMENT'S DISCUSSION AND ANALYSIS ------------------------------------ The following is management's discussion and analysis (MD&A) of PrimeWest's operating and financial results for the year ended December 31, 2003 compared with the prior year as well as information and opinions concerning the Trust's future outlook based on currently available information. This discussion should be read in conjunction with the Trust's audited consolidated financial statements for the years ended December 31, 2003 and 2002, together with accompanying notes. Consolidation of Trust Units ---------------------------- On August 16, 2002 the Trust Units of PrimeWest began trading on a four to one consolidated basis on the TSX. All per Trust Unit amounts have been restated to conform to the four to one consolidated basis. FORWARD-LOOKING INFORMATION --------------------------- This MD&A contains forward-looking or outlook information with respect to PrimeWest. The use of any of the words "anticipate", "continue", "estimate", "expect", "may", "will", "project", "should", "believe", "outlook" and similar expressions are intended to identify forward-looking statements. 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 report. These statements speak only as of the date of this MD&A. In particular, this MD&A 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 toachieve 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; - The Trust's 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 regulation on the Trust relative to other oil and 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 - The Trust's ability to benefit from the combination of growth opportunities and the ability to grow through the capital markets. Our actual results could differ materially from those anticipated in these forward looking statements as a result of the risk factors set forth below and elsewhere in this MD&A. - Volatility in market prices for oil and natural gas; - Risks inherent in our oil and gas operations; - Uncertainties associated with estimating reserves; - Competition for, among other things; capital, acquisitions of reserves, undeveloped lands and skilled personnel; - Incorrect assessments of the value of acquisitions; - Geological, technical, drilling and processing problems; - General economic conditions in Canada, the United States and globally; - Industry conditions, including fluctuations in the price of oil and natural gas; - Royalties payable in respect of PrimeWest's oil and gas production; - Governmental regulation of the oil and gas industry, including environmental regulation; - Fluctuation in foreign exchange orinterest rates; - Unanticipated operating events that can reduce production or cause production to be shut-in or delayed; - Failure to obtain industry partner and other third party consents and approvals, when required; - Stock market volatility and market valuations; - The need to obtain required approvals from regulatory authorities, and - The other factors discussed under "Operational and Other Business Risks" in this MD&A. These factors should not be construed as exhaustive. Evaluation of Disclosure Controls and Procedures. ------------------------------------------------- The Chief Executive Officer, Don Garner, and Chief Financial Officer, Dennis Feuchuk, evaluated the effectiveness of PrimeWest Energy's disclosure controls and procedures as of December 31, 2003, and concluded that PrimeWest Energy's disclosure controls and procedures were effective to ensure that information PrimeWest is required to disclose in its filings with the Securities and Exchange Commission under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported, within the time periods specified in the Commission'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. Changes to Internal Controls and Procedures for Financial Reporting. -------------------------------------------------------------------- There were no significant changes to PrimeWest's internal controls or in other factors that could significantly affect these controls subsequent to the Evaluation Date. VISION, CORE BUSINESS AND STRATEGY PrimeWest Energy Trust is a conventional oil and gas royalty trust actively managed to generate monthly cash distributions for unitholders. The Trust's operations are focused in Canada, with its assets concentrated in the Western Canadian Sedimentary Basin. PrimeWest is one of North America's largest natural gas weighted energy trusts. Maximizing total return to unitholders, in the form of cash distributions and change 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 in 2003 and our goals for 2004 and beyond. We believe that PrimeWest can maximize total return to unitholders through the continued development of 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 to protect the interests of all stakeholders. ASSET MANAGEMENT AND GROWTH PrimeWest has a strategy to focus our expansion efforts on existing Canadian core areas, and pursue field optimization within those core areas to maximize asset value. We strive to control our operations whenever possible, and maintain high working interests. Maintaining control of 80% of operations allowsus to use existing infrastructure and synergies within our core areas. We believe this high level of operatorship can translate to control over costs and timing of capital outlays and projects. We will continue to be an opportunistic acquirer who uses the business cycles to make accretive acquisitions. The current size of the Trust gives us the ability and critical mass to make acquisitions of significant size, while still being able to add value by transacting smaller acquisitions. FINANCIAL MANAGEMENT PrimeWest strives to maintain a conservative debt position, to position us to take advantage of opportunities that arise in the acquisition market, as well as fund development activities. Our diversified debt instruments help to reduce our reliance on the bank syndicate, as well as afford additional foreign exchange protection because a portion of our debt, the secured notes, is denominated in U.S. dollars. PrimeWest's consistent commodity hedging approach helps to stabilize cash flow, reduce volatility, and protect transaction economics. In the interests of the future sustainability of the Trust, during 2003 PrimeWest began easing its distribution payout ratio from the historic highs of 95% downward to a targeted range of between 70% and 90%annually. The 2003 payout ratio was approximately 89%. Retention of some internally generated cash flow is designed to help keep the balance sheet strong and give more financial flexibility to PrimeWest in an increasingly competitive environment. Our success in executing prudent financial management in 2003 is demonstrated by our year end debt to cash flow level of 1.2 times, less than our internal limit of 2.0 times and slightly lower than our 2002 year end level of 1.3 times. PrimeWest's dual listing on both the Toronto Stock Exchange (TSX) and New York Stock Exchange (NYSE) has provided increased liquidity and greatly broadened our investor base. The NYSE listing enables U.S. unitholders to conveniently trade in our Trust Units, allows us to access the U.S. capital markets in the future, and our status as a corporation for U.S. tax purposes simplifies tax reporting for our U.S. unitholders. For eligible Canadian unitholders, PrimeWest offers participation in the Distribution Reinvestment (DRIP), Premium Distribution (PREP), or Optional Trust Unit Purchase Plan (OTUPP), all of which represent a convenient way to maximize an investment in PrimeWest. For alternate investment styles, PrimeWest also has exchangeable shares available, which permit participation in PrimeWest without the ongoing tax complications associated with receiving a distribution. CORPORATE GOVERNANCE PrimeWest remains committed to the highest standards of corporate governance. Each regulatory body has a different set ofrules pertaining to Corporate Governance, including the Toronto Stock Exchange, the New York Stock Exchange, the Canadian provincial securities commissions and the U.S. Securities and Exchange Commission (whose responsibilities include implementing rules under the United States Sarbanes-Oxley Act of 2002). PrimeWest upholds the rules of the governing bodies under which it operates, and in many cases, we already comply with proposals and recommendations that have not yet come into force. We provide full disclosure of this compliance within our proxy circular and on our website. In 2003, we strengthened our Board by adding two additional independent directors, and assigned committee leadership only to independent directors. 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. OUTLOOK - 2004 PrimeWest expects 2004 production volumes to average approximately 30,000 BOE/day. Full year operating costs are expected to be approximately $6.75/BOE, while full year G&A costs are expected to be approximately $1.25/BOE. PrimeWest expects to spend between $65 and $90 million on its 2004 capital development program, with the focus primarily in the core areas of Caroline, Valhalla, Brant/Farrow and Princess/Hays. This outlook assumes the successful completion of the Seventh Energy acquisition. Based on current expectations for capital spending and cash flow for 2004, it is anticipated that approximately 60% of 2004 distributions will be taxable and 40% will be deemed return of capital for unitholders resident in Canada. The taxability of 2004 distributions for U.S. unitholders cannot be accurately estimated and will be confirmed after year end. For residents of the U.S., Canadian withholding tax of 15% applies to the distribution. For more details on withholding tax, please visit our website at http://www.primewestenergy.com/. CASH FLOW RECONCILIATION 2002 cash flow from operations $ 170.9 Production volumes 22.5 Commodity prices 148.3 Nethedging change from prior year (58.6) Operating expenses (18.6) Royalties (45.4) Other (2.5) --------------------------------------------------------- 2003 cash flow from operations $ 216.6 --------------------------------------------------------- --------------------------------------------------------- The above table includes non-GAAP measurements The basis of PrimeWest's business and a key performance driver for the Trust is cash flow from operations. Cash flow is generated through the production and sale of crude oil, natural gas and natural gas liquids, and is dependent on production levels, commodity prices, operating expenses, hedging gains or losses, royalties and currency exchange rates. Cash flow from operations can be impacted by macro factors such as commodity prices, the currency exchange rate, royalties and the forward markets for oil and gas. Cash flow can also be impacted by factors specific to PrimeWest such as production levels, hedging gains or losses, or operating expenses, as well as interest and general and administrative expenses. It is expected that these factors will impact cash flows in the future. CAPITAL SPENDING Capital expenditures, including development and acquisitions, totaled approximately $334.4 million in 2003, versus $124.1 million in 2002. PrimeWest's capital development program for 2003 was the largest in its history, and totaled $104.5 million (2002 - $64.2 million). As commodity prices increased and potential acquisition assets became more expensive through 2003, PrimeWest increased its capital spending on internal development opportunities. Rather than risk undertaking an acquisition that did not meet economic thresholds for adding value, PrimeWest instead focused on adding reserves via development. PrimeWest's capital program in 2003 was focused on specific core areas, with 31% ($33.3 million) of the program invested in facilities to increase capacity or undertake upgrades to improve efficiencies. These benefits are expected to be realized in 2004 and beyond. The development program added 7.9 million BOE of Company Interest Proved PlusProbable reserves at a cost of $14.29 per BOE, including future development capital of $1.06/BOE, but does not reflect the impact of technical revisions. In 2003, PrimeWest completed $228.6 million in net property acquisitions (2002 - $61.0 million) adding 12.7 million BOE of Company Interest Proved reserves and 15.6 million BOE of Company Interest Proved plus Probable reserves. In 2002, PrimeWest's acquisitions include $13.2 million to acquire the 1% retained royalty as part of the internalization of management plus $0.8 million in capitalized costs to effect the internalization. ($ millions, except per BOE) 2003 2002 ------------------------------------------------------------------------- Land & lease acquisitions $ 6.0 $ 5.7 Geological and geophysical 5.8 1.8 Drilling and completions 58.4 33.4 Investment in facilities 33.3 22.3 Capitalized G&A 1.0 1.0 ------------------------------------------------------------------------- Development capital $ 104.5 $ 64.2 ------------------------------------------------------------------------- Corporate/property acquisitions 230.9 61.0 Dispositions (2.3) (4.5) Head office equipment1.3 3.4 ------------------------------------------------------------------------- Total $ 334.4 $ 124.1 ------------------------------------------------------------------------- ------------------------------------------------------------------------- 2003 2002 ------------------------------------------------------------------------- Development Program: Proved reserve additions (mmBOE)(1) 6.9 6.3 Average cost ($/BOE)(2) $ 15.98 $ 11.06 ------------------------------------------------------------------------- Proved & probable reserve additions (mmBOE)(1) 7.9 8.7 Average cost ($/BOE)(1) $ 14.29 $ 8.29 ------------------------------------------------------------------------- Acquisition Program:(3) Proved reserve additions (mmBOE)(1) 12.7 3.4 Average cost ($/BOE)(2) $ 18.84 $ 12.94 ------------------------------------------------------------------------- Proved & probable reserve additions (mmBOE)(1) 15.6 3.6 Average cost ($/BOE)(2) $ 15.71 $ 12.32 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Company Interest reserve additions, includes infill drilling, reserves that are included in technical revisions, in the reserves table (2) Under NI 51-101 (see discussion below under "Reserves and Production"), the implied methodology to be used to calculate FD&A costs includes incorporating changes in future development capital (FDC) required to bring the Company Interest Proved Undeveloped and Probable reserves to production. The average cost per BOE from Company Interest Proved reserve additions includes FDC of $0.84/BOE ($0.87/BOE for 2002), and the average cost per BOE from Company Interest Proved Plus Probable reserve additions includes FDC of $1.06/BOE ($0.91/BOE for 2002). (3) Net of dispositions and adjusted for technical performance and NI 51-101 PrimeWest's development program for 2003 totaled $104.5 million. Of this amount, 56% was spent on drilling and completions, which contributed to newreserve additions. A significant portion of the investments made in facilities represents debottlenecking, increasing capacity or other activities which contribute to future production volumes. In 2004, PrimeWest plans to spend between $65 to 90 million on its capital development programs. The 2004 program will primarily be focused in our core areas of Brant Farrow, Caroline, and Valhalla, with approximately $7 million of the total budgeted amount for activities in the Princess/Hays area, with the completion of the Seventh Energy acquisition. Given that production volumes will decline naturally over time as oil or gas reservoirs are depleted, PrimeWest is always striving to offset this natural production 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. Capital is allocated on the basis of anticipated rate of return on projects undertaken. At PrimeWest, every capital project is measured against stringent economic evaluation criteria prior to approval that include expected return, risks and further development opportunities. ASSETS Since inception, PrimeWest has focused on the conventional oil and natural gas plays of the Western Canada Sedimentary Basin. Within this focused area, we have a diversified, multi-zone suite of assets stretching from northeast B.C., across much of Alberta and down through southwest Saskatchewan. We believe this diversity reduces risks to overall corporate production and cash flow, while the core area focus allows us to capitalize on our existing technical knowledge in each of the core areas. Our operations staff are grouped into three teams - North, Central and South - with each being responsible for production and development of assets that are geographically located within those regions of the basin. During 2003, PrimeWest had 15 core areas, which in aggregate produced 87% of the company's total production volumes for the year. No core area produced greater than 20% of PrimeWest's total volumes, and PrimeWest is the operator in all but two core areas. With the acquisition of Seventh Energy, the Trust intends to expand its existing Princess/Hays region of southeast Alberta. This is an example of the Trust's strategy to expand existing areas or build new core areas within which we retain control of operations. RESERVES AND PRODUCTION In 1998, the Alberta Securities Commission established an oil and gas taskforce to investigate methods of improving oil and natural gas reserve reports prepared pursuant to National Policy Statement 2-B (NP 2B), the existing legislative regime. The taskforce passed on its findings and recommendations to the Canadian Securities Administrators in 2001, which ultimately initiated its own extensive public consultative process culminating with National Instrument 51-101 (NI 51-101) which came into force on September 30, 2003. NI 51-101 reflects a departure from its predecessor NP 2B, attempting to address the perceived shortcomings of NP 2B by improving the standards and quality of reserve reporting and achieving a higher industry consistency. Under NI 51-101, "Proved" Reserves are those Reserves that can be estimated with a high degree of certainty to be recoverable (i.e. it is likely that the actual remaining quantities recovered will exceed the estimated Proved Reserves). In accordance with this definition, the level of certainty targeted by the reporting company should result in at least a 90% probability that the quantities actually recovered will equal or exceed the estimated Reserves. There was no such consideration of probability under NP 2B. In the case of "Probable" Reserves, which are obviously less certain to be recovered than Proved Reserves, NI 51-101 states that it must be equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated Proved plus Probable Reserves. With respect to the consideration of certainty, in order to report Reserves as Proved plus Probable, the reporting company must believe that there is at least a 50% probability that the quantities actually recovered will equal or exceed the sum of the estimated Proved plus Probable Reserves. The implementation of NI 51-101 has resulted in a more rigorous and uniform standardization of Reserve evaluation. Proved plus Probable Reserves replace the "Established" Reserves definition that was used historically. Under the old rules, theEstablished Reserves category was generally calculated on the basis that Proved plus half of Probable Reserves (as those terms were defined in National Policy 2B) represented the best estimate at the time. PrimeWest believes that its Established Reserves reported under NP 2B were calculated on a reasonable basis as its estimate of Reserves that would ultimately be recovered. As a result, and for comparison purposes, we have included Established Reserves from our December 31, 2002 Reserves Report as our December 31, 2002 opening balances under the Proved Plus Probable Reserves category reconciled on a Company Interest basis and on a Net Interest Basis (see Discussion below). Similarly, we have included 50% of Probable Reserves from our December 31, 2002 Reserves Report as our opening balances under the Probable Reserves category, again reconciled on a Company Interest basis and on a Net Interest Basis. Before the implementation of NI 51-101, reporting companies reported and reconciled reserves ona "Company Interest" basis, which included working interest Reserves plus royalties receivable (with no deduction for royalties payable). Under the new rules, companies must reconcile their Reserves on a "Net Interest" basis (working interest and royalties receivable, less royalties payable). In accordance with this requirement, PrimeWest has provided its Reserves Reconciliation on a Net Interest basis. Again, for continuity and comparison purposes, we have also provided a reconciliation of our Reserves using the old Company Interest definition. PrimeWest's complete NI 51-101 reserves disclosure as at December 31, 2003, including underlying assumptions regarding commodity prices, expenses and other factors, will shortly be available in the Trust'sAnnual Information Form and on our corporate website at http://www.primewestenergy.com/. The following table sets forth a reconciliation of the Company Interest reserves of PrimeWest for the year ended December 31, 2003 derived from the report of the independent reserve evaluators, Gilbert Laustsen Jung Associates Ltd (GLJ) report using consultant's average pricing. PrimeWest's Company Interest reserves include working interest and royalties receivable. COMPANY INTEREST RESERVES - CONSULTANT'S AVERAGE PRICING Light, Medium and Heavy Crude Oil (mbbls) ----------------------------------------- Proved Total Proved Plus Producing Proved Probable Probable ------------------------------------------------------------------------- December 31, 2002 20,136.2 21,416.2 3,043.9(a) 24,460.1(b) Capital Additions(d) 832.8 575.9 43.0 618.9 Technical Revisions(e) 263.4 10.3 99.2 109.5 Acquisitions 436.9 436.9 71.9 508.8 Dispositions (28.0) (28.0) (5.0) (33.0) Economic Factors 197.0 128.0 71.0 199.0 Production (2,984.3) (2,984.3) 0.0 (2,984.3) ------------------------------------------------------------------------- December 31, 2003 18,854 19,555.0 3,324.0 22,879.0(c) ------------------------------------------------------------------------- ------------------------------------------------------------------------- Natural Gas Liquids (Bcf) --------------------------- Proved Total Proved Plus Producing Proved Probable Probable ------------------------------------------------------------------------- December 31, 2002 286.6 349.5 69.0(a) 418.5(b) Capital additions(d) 20.4 18.8 2.6 21.4 Technical Revisions(e) (6.9) (35.5) 4.4 (31.1) Acquisitions 57.3 64.0 16.2 80.2 Dispositions (0.2) (1.0) (2.0) (3.0) Economic Factors (3.4) (3.7) (1.2) (4.9) Production (48.9) (48.9) 0.0 (48.9) ------------------------------------------------------------------------- December 31, 2003 304.9 343.2 89.0 432.2(c) ------------------------------------------------------------------------- ------------------------------------------------------------------------- Natural Gas Liquids (mbbls) --------------------------- Proved Total Proved Plus Producing Proved Probable Probable ------------------------------------------------------------------------- December 31, 2002 6,795.3 8,448.3 1,740.7(a) 10,189.0(b) Capital Additions(d) 497.3 590.0 130.3 720.3 Technical Revisions(e) (8.9) (749.9) 534.8 (215.1) Acquisitions 1,565.3 1,747.7 489.7 2,237.4 Dispositions (1.1) (3.2) (1.5) (4.7) Economic Factors (8.0) (16.0) (6.0) (22.0) Production (1,041.9) (1,041.9) 0.0 (1,041.9) ------------------------------------------------------------------------- December 31, 2003 7,798.0 8,975.0 2,888.0 11,863.0(c) ------------------------------------------------------------------------- ------------------------------------------------------------------------- Barrel of oil equivalent (mmBOE) -------------------------------- Proved Total Proved Plus Producing Proved Probable Probable ------------------------------------------------------------------------- December 31, 2002 74.7 88.1 16.3(a) 104.4(b) Capital additions(d) 4.7 4.3 0.6 4.9 Technical Revisions(e) (0.8) (6.7) 1.4 (5.3) Acquisitions 11.6 12.9 3.2 16.1 Dispositions (0.1) (0.2) (0.3) (0.5) Economic Factors (0.4) (0.5) (0.1) (0.6) Production (12.2) (12.2) 0.0 (12.2) ------------------------------------------------------------------------- December 31, 2003 77.5 85.7 21.0 106.8(c) ------------------------------------------------------------------------- ------------------------------------------------------------------------- Columns may not add due to rounding (a) Amount equals 50% of Probable reserves reported in PrimeWest's December 31, 2002 reserves report. (b) Proved Plus Probable figures for December 31, 2002 represent Established Reserves from PrimeWest's December 31, 2002 Reserves Report. Proved plus Probable illustrates the reconciliation between Established Reserves at December 31, 2002 under NP 2B to Proved Plus Probable reserves as at December 31, 2003 under NI 51-101. See initial discussion above under Reserves and Production. (c) Proved Plus Probable Reserves reflect at least a 50% probability that the quantities actually recovered will equal or exceed the sum of the estimated Net Proved Plus Probable Reserves. (d) Includes Discoveries, Extensions, and Improved Recoveries. (e) Includes infill drilling. The following table is the reconciliation of PrimeWest's Net Interest reserves for the year ended December 31, 2003 using consultant's average pricing and cost estimates, as required under NI 51-101 guidelines and format. Net Interest reserves include working interest reserves plus royalties receivable less royalties payable. NET INTEREST RESERVES - CONSULTANT'S AVERAGE PRICING Light and Medium Crude Oil (mbbls) ---------------------------------------------------- Proved Total Proved Plus Producing Proved Probable Probable ------------------------------------------------------------------------- December 31, 2002 13,432.0 14,020.0 908.5(a) 14,928.5(b) Extensions 11.9 49.2 40.8 90.0 Improved Recovery 451.6 443.0 (26.1) 416.9 Technical Revisions(d) 844.3 745.6 1,147.6 1,893.2 Discoveries 0.0 0.0 0.0 0.0 Acquisitions 219.1 219.1 36.5 255.6 Dispositions (21.4) (21.4) (4.3) (25.7) Economic Factors (104.0) (100.0) 6.0 (94.0) Production (1,586.5) (1,586.5) - (1,586.5) ------------------------------------------------------------------------- December 31, 2003 13,247.0 13,769.0 2,109.0 15,878.0(c) ------------------------------------------------------------------------- ------------------------------------------------------------------------- Heavy Oil (mbbls) ---------------------------------------------------- Proved Total Proved Plus Producing Proved Probable Probable ------------------------------------------------------------------------- December 31, 2002 4,529.0 5,058.0 420.0(a) 5,478.0(b) Extensions 37.6 37.6 24.9 62.5 Improved Recovery 265.1 0.0 0.0 0.0 Technical Revisions (613.0) (681.9) 328.5 (353.4) Discoveries 0.0 0.0 0.0 0.0 Acquisitions 156.5 156.5 24.6 181.1 Dispositions (2.7) (2.7) 0.0 (2.7) Economic Factors 290.0 221.0 33.0 254.0 Production (769.5) (769.5) - (769.5) ------------------------------------------------------------------------- December 31, 2003 3,893.0 4,019.0 831.0 4,850.0(c) ------------------------------------------------------------------------- ------------------------------------------------------------------------- Associated and Non-Associated Gas (Natural Gas)(mmcf) ---------------------------------------------------- Proved Total Proved Plus Producing Proved Probable Probable ------------------------------------------------------------------------- December31, 2002 227,971.0 277,468.0 27,244.0(a) 304,712.0(b) Extensions 10,045.0 9,802.0 1,953.0 11,755.0 Improved Recovery 5,836.0 4,809.0 73.0 4,882.0 Technical Revisions(d) (7,647.0) (30,766.0) 30,591.0 (175.0) Discoveries 0.0 0.0 0.0 0.0 Acquisitions 41,841.0 46,740.0 11,770.0 58,510.0 Dispositions (175.0) (796.0) (1,551.0) (2,347.0) Economic Factors (268.0) (502.0) (6.0) (508.0) Production (36,897.0) (36,897.0) - (36,897.0) ------------------------------------------------------------------------- December 31, 2003 240,706.0 269,858.0 70,075.0 339,932.0(c) ------------------------------------------------------------------------- ------------------------------------------------------------------------- Natural Gas Liquids (mbbls) ---------------------------------------------------- Proved Proved Plus Producing Proved Probable Probable ------------------------------------------------------------------------- December 31, 2002 4,927.0 6,140.0 629.5(a) 6,769.5(b) Extensions 69.6 70.8 8.4 79.2 Improved Recovery 278.5 342.2 82.4 425 Technical Revisions(d) (25.8) (613.0) 989.6 376.6 Discoveries 0.0 0.0 0.0 0.0 Acquisitions 1,095.7 1,223.4 342.8 1,566.2 Dispositions (0.8) (2.2) (1.1) (3.3) Economic Factors (6.0) (12.0) (1.0) (13.0) Production (768.2) (768.2) - (768.2) ------------------------------------------------------------------------- December 31, 2003 5,570.0 6,381.0 2,051.0 8,432.0(c) ------------------------------------------------------------------------- ------------------------------------------------------------------------- Barrels of Oil Equivalent (mmBOE) ---------------------------------------------------- Net Proved Net Proved Net Plus Producing Net Proved Probable Probable ------------------------------------------------------------------------- December 31, 2002 60.9 71.5 6.5(a) 78.0(b) Extensions 1.8 1.8 0.4 2.2 Improved Recovery 2.0 1.6 0.1 1.7 Technical Revisions(d) (1.1) (5.7) 7.6 1.9 Discoveries 0.0 0.0 0.0 0.0 Acquisitions 8.4 9.4 2.4 11.8 Dispositions (0.1) (0.2) (0.2) (0.4) Economic Factors 0.1 0.0 0.1 0.1 Production (9.3) (9.3) - (9.3) ------------------------------------------------------------------------- December 31, 2003 62.8 69.1 16.7 85.8(c) ------------------------------------------------------------------------- ------------------------------------------------------------------------- Columns may not add due to rounding (a) Amount equals 50% of Probable reserves reported in PrimeWest's December 31, 2002 reserves report (b) Proved Plus Probable figures for December 31, 2002 represent Established reserves from PrimeWest's December31, 2002 Reserves Report. Proved plus Probable illustrates the reconciliation between Established reserves at December 31, 2002 under NP 2B to Proved Plus Probable reserves as at December 31, 2003 under NI 51-101. See initial discussion above under Reserves and Production. (c) Proved Plus Probable reserves reflect at least a 50% probability that the quantities actually recovered will equal or exceed the sum of the estimated Net Proved Plus Probable reserves. (d) Includes infill drilling. PRODUCTION VOLUMES 2003 2002 Change (%) ------------------------------------------------------------------------- Natural gas (MMcf/day) 134.1 113.5 18 Crude oil (bbls/day) 8,116 9,239 (12) Natural gas liquids (bbls/day) 2,855 2,030 41 Total (BOE/day) 33,316 30,189 10 ------------------------------------------------------------------------- Gross Overriding Royalty volumes included above (BOE/day) 1,604 1,772 (10) ------------------------------------------------------------------------- ------------------------------------------------------------------------- All production information is reported before the deduction of crown and freehold royalties. The 10% increase in production volumes year over year is due to the acquisition of the Caroline / Peace River Arch properties, completed in January of 2003 combined with development additions, and offset by natural decline. During 2003, natural production decline averaged approximately 20%. Through the year, approximately3,060 BOE/day of incremental production was brought on-line from development activities to mitigate decline. Approximately 1,700 BOE/day remained behind pipe at the end of 2003. PrimeWest expects production for full year 2004 to be approximately 30,000 BOE per day. This estimate incorporates PrimeWest's expected natural decline rate, production volume shut-ins described in greater detail below, as well as the offset of production additions due to the capital development program and the expected acquired production from the purchase of Seventh Energy. It is anticipated that production from PrimeWest's non-operated Ells property in NorthEast Alberta will be subject to shut-in by the Alberta Energy and Utilities Board prior to spring break-up, as a result of the gas over bitumen issue. An additional shut-in at PrimeWest's non-operated Whiskey Creek area due to facility capacity constraints, will result in PrimeWest's volumes being temporarily shut-in. These shut-ins are anticipated to impact PrimeWest by approximately 1,000 BOE/day of natural gas production. These shut-ins at non-operated properties highlight the importance of PrimeWest's strategy of maintaining control of operations wherever possible, thereby retaining control of projects andtiming. COMMODITY PRICES Benchmark Prices 2003 2002 Change (%) ------------------------------------------------------------------------- Natural gas ($/mcf AECO) $ 6.70 $ 4.07 65 Crude oil (U.S.$/bbl WTI) $ 31.04 $ 26.08 19 ------------------------------------------------------------------------- Average Realized Sales Prices(1) (Canadian Dollars) 2003 2002 Change (%) ------------------------------------------------------------------------- Natural gas ($/mcf) $ 6.05 $ 4.55 33 Crude oil ($/bbl) 33.94 33.53 1 Natural gas liquids ($/bbl) 35.34 26.56 33 ------------------------------------------------------------------------- Total Oil Equivalent(2) ($/boe) $ 35.68 $ 29.16 22 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Realized hedging gain (loss) included in prices above ($ per BOE) $ (2.51) $ 2.55 (198) ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Includes hedging gains/losses (2) Excludes sulphur During 2003 commodity prices were generally higher than in 2002, with average realized selling prices per BOE increasing by 22% in 2003 over 2002. Within this higher commodity price environment, PrimeWest realized an average loss of $2.51 per BOE due to hedging. This loss does not represent a cash expenditure, but is the calculation of the additional revenue PrimeWest would have generated had it not sold production on a hedged basis. PrimeWest's cash flow from operations is directly impacted by commodity prices, but the use of hedging can increase or decrease the prices realized by the Trust. PrimeWest's hedging program delivered gains of $37.1 million from January 1, 2001 through to December 31, 2003 and remains an important element in PrimeWest's financial management strategy. The hedging program is designed to reduce commodity price volatility, increase cash flow stability as well as protect the economics of asset acquisitions. The realized selling price in Canadian dollars is also impacted by currency exchange rates. Oil and gas prices are denominated in U.S. dollars, therefore, a strengthened Canadian dollar translates into lower realized prices and lower Canadian revenue for producers. Throughout 2003, the Canadian dollar strengthened more than 20%. At December 31 2002, the Canadian dollar was $0.6334 versus its U.S. counterpart, compared to $0.7673 at December 31, 2003. With oil and natural gas prices denominated in US dollars, the strengthening Canadian dollar during 2003 continued to negatively impact Canadian dollar realizations. Crude Oil Prices - Crude oil prices fluctuated significantly during 2003, reflecting uncertainties around the globe. Contributing factors include erratic production of oil in an unstable post-war Iraq; supply management by the members of OPEC; ongoing civil unrest in Nigeria and Venezuela; record low storage levels of oil being maintained by refiners in the contiguous U.S.; and a recovering U.S. economy. The weakness of the U.S. dollar in relation to most of the rest of the world's currencies has had the effect of increasing the purchasing power of many countries, contributing to an economic recovery. In addition, a weaker U.S. dollar has reduced the overall revenue of OPEC countries, which may have required them to manage to a higher WTI benchmark price. During 2003 oil reached a high of $US 39.25 on February 27, 2003, and a low of $US 25.22 on April 29, 2003 closing out the year at $US32.52 per barrel. The forward market for crude oil indicates prices are in gradual decline over the next four quarters. U.S. crude oil inventories were at record low levels as we entered 2004. At the OPEC meeting on February 9th, 2004 the Cartel announced its intention to reign in overproduction by some of its members and to cut quotas by a further 1 millionbarrels per day on April 1, 2004. Unless they are successful in this new initiative, it is expected that the current level of output from OPEC will be sufficient to begin to build inventories by the end of the first quarter and into the second quarter of 2004 which could result in a slight reduction of WTI pricing in 2004 compared to 2003. However, given the global economic recovery currently underway, oil demand is expected to continue to increase in 2004. This additional demand combined with continued geopolitical unrest in many of the significant producing nations referred to above, leaves oil prices vulnerable to any supply disruptions and the associated high pricing scenario as was experienced in 2003. PrimeWest's greater natural gas weighting makes its revenues less susceptible to volatility in crude oil prices as compared to companies with a heavier crude oil weighting. Natural Gas Prices - Natural gas prices increased approximately 65% from a 2002 average of $4.07 per mcf to an average of $6.70 per mcf during 2003. Natural gas prices rose significantly during the first quarter of 2003 reaching a high of over $9.00/mcf at AECO on a one month forward spot basis due to very cold weather conditions in the consuming areas of the United States during February and March that resulted in gas shortages. This late winter cold weather caused the natural gas storage levels in the US and Canada to exit the winter heating season at record low levels. Gas prices maintained strength through the remainder of 2003 as storage owners, which includes local distribution companies, purchased gas to ensure adequate storage levels for the November 2003 to March 2004 winter heating season. As the industry entered the winter heating season in November, storage levels were back to normal levels. However, due to the early cold weather that was experienced in the major U.S. Northeast market area during December, combined with the recent experience of low storage levels the previous year, the market has continued to purchase spot gas at relatively high prices in order to manage the storage inventories. The high gas price environment in 2003 has had the effect of reducing industrial demand while at the same time increasing industry drilling activity. However, until the rebalancing of supply and demand becomes a reality as evidenced by sustained year over year storage level increases into spring, gas pricing is not anticipated to drop significantly. Even in the event of softer prices during the summer of 2004, the long term price outlook for 2005 and beyond is still very positive due to an anticipated gas supply delivery shortfall from conventional sources. SALES REVENUE % of % of Change Revenue ($ millions) 2003 total 2002 total (%) ------------------------------------------------------------------------- Natural gas (1) $ 297.3 68 $ 187.7 59 58 Crude oil 100.5 23 113.1 35 (11) Natural gas liquids 36.8 9 19.7 6 87 ------------------------------------------------------------------------- Total $ 434.6 $ 320.5 36 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Hedging (loss)/gains included above(2) $ (30.5) 100 $ 28.1 100 (209) ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Includes sulphur (2) Net of amortized premiums Revenues for 2003 were $434.6 million compared to $320.5 million in the previous year, including the effect of hedging. Higher gas sales volumes as a result of the Caroline/Peace River Arch acquisition completed in January 2003 along with higher crude oil and natural gas liquids prices were the major contributors to the increased revenue in 2003. Revenues are impacted by commodity prices, production volumes, and currency exchange rates. The strength of the Canadian dollar versus its American counterpart through the last three quarters of 2003 negatively impacted the oil and gas sector, including PrimeWest. Oil and gas prices are denominated in U.S. dollars, therefore, a strengthened Canadian dollar translates into lower Canadian revenue for producers. Based on the forward markets, the outlook for commodity prices in 2004 is lower, and has been reflected in PrimeWest's internal price forecasts. If the pricing environment softens in 2004, and the Canadian dollar remains strong, oil and gas revenues will be negatively impacted. Since a greater portion of PrimeWest's revenues (68%) is derived from natural gas, the Trust has greater sensitivity to changes in natural gas prices than crude oil prices. Natural decline is expected to reduce production volumes, some of which is expected to be offset by development projects and any acquisition activity. 2003 HEDGING RESULTS As part of our financial management strategy, PrimeWest uses a consistent commodity hedging approach. The purpose of the hedging program is to reduce volatility in cash flows, protect acquisition economics and to stabilize cash flow against the unpredictable commodity price environment. PrimeWest's hedging program delivered gains of $37.1 million over the 3 year period from January 1, 2001 to December 31,2003. Hedging is an important element in PrimeWest's financial management strategy. It is designed to reduce commodity price volatility, increase cash flow stability, and protect the economics of asset acquisitions. The hedging policy reflects a willingness to forfeit a portion of the pricing upside in return for protection against a significant downturn in prices. Crude Oil Natural Gas BOE ($/bbl) ($/mcf) ($/BOE)(1) ------------------------------------------------------------------------- 2003 2002 2003 2002 2003 2002 ----------------------------------------------------- Unhedged price $ 36.55 $ 34.25 $ 6.51 $ 3.81 $ 38.14 $ 26.61 Hedge gain/(loss) (2.61) (0.72) (0.46) 0.74 (2.51) 2.55 ------------------------------------------------------------------------- Realized price $ 33.94 $ 33.53 $ 6.05 $ 4.55 $ 35.63 $ 29.16 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Excludes sulphur 2003 Hedge Gain 2002 Hedge Gain (Loss) (Loss) ------------------------------------------------------------------------- % Hedged $ millions % Hedged $ millions --------------------------------------------- Crude oil 65 $ (7.7) 71 $ 30.5 Natural gas 61 (22.8) 69 (2.4) ------------------------------------------------------------------------- Total Gain $ (30.5) $ 28.1 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Approximate percentage of future anticipated production volumes hedged at December 31, 2003, net of anticipated royalties, reflecting full production declines with no offsetting additions: 2004 Q1 Q2 Q3 Q4 Full Year ------------------------------------------------------------------------- Crude Oil 66% 60% 48% 41% 54% Natural Gas 66% 44% 46% 17% 43% ------------------------------------------------------------------------- ------------------------------------------------------------------------- 2005 ------------------------------------------------------------------------- Crude Oil 9% 9% 0% 0% 5% ------------------------------------------------------------------------- ------------------------------------------------------------------------- The mark-to-market valuation of hedges in place as at December 31, 2003 was a $6.0 million loss consisting of a $3.9 million loss in crude oil and a $2.1 million loss in natural gas. A summary of contracts in place as at December 31, 2003 is available under Note 13 in the Notes to the Consolidated Financial Statements, reproduced later in this press release. ROYALTIES (NET OF ARTC) Royalties are paid by PrimeWest to the owners of mineral rights with whom PrimeWest holds leases. PrimeWest has mineral leases with the Crown (Provincial and Federal Governments), freeholders (individuals or other companies) and other operators. ARTC is the Alberta Royalty Tax Credit, a tax rebate provided by the Alberta government to producers that paid eligible Crown royalties in the year. ($ millions, except per BOE) 2003 2002 Change (%) ------------------------------------------------------------------------- Royalty expense (net of ARTC) $ 101.9 $ 56.5 80 Per BOE $ 8.38 $ 5.13 63 ------------------------------------------------------------------------- Royalties as % of sales revenues With hedge revenue 24% 18% 33% Excluding hedge revenue 22% 19% 16% ------------------------------------------------------------------------- ------------------------------------------------------------------------- Royalty expense in 2003 was 80% higher than in 2002 due to higher crude oil and natural gas prices year over year. Royalties are calculated on a sliding scale based on commodity prices. As commodity prices increase, so do royalty rates. Since hedging gains do not attract royalties and result in lower royalty expense as a percentage of sales, the hedging gains realized in 2002 contributed to the lower royalty rate. As a percent of sales revenue, royalties were 16% higher in 2003 compared to 2002. Royalty rates are based on commodity prices so future changes to prices will be accompanied by changes in royalty rates and royalty expense. OPERATING EXPENSES ($ millions, except per BOE) 2003 2002 Change (%) ------------------------------------------------------------------------- Operating expense ($ millions) $ 79.4 $ 60.8 31 Per BOE $ 6.53 $ 5.52 18 ------------------------------------------------------------------------- ------------------------------------------------------------------------- In general, as natural gas prices rise, power costs also increase accordingly. In 2003, PrimeWest's power cost increased by $2.8 million ($0.23 per BOE). During 2003, as natural gas prices strengthened, power costs escalated. However, PrimeWest's natural gas weighting gives a natural hedge to rising power costs. Further, PrimeWest engaged in heat rate swaps, and recovered $0.5 million in protection ($0.04 per BOE) reducing the power cost, resulting in a net increase in power expense of $2.3 million ($0.19 per BOE). Operating expenses for 2003 are $18.6 million higher than 2002. On a per BOE basis operating expenses increased 18% over the 2002 level. A primary contributor to the increase in operating expenses during 2003 was the increased volumes and resulting operating cost of $6.7 million associated with the Caroline/Peace River Arch acquisition which closed in January 2003. Increased operating expenses for 2003 include prior period adjustments in the form of equalization fees PrimeWest incurred to cover the costs associated with processing more production volumes than allotted at a shared production facility. These increased equalization fees totaled $2.3 million ($0.19 per BOE). Field consulting and contracting expenses totaled $1.4 million ($0.12 per BOE) and were attributed to a field level restructuring undertaken in 2003 which is expected to reduce ongoing staff costs by 20%. Well workovers and repairs during 2003 added an additional $1.9 million ($0.16 per BOE) to operating expenses and in addition, non-operated property expenses for 2003 were $2.5 million higher than the 2002 costs. Operating expenses are primarily impacted by labour and power expenditures which representapproximately 30% of PrimeWest's costs. In addition, partner operated expenses, along with property taxes and lease rentals make up approximately 24% of our costs, which are difficult to influence. PrimeWest is targeting 2004 operating expenses at approximately $6.75 per BOE. Cost control will be undertaken by maintaining control of operations wherever possible. OPERATING MARGIN ($/BOE) 2003 2002 Change (%) ------------------------------------------------------------------------- Sales price and other revenue(1) $ 35.52 $ 29.11 22 Royalties (8.38) (5.13) 63 Operating expenses (6.53) (5.52) 18 ------------------------------------------------------------------------- Operating margin $ 20.61 $ 18.46 12 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Includes hedging and sulphur Operating margins increased 12% from 2002 on a per BOE basis. The increase in 2003 compared to 2002 is primarily due to higher sales prices, offset by higher operating expenses and higher royalties. Operating margin is an important measure of our business because it gives an indication of how much money PrimeWest makes per barrel of oil equivalent that is produced. Based on PrimeWest's commodity price outlook, operating expense expectations and hedge positions, margins are expected to be lower in 2004 than 2003. This however, will be heavily dependent on actual commodity prices. PrimeWest will continue to emphasize maintaining lower than average operating expenses to maximize margins, which can reduce the volatility of cash flows through commodity price cycles. GENERAL & ADMINISTRATIVE EXPENSE ($ millions, except per BOE) 2003 2002 Change (%) ------------------------------------------------------------------------- Cash G&A expense ($ millions) $ 14.5 $ 11.3 28 Per BOE 1.20 1.02 18 Non-cash G&A expense ($ millions) 14.4 6.1 136 Per BOE $ 1.19 $ 0.56 113 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Cash G&A expense increased 28% in 2003 from 2002, primarily due to higher recruitment costs, staff levels, short term incentive payments and salary payments totaling approximately $2.6 million ($0.21 /BOE). In addition, one time costs associated with international business development activities of $0.4 million were incurred in 2003. We anticipate that 2004 G&A costs will be reduced on a dollar basis due to the elimination of international business development activities one time evaluation costs. Non-cash G&A expense consists mainly of the change in the value of the Unit Appreciation Rights (UARs). Unit Appreciation Rights in a trust are similar to stock options in a corporation. Consistent with the resolution approved by unitholders at the last annual meeting of unitholders, PrimeWest continues to pay for the exercise of UARs in Trust Units. The intent of PrimeWest's UAR plan is to align employee and unitholder interests. Of the $14.4 million in non-cash G&A expense, $13.9 million pertained to UARs. This compares to $6.12 million in 2002 and is attributable to PrimeWest's 28% total return to unitholders in 2003 (2002 - 19.5%), along with ongoing employee UAR grants to ensure PrimeWest remains competitive in attracting and retaining quality staff. Theprogram rewards employees based on total unitholder return, which is comprised of cumulative distributions on a reinvested basis plus growth in unit price. No benefit accrues to employees who hold UARs until the unitholders have first achieved a 5% total annual return from the time of grant. Expenses related to the UAR plan are recorded on a mark-to-market basis, whereby increases or decreases in the valuation of the UAR liability are reported quarterly, as a charge to the income statement. MANAGEMENT FEES/INTERNALIZATION ($ millions) 2003 2002 ------------------------------------------------------------------------- Cash management fees $ - $ 4.0 Non-cash management fees - 1.4 Non-cash internalization costs - 13.1 Acquisition / disposition fees - 0.4 1% retained royalty - 1.3 Purchase of 1% retained royalty - 13.2 ------------------------------------------------------------------------- $- $ 33.4 ------------------------------------------------------------------------- ------------------------------------------------------------------------- On November 4, 2002, unitholders voted by a 92% majority to internalize management at a cost of $26.3 million. The management internalization was an important change for PrimeWest and benefited unitholders for several reasons. The internalization was accretive to net asset value and cash flow in 2003 and improved the long term cost structure of the Trust. Further, it more appropriately aligned management interests with unitholders, and resulted in unitholders having the ability to elect all of the directors of the Trust. INTEREST EXPENSE ($millions, except per Trust Unit) 2003 2002 Change (%) ------------------------------------------------------------------------- Interest expense $ 15.1 $ 10.8 40 Period end net debt level $ 255.9 $ 225.7 13 Debt per Trust Unit $ 5.07 $ 5.75 (13) ------------------------------------------------------------------------- Average cost of debt 4.7% 4.6% 2 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Interest expense, representing interest on bank debt, increased to $15.1 million from $10.8 million in 2002 due to higher average debt balances in 2003 compared to 2002. In 2003, PrimeWest diversified its debt financing by completing a private placement of U.S. $125 million at a U.S. fixed coupon rate of 4.19%. The actual Canadian interest expense will fluctuate with any changes in the Canadian/U.S. foreign exchange rates. Canadian interest rates are expected to decline in 2004, as the Bank of Canada has reduced its overnight rate by 25 basis points on January 20, 2004. Additional Bank of Canada rate reductionsare anticipated later in 2004. FOREIGN EXCHANGE GAIN The foreign exchange gain of $11.9 million results from the translation of the U.S. dollar denominated secured notes and related interest payable. The notes were issued at 1.3923:1 Canadian to U.S.dollars, and the close rate on December 31, 2003 was 1.2965:1 Canadian to U.S. dollars. DEPLETION, DEPRECIATION AND AMORTIZATION The 2003 DD&A rate of $16.70 per BOE is higher than the full year 2002 rate of $16.51 per BOE due to 2003 acquisitions. The 2002 and 2003 DD&A rates are inflated relative to the acquisition cost of certain reserves due to the requirement to account for future income tax liabilities associated with the acquisition of those reserves. The offset is in the income tax recovery. Without this tax adjustment, the DD&A rate would be lower by approximately $3.14 per BOE in 2003 (2002 - $3.62 per BOE). CEILING TEST PrimeWest performs a ceiling test at each balance sheet date, which compares the net book value of capital assets (i.e. the value of capital assets reflected on the balance sheet, net of DD&A) with an estimate of the future net revenue from proved reserves (as determined by independent engineers) less estimated future general and administrative costs, debt servicing costs, and applicable income taxes. Performing this test at December 31, 2003, using commodity prices as at December 31, 2003 of AECO $6.09 per mcf for natural gas and $U.S. 32.52 per barrel WTI for crude oil results in a ceiling test surplus. The new CICA Accounting Guideline 16 was introduced in 2003 (for additional details see "Accounting Pronouncements Issued but not Implemented" later in this release). The impact of this new guideline on the Trust would be an impairment to capital assets of ($460) million before tax or ($300) million after tax. The after tax impairment of ($300) million will be booked to retained earnings in the first quarter of 2004. SITE RECLAMATION AND RESTORATION RESERVE Since the inception of the Trust, PrimeWest has maintained an environmental fund to pay for future costs related to well abandonment and site clean-up. In 2003, PrimeWest contributed $0.50 per BOE, totaling $6.2 million for 2003, to this fund. A provision of $4.2 million was made for site reclamationand abandonment during 2003, compared to $4.0 million for 2002. The provision is based on site reclamation and abandonment cost estimates made by both PrimeWest and external engineers and is charged to depletion, depreciation and amortization expense on a unit of production basis. An additional contribution of $4.2 million was made to fund reclamation expenditures associated with properties acquired in 2002. The fund is used to pay for reclamation and abandonment costs as they are incurred. In 2003,a total of $2.2 million was paid out of the reserve, leaving a balance of $8.2 million in the fund at year end. The 2004 contribution rate has been set at $0.50 per BOE which is expected to be sufficient to meet the funding requirements for the future. NET ASSET VALUE Net asset value (NAV) is a measure of the worth of PrimeWest's underlying assets - primarily crude oil, natural gas and natural gas liquids reserves. The value placed on these reserves is the pre-tax present value of future net cash flows, discounted at 10% from these reserves, as independently assessed in accordance with NI 51-101 by GLJ as at December 31, 2003. Two commodity price forecasts were used in this assessment. The first forecast is based on the arithmetic average of three independent consultants' price forecasts. The second forecast is the forward oil and natural gas prices as of February 5th, 2004. The present value of reserves reflects provisions for royalties, operating costs, future capital costs and site reclamation and abandonment costs, but is prior to deductions for income taxes, interest costs and general and administrative costs. This calculation is a "snapshot" in time and is heavily dependent upon future commodity price expectations at the point in timethe "snapshot" is taken. Accordingly, the NAV as at January 1, 2004 may not reflect fairly the equity market trading value of PrimeWest. It is also significant to note that NAV reduces as reserves are produced and net operating cash flow is distributed. Value is delivered to unitholders through such monthly distributions. The following table sets forth the calculation of NAV: 2003 Feb 5th 2002 Consultant's Forward Consultant's Average Strip Average ------------------------------------------------------------------------- As at December 31 ($ millions except per Trust Unit Amounts) 2003 2003 2002 ------------------------------------------------------------------------- Assets PV 10 of future cash flow (1) 904.6 1,036.5 923.0 Mark to market value of hedging contracts (0.5) (6.0) (13.6) Unproved lands 36.0 36.0 44.2 Reclamation fund 8.2 8.2 - 948.31,074.7 953.6 Liabilities Debt and working capital deficiency (255.9) (255.9) (225.4) ------------------------------------------------------------------------- Net Asset Value 692.4 818.8 728.2 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Outstanding units - millions, fully diluted 50.4 50.4 39.3 NAV per unit $ 13.74 $ 16.25 $ 18.53 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) 100% of Proved and Probable reserves for 2003; 100% of established reserves for 2002 2003 Feb 5th 2002 Consultant's Forward Consultant's Pricing Assumptions Average Strip Average ------------------------------------------------------------------------- Edmonton Par Oil - Cdn. $/bbl 2004 $37.81 $40.11 $34.41 2005 $34.10 $36.81 $32.14 2006 $32.79 $35.63 $32.09 2007 $32.72 $35.26 $32.53 2008 $32.89 $35.19 $33.11 Spot Gas at AECO-C - Cdn. $/mcf 2004 $5.90 $6.23 $5.13 2005 $5.33 $6.02 $4.76 2006 $4.98 $5.64 $4.70 2007 $4.95 $5.44 $4.76 2008 $4.92 $5.36 $4.79 ------------------------------------------------------------------------- The NAV calculation is based on the above reference prices as of December 31, 2003 and 2002 and is highly sensitive to changes in price forecasts over time as well as the exchange rate. In addition, the year over year change is impacted by the cash distributions made throughout the year which totaled $192.6 million or $4.40 per unit. Also, the NAV calculation assumes a "blow down" scenario whereby existing reserves are produced without being replaced by acquisitions. A major cornerstone of PrimeWest's strategy is to replace reserves through accretive acquisitions and capital development. INCOME AND CAPITAL TAXES ($ millions) 2003 2002 Change (%) ------------------------------------------------------------------------- Income and capital taxes $ 3.8 $ 2.9 31 Future income taxes recovery (83.0) (32.3) 157 ------------------------------------------------------------------------- $ (79.2) $ (29.4) 169 ------------------------------------------------------------------------- ------------------------------------------------------------------------- On June 9, 2003, the Canadian Government substantially enacted Federal income tax changes for the oil and gas resource sector as outlined in its 2003 Budget. The Federal income tax changes effectively reduced the statutory tax rates for current and future periods, resulting in a significant increase in the future tax recovery (a non-cash item) compared to the first quarter and prior years. Specifically, the current 100% deductibility of the resource allowance will be completely phased out by the year 2007. During the same time frame, Crown charges will become 100% deductible and resource tax rates will decline from the current 27% to 21%. NET INCOME ($ millions) 2003 2002 ------------------------------------------------------------------------- Net Income $ 90.3 $ 0.6 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Cash flow from operations, as opposed to net income, is the primary measure of performance for an energy trust. The generation of cash flow is critical to the ability of an energy trust to continue to sustain the monthly distribution of cash to unitholders. Conversely, net income is an accounting measure impacted by both cash and non-cash items. The largest non-cash items impacting PrimeWest's net income are depletion, depreciation, and amortization (DD&A) and future taxes. The future tax figure has been significantly impacted by changes to statutory tax rates during the second quarter of 2003. Net income for 2003 was impacted by higher sales revenue as a result of higher commodity prices and volumes compared to 2002. In addition, future income tax recoveries and non-cash foreign exchange gains contributed approximately $95 million to net income in 2003. LIQUIDITY & CAPITAL RESOURCES LONG TERM DEBT ($ millions) 2003 2002 Change (%) ------------------------------------------------------------------------- Long-term debt $ 250.1 $ 225.0 11 Working capital deficit 5.8 0.7 443 ------------------------------------------------------------------------- Net debt $ 255.9 $ 225.7 12 Market value of Trust Units and exchangeable shares outstanding(1) 1,380.7 989.2 41 ------------------------------------------------------------------------- Total capitalization $1,636.6 $1,214.9 35 ------------------------------------------------------------------------- Net debt as a % of total capitalization 16% 19% (5) ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Based on December 31 Trust Unit closing price of $27.56 and exchangeable ratio of 0.44302:1 Long term debt is comprised of bank credit facilities and senior secured notes for $88.0 million and $162.1 million, respectively. PrimeWest has a borrowing base of $390 million at year end 2003. The bank credit facilities consists of a revolving term loan of $188 million and an operating facility of $25 million. In addition to amounts outstanding under the facilities,PrimeWest has outstanding letters of credit in the amount of $5.1 million (2002 - $3.8 million). The credit facility revolves until June 30, 2004, by which time the lenders will have conducted their annual borrowing base review. On May 7, 2003, PrimeWest replaced a portion of its bank debt with Senior Secured Notes in the amount of $U.S. 125 million. The notes have a final maturity date of May 7, 2010, and bear interest at 4.19% per annum, with interest paid semi-annually on November 7 and May 7 of each year. The Note Purchase Agreement requires PrimeWest to make four annual principal repayments of $U.S. 31,250,000 commencing May 7, 2007. Being in a cyclical business, it is important that PrimeWest maintain financial flexibility to ensure we can operate without any restrictions regardless of where commodities are in the price cycle. PrimeWest's objective is to have conservative debt levels. Our internal targets are to keep debt at 2 times or less than our annual cash flow and less than 25% of enterprise value. For 2003, PrimeWest's debt to cash flow was 1.2 times, and at year end, was 16% of our total enterprise value. In 2003, PrimeWest expanded its debt financing strategy by undertaking a U.S. private placement and thus reducing its total dependence on bank financing. In addition, PrimeWest moved to a lower payout ratio thus using internally generated cash to invest in development opportunities or pay down bank debt. FIRST AND FINAL ADD TO FOLLOW DATASOURCE: PrimeWest Energy Trust CONTACT: For Investor Relations inquiries, please contact: George Kesteven, Manager, Investor Relations, (403) 699-7367; Cindy Gray, Investor Relations Advisor, (403) 699-7356, Toll-free: 1-877-968-7878, e-mail: ; To request a free copy of this organization's annual report, please go to http://www.newswire.ca/ and click on reports@cnw.

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