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PrimeWest Energy Trust announces first quarter 2004 results CALGARY, April 27 /PRNewswire-FirstCall/ -- (TSX: PWI.UN, PWX; NYSE: PWI) - PrimeWest Energy Trust (PrimeWest or the Trust) today announced interim operating and financial results for the first quarter ended March 31, 2004, and information is provided as of April 27, 2004. Unless otherwise noted, all figures contained in this report are in Canadian dollars. First Quarter Highlights: - First quarter production averaged 31,202 barrels of oil equivalent (BOE) per day, compared to the fourth quarter 2003 rate of 32,111 BOE/day(1). - Distributions of $0.82 per unit represent a payout ratio of approximately 70%, compared to fourth quarter 2003 distributions of $0.96 per unit, representing a payout ratio of 107%. - Cash flow from operations of $58.5 million ($1.15 per unit) compared to $43.2 million ($0.86 per unit) in the fourth quarter of 2003, primarily due to a continued strong commodity price environment. - Operating costs of $19.7 million ($6.92 per BOE) were lower than the fourth quarter 2003 operating costs of $21.2 million ($7.18 per BOE). - The acquisition of Seventh Energy Ltd. closed during the quarter, for total consideration of $34.8 million plus assumed debt, working capital adjustments and transaction costs of $11.6 million, adding approximately 1,300 BOE/day of predominantly natural gas production to PrimeWest and providing future development potential. - PrimeWest determined that as of March 22, 2004 the ownership of its trust units by non-residents exceeded 50%, giving the Trust more than 2.5 years to comply with the Canadian Federal Government's proposal to limit foreign ownership of Canadian energy royalty trusts to less than 50% by January 1, 2007. PrimeWest continues to investigate alternatives to comply with this proposal should it become law. Subsequent Events - On April 5, 2004 PrimeWest announced a bought deal financing of 5.4 million units at $26.30 per unit, raising gross proceeds totaling approximately $142 million, and net proceeds after commissions of $134.9 million. The funds will be used to reduce debt partially incurred in the $46 million acquisition of Seventh Energy, for ongoing capital expenditures and for general corporate purposes. On a proforma basis after applying the proceeds of the offering, PrimeWest's first quarter net debt would be approximately $170 million, and net debt to first quarter cash flow annualized would be approximately 0.7 times. - On April 15, 2004 PrimeWest announced the appointment of Peter Valentine to its Board of Directors. Mr. Valentine brings extensive experience to the audit function, including his current position as Chair of the Board of Governors of the Canadian Comprehensive Audit Foundation. As an independent and unrelated director, Mr. Valentine will serve on PrimeWest's Audit Committee. - On April 15, 2004 the Board of Directors also established a new Operations and Reserves Committee. Management's Discussion and Analysis The following is management's discussion and analysis (MD&A) of PrimeWest's operating and financial results for the quarter ended March 31, 2004 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. 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, as contained in the Trust's 2003 Annual Report. Financial and Operating Highlights - First Quarter Financial Highlights Three Months Ended -------------------------------------- (millions of dollars, except per Mar 31, Dec 31, Mar 31, BOE and per Trust Unit amounts) 2004 2003 2003 ------------------------------------------------------------------------- Net revenue $ 85.7 $ 73.0 $ 94.0 per BOE(1) 30.20 24.72 30.23 Cash flow from operations 58.5 43.2 64.8 per BOE 20.59 14.62 20.84 per Trust Unit(2) 1.15 0.86 1.53 Royalty expense 23.3 21.1 32.7 per BOE 8.22 7.13 10.50 Operating expenses 19.7 21.2 20.6 per BOE 6.92 7.18 6.63 G&A expenses - Cash 4.2 4.1 3.8 per BOE 1.49 1.37 1.23 G&A expenses - Non-cash 0.4 8.5 0.4 per BOE 0.15 2.88 0.12 Interest expense 3.2 4.1 3.6 per BOE 1.11 1.37 1.16 Distributions to unitholders 41.1 46.3 49.8 per Trust Unit(3) 0.82 0.96 1.20 Net debt(4) 305.7 255.9 281.5 per Trust Unit(5) 5.99 5.07 6.15 ------------------------------------------------------------------------- (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. 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) Weighted average Trust Units & exchangeable shares (diluted). (3) Based on Trust Units outstanding at date of distribution. (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 Three months ended -------------------------------------- Mar 31, Dec 31, Mar 31, 2004 2003 2003 ------------------------------------------------------------------------- Daily Sales Volumes Natural gas (mmcf/day) 123.9 126.9 140.3 Crude oil (bbls/day) 7,864 8,189 8,142 Natural gas liquids (bbls/day) 2,696 2,779 3,030 ------------------------------------------------------------------------- Total (BOE/day) 31,202 32,111 34,554 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Realized Commodity Prices(1) (Cdn $) Natural gas ($/Mcf) 6.57 5.52 6.92 Without hedging 6.62 5.50 7.84 Crude oil ($/bbl) 34.93 31.27 38.33 Without hedging 39.44 33.43 43.65 Natural gas liquids ($/bbl) 38.54 34.49 40.77 ------------------------------------------------------------------------- Total ($ per BOE) 38.21 32.78 40.70 Without hedging 39.56 33.25 45.68 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Includes hedging gains (losses) 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 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, operation 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 therefrom; - 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, natural gas and natural gas liquids; - 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, natural gas and natural gas liquids; - 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 or interest 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 March 31, 2004 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 (SEC) 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. 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 the first quarter of 2004 and our goals for the remainder of 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 allows us 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. During the first quarter of 2004, the Trust closed the acquisition of Seventh Energy Ltd. (Seventh), a publicly traded company with primarily natural gas production in Southeastern Alberta, for total consideration of $34.8 million plus assumed debt, working capital adjustments and transaction costs of $11.6 million. The predominantly natural gas assets acquired from Seventh are adjacent to PrimeWest's existing assets in the Princess, Hays and Taber areas and in the first quarter produced an average of approximately 1,300 BOE per day, of which 72% was natural gas and 28% was crude oil and natural gas liquids. Volumes associated with the Seventh acquisition were only included in PrimeWest's first quarter results for the period of March 16 to March 31, 2004. The first quarter impact on PrimeWest's overall volumes was approximately 200 BOE/day. The assets acquired include approximately 39,000 net acres of undeveloped land, and a proprietary 3-D seismic inventory, both of which will provide future development opportunities for PrimeWest. In order to protect the transaction economics upon announcing the deal, PrimeWest hedged approximately 70% of the gas production at a price of Cdn $6.18 per thousand cubic feet from March 2004 through April 2005. In the near-term PrimeWest will be investing approximately $7 million in drilling, facilities, and waterflood opportunities that will significantly enhance both the production volumes and reserve recovery from the acquired assets. The acquisition costs were funded through PrimeWest's existing debt facility. Net proceeds of $134.9 million from an equity offering undertaken subsequent to quarter-end will reduce bank debt, including the debt incurred with the Seventh acquisition. Future development costs will also be funded through the debt facility. Based on current forecasts, PrimeWest expects the acquisition to be accretive to its unitholders during 2004 on both a cash flow and net asset value per unit basis. Financial Management PrimeWest strives to maintain a conservative debt position, to allow 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. PrimeWest continues to target a payout ratio between 70% and 90% of annual cash flow to increase the Trust's financial flexibility. The first quarter 2004 payout ratio was approximately 70%, and the retained cash flow was utilized primarily for debt repayment, and towards the Trust's capital spending program. PrimeWest's success in executing conservative financial management is demonstrated by our debt to cash flow level of 1.3 times at the end of the first quarter, less than our internal limit of 2.0 times and slightly higher than our level of 1.1 times for the same period the previous year. PrimeWest's dual listing on both the Toronto Stock Exchange (TSX) and New York Stock Exchange (NYSE) provide increased liquidity and a broadened 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 Plan (DRIP), Premium Distribution Plan (PREP), and Optional Trust Unit Purchase Plan (OTUPP), 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 implications associated with receiving a distribution. Corporate Governance PrimeWest remains committed to the highest 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 available on our website at http://www.primewestenergy.com/. PrimeWest actively monitors the corporate governance and disclosure environment to ensure compliance with current and future requirements. Subsequent to the end of the first quarter, PrimeWest announced the appointment of Mr. Peter Valentine to the Board of Directors, an additional independent and unrelated director with extensive experience in the finance field. 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 continues to expect 2004 production volumes to average approximately 30,000 BOE/day. Full year operating costs are expected to be approximately $6.75/BOE. PrimeWest expects to invest between $65 and $90 million in its capital development program, with the focus primarily in the core areas of Caroline, Valhalla, Brant/Farrow and Princess/Hays. For unitholders resident in Canada, PrimeWest anticipates that approximately 60% of 2004 distributions will be taxable and 40% will be deemed return of capital. The taxability of 2004 distributions for U.S. unitholders cannot be accurately estimated at this time, but will be confirmed after year end. For residents of the U.S., Canadian withholding tax of 15% applies to the distribution. In addition, the Canadian Federal Government announced a proposal on March 23, 2004 which would expand Canadian withholding tax on non- Canadian residents (15% for U.S. unitholders) by applying it to both the "taxable income" portion, as well as the return of capital portion of the distributions made after 2004. For more details on withholding tax, please visit our website at http://www.primewestenergy.com/. Cash Flow Reconciliation ($ millions) ------------------------------------------------------------ Fourth quarter 2003 cash flow from operations $ 43.2 Production volumes (3.8) Commodity prices 18.0 Net hedging change from prior year (2.5) Operating expenses 1.5 Royalties (2.2) Other 4.3 ------------------------------------------------------------ First quarter 2004 cash flow from operations $ 58.5 ------------------------------------------------------------ The above table includes non-GAAP measurements which may not be comparable to other companies. 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 (G&A) expenses. It is expected that these factors will impact cash flows in the future. Quarterly Performance ------------------------------------------------------ ($ millions, 2004 2003 2002 except per Trust ------------------------------------------------------ Unit amounts) Q1 Q4 Q3 Q2 Q1 Q4 Q3 Q2 Q1 ------------------------------------------------------------------------- Net Revenues 85.7 73.0 77.3 85.6 94.0 68.8 63.8 62.3 69.4 Net Income 20.1 (0.7) 7.4 61.6 22.4 (7.3) 8.2 (6.2) 6.0 Net Income Per Unit - Basic 0.40 (0.01) 0.16 1.35 0.53 (0.20) 0.24 (0.20) 0.20 Net Income Per Unit - Diluted 0.40 (0.01) 0.16 1.34 0.53 (0.20) 0.24 (0.20) 0.16 ------------------------------------------------------------------------- The above table highlights PrimeWest's performance for the first quarter ended 2004, and the preceding eight quarters through 2003 and 2002. Net revenues are primarily impacted by commodity prices, production volumes, and operating expenses. As a result, the first quarter 2004 net revenues were higher compared to the fourth quarter of 2003. As production volumes decline due to natural reservoir depletion, net revenues can also be impacted and trend accordingly. Net income and net income per unit are secondary measures for a royalty trust because net income includes both cash and non-cash items. The non-cash items such as depletion, depreciation and amortization (DD&A), future income taxes, foreign exchange, and unrealized gain or loss on derivatives can cause the net income to vary significantly. Capital Expenditures Three months ended -------------------------------------- Mar 31, Dec 31, Mar 31, ($ millions, except per BOE) 2004 2003 2003 ------------------------------------------------------------------------- Land & lease acquisitions $ 1.8 $ 2.1 $ 1.2 Geological and geophysical 1.7 4.4 0.6 Drilling and completions 18.8 17.2 15.0 Investment in facilities Equipping & tie-in 4.0 3.4 3.0 Compression & processing 2.0 0.5 1.7 Gas gathering 0.5 1.4 2.3 Production facilities 2.1 2.4 0.8 Capitalized G&A 0.4 0.3 0.5 ------------------------------------------------------------------------- Development capital $ 31.3 $ 31.7 $ 25.1 ------------------------------------------------------------------------- Corporate/property acquisitions 38.6 3.9 198.2 Dispositions (3.5) (1.5) (0.2) Head office equipment 0.2 - (0.1) ------------------------------------------------------------------------- Total $ 66.6 $ 34.1 $ 223.0 ------------------------------------------------------------------------- ------------------------------------------------------------------------- During the first quarter of 2004, PrimeWest's capital expenditures totaled $66.6 million, including the acquisition of Seventh, compared to the first quarter of 2003 spending of $246.4, which included the acquisition of two private Canadian oil and gas companies. Development capital of $31.3 million was higher than the first quarter 2003 development capital of $25.1 million. For many oil and gas companies, the first quarter winter months tend to be capital intensive periods with active drilling programs. Of the $31.3 million in development capital, $18.8 million or 60% was spent on drilling and completions, which contribute to new reserve additions and help offset natural production decline. Of the $9 million investments made in facilities, $4 million or 44% represents equipping and volume tie-ins, with the remainder invested in other activities that contribute to future production volumes. In the first quarter of 2004, PrimeWest's capital spending was focused primarily in the areas of Caroline, Brant/Farrow, and Boundary Lake where the Trust drilled 4, 6, and 4 new wells respectively. Gross wells drilled in the first quarter totaled 32, with a success rate of approximately 91%. Quarter over quarter, development capital spending in the first quarter of 2004 did not differ materially from the fourth quarter of 2003. The Seventh acquisition completed in 2004 contributed to the increase in total capital spending for the first quarter of 2004 relative to the previous quarter. Through acquisitions as well as development drilling, workovers, and recompletion activities, PrimeWest strives to offset the natural production decline, and add to reserves in an effort to sustain cash flows. 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 Canadian 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. PrimeWest currently has 15 primary assets, with no single asset producing greater than 20% of PrimeWest's total volumes. As a result of the Seventh acquisition, PrimeWest's 2004 capital spending program includes investment in the expanded Princess/Hays region of southeast Alberta. This is an example of the Trust's strategy to expand on existing areas or build new core areas within which we retain control of operations. Production Volumes Three months ended -------------------------------------- Mar 31, Dec 31, Mar 31, 2004 2003 2003 ------------------------------------------------------------------------- Natural gas (mmcf/day) 123.9 126.9 140.3 Crude oil (bbls/day) 7,864 8,189 8,142 Natural gas liquids (bbls/day) 2,696 2,779 3,030 ------------------------------------------------------------------------- Total (BOE/day) 31,202 32,111 34,554 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Gross Overriding Royalty volumes included above (BOE/day) 1,397 1,595 1,700 ------------------------------------------------------------------------- ------------------------------------------------------------------------- All production information is reported before the deduction of crown and freehold royalties. PrimeWest's production volumes in the first quarter 2004 were lower than the same period the prior year and the previous quarter, primarily due to natural production decline, partially offset by development volume additions throughout the first quarter of 2004. Production of approximately 300 BOE/day at Ells is expected to be shut-in as a result of an Alberta Energy and Utilities Board ruling regarding the gas over bitumen issue. With the operator, PrimeWest intends to seek compensation for any shut-in production. Production at PrimeWest's non-operated Whiskey Creek area was partially restricted during the first quarter of 2004, with further curtailments anticipated throughout 2004 due to third party facility capacity constraints. PrimeWest continues to expect full year 2004 production to average approximately 30,000 BOE/day. This estimate incorporates PrimeWest's expected natural decline rate, the production volume shut-ins described above, offset by production additions due to the capital development program and the acquired production from Seventh. Commodity Prices Three months ended -------------------------------------- Mar 31, Dec 31, Mar 31, Benchmark Prices 2004 2003 2003 ------------------------------------------------------------------------- Natural gas ($/mcf AECO) $ 6.61 $ 5.59 $ 7.92 Crude oil (U.S.$/bbl WTI) $ 35.17 $ 31.18 $ 33.86 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Average Realized Sales Prices Three months ended -------------------------------------- Mar 31, Dec 31, Mar 31, (Canadian Dollars) 2004 2003 2003 ------------------------------------------------------------------------- Natural gas ($/mcf)(1)(2) $ 6.57 $ 5.52 $ 6.92 Without hedging 6.62 5.50 7.84 Crude oil ($/bbl)(1) 34.93 31.27 38.33 Without hedging 39.44 33.43 43.65 Natural gas liquids ($/bbl) 38.54 34.49 40.77 ------------------------------------------------------------------------- Total Oil Equivalent(2) ($/BOE) $ 38.21 $ 32.78 $ 40.70 Without hedging $ 39.56 $ 33.25 $ 45.68 ------------------------------------------------------------------------- Realized hedging gain (loss) included in prices above ($/BOE) $ (1.35) $ (0.47) $ (4.98) ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Includes hedging gains/losses. (2) Excludes sulphur. Canadian commodity prices were generally lower in the first quarter 2004 than during the same period in 2003, with average realized selling prices per BOE decreasing by 6% in the first quarter 2004 compared to the same period in 2003. The realized selling price in Canadian dollars is 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. At March 31, 2003, the Canadian dollar was $0.6813 versus its U.S. counterpart, compared to $0.7626 at March 31, 2004, an increase of 12%. Compared to the fourth quarter 2003, average realized sales prices per BOE increased 17% in the first quarter 2004 due to higher average prices for crude oil, liquids and natural gas. 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. In the first quarter of 2004, PrimeWest had a $3.8 million hedging loss compared to a loss of $15.5 million for the same period in 2003. PrimeWest's hedging loss was $1.4 million in the fourth quarter 2003 as a result of lower average commodity prices in that quarter. The following table sets forth benchmark historical and estimated future commodity prices. Benchmark Commodity Prices Past Four Quarters (Actual) ------------------------------------------------------------------------- Q2 2003 Q3 2003 Q4 2003 Q1 2004 ------------------------------------------------------------------------- Natural gas NYMEX ($U.S./Mcf) 5.48 5.10 4.58 5.69 AECO ($Cdn/Mcf) 6.99 6.29 5.59 6.61 Crude oil WTI ($U.S./bbl) 28.91 30.20 31.18 35.17 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Benchmark Commodity Prices Next Four Quarters (Forward Markets)(1) ------------------------------------------------------------------------- Q2 2004 Q3 2004 Q4 2004 Q1 2005 ------------------------------------------------------------------------- Natural gas NYMEX ($U.S./Mcf) 5.76 6.02 6.17 6.32 AECO ($Cdn/Mcf) 6.61 6.88 7.14 7.34 Crude oil WTI ($U.S./bbl) 34.94 33.55 32.55 31.71 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) As at March 31, 2004 Sales Revenue Three months ended ------------------------------------------------------ Mar 31, % of Dec 31, % of Mar 31, % of Revenue ($ millions) 2004 total 2003 total 2003 total ------------------------------------------------------------------------- Natural gas(1) $ 74.0 68% $ 64.5 67% $ 87.4 69% Crude oil 25.0 23% 23.6 24% 28.1 22% Natural gas liquids 9.5 9% 8.8 9% 11.1 9% ------------------------------------------------------------------------- Total $ 108.5 100% $ 96.9 100% $ 126.6 100% ------------------------------------------------------------------------- ------------------------------------------------------------------------- Hedging (loss)/gains included above(2) $ (3.8) $ (1.4) $ (15.5) ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Excludes sulphur. (2) Net of amortized premiums. First quarter 2004 revenues were lower than the same period the previous year, primarily as a result of lower production volumes and a stronger Canadian dollar versus its U.S. counterpart. Since oil and gas prices are denominated in U.S. dollars, a strengthened Canadian dollar translates into lower Canadian revenue for producers. Revenues are 17% higher in the first quarter 2004 compared to the previous quarter due to the higher commodity price environment. 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 may be offset by development projects and any acquisition activity. Financial Derivatives 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 $33.3 million over the period from January 1, 2001 to March 31, 2004. Hedging is an important element in PrimeWest's financial management strategy. It is designed to reduce commodity price volatility, increase cash flow stability, and protect the economics of asset acquisitions. The hedging policy reflects a willingness to forfeit a portion of the pricing upside in return for protection against a significant downturn in prices. Approximate percentage of future anticipated production volumes hedged at March 31, 2004, net of anticipated royalties, reflecting full production declines with no offsetting additions: ----------------------------------------------------------- 2004 Q2 Q3 Q4 Q2-Q4 ------------------------------------------------------------------------- Crude Oil 65% 59% 55% 60% Natural Gas 53% 57% 28% 46% ------------------------------------------------------------------------- ------------------------------------------------------------------------- ----------------------------------------------------------- 2005 Q1 Q2 Q3 Q4 Full Year ------------------------------------------------------------------------- Crude Oil 33% 26% 18% 9% 21% Natural Gas 12% 0% 0% 0% 3% ------------------------------------------------------------------------- ------------------------------------------------------------------------- PrimeWest generally sells its oil and gas under short-term market-based contracts. Derivative financial instruments, options and swaps may be used to hedge the impact of oil and gas price fluctuations. A listing of these contracts in place at March 31, 2004 follows: Crude Oil ($U.S./bbl) ------------------------------------------------------------------------- Volume WTI Price Period (bbls/d) Type ($U.S./bbl) ------------------------------------------------------------------------- Apr - Jun 2004 1000 Swap 27.13 Apr - Jun 2004 500 Swap 28.64 Apr - Jun 2004 500 Swap 30.06 Apr - Jun 2004 500 Swap 32.04 Apr - Jun 2004 500 Costless Collar 22.00/26.12 Apr - Jun 2004 500 Costless Collar 24.00/30.50 Apr - Jun 2004 500 Costless Collar 25.00/28.07 Apr - Jun 2004 500 Costless Collar 26.00/32.07 Jul - Aug 2004 500 Swap 31.55 Jul - Sep 2004 500 Swap 26.07 Jul - Sep 2004 500 Swap 27.04 Jul - Sep 2004 500 Swap 28.51 Jul - Sep 2004 500 Swap 30.23 Jul - Sep 2004 500 Costless Collar 24.00/30.75 Jul - Sep 2004 500 Costless Collar 25.00/28.30 Jul - Sep 2004 500 Costless Collar 26.00/32.05 Oct - Dec 2004 500 Swap 26.00 Oct - Dec 2004 500 Swap 27.03 Oct - Dec 2004 500 Swap 28.53 Oct - Dec 2004 500 Swap 30.10 Oct - Dec 2004 500 Costless Collar 24.00/30.00 Oct - Dec 2004 500 Costless Collar 25.00/28.30 Oct - Dec 2004 500 Costless Collar 26.00/32.72 Jan - Mar 2005 500 Swap 27.25 Jan - Mar 2005 500 Swap 28.60 Jan - Mar 2005 500 Swap 30.00 Jan - Mar 2005 500 Costless Collar 28.00/34.35 Apr - Jun 2005 500 Swap 27.07 Apr - Jun 2005 500 Swap 28.50 Apr - Jun 2005 500 Swap 30.00 Jul - Sep 2005 500 Swap 27.05 Jul - Sep 2005 500 Swap 28.50 Oct - Dec 2005 500 Swap 27.18 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Natural Gas (Cdn$/mcf) ------------------------------------------------------------------------- Volume AECO Price Period (mmcf/d) Type (Cdn$/mcf) ------------------------------------------------------------------------- Jan 2004 - Oct 2004 9.5 3 Way 3.17/4.22/6.09 Jan 2004 - Dec 2004 1.0 Swap 6.02 Apr 2004 - Oct 2004 4.7 Swap 5.45 Apr 2004 - Oct 2004 4.7 Swap 6.02 Apr 2004 - Oct 2004 4.7 Swap 6.06 Apr 2004 - Oct 2004 4.7 Costless Collar 5.01/6.06 Apr 2004 - Oct 2004 4.7 Costless Collar 5.28/7.39 Apr 2004 - Oct 2004 4.7 Swap 6.25 Apr 2004 - Oct 2004 4.7 Swap 6.20 Nov 2004 - Mar 2005 4.7 Costless Collar 5.80/7.91 Nov 2004 - Mar 2005 4.7 Swap 6.71 ------------------------------------------------------------------------- ------------------------------------------------------------------------- A 3-way option is like a traditional collar, except that PrimeWest has resold the put at a lower price. Utilizing the first 3-way natural gas contract above as an example, PrimeWest has sold a call at $6.09, purchased a put at $4.22, and resold the put at $3.17. Should the market price drop below $4.22 PrimeWest will receive $4.22 until the price is less than $3.17, at which time PrimeWest would then receive market price plus $1.05. However, should market prices rise above $6.09, PrimeWest would receive a maximum of $6.09. Should the market price remain between $4.22 and $6.09, PrimeWest would receive the market price. Natural Gas Basis Differential ------------------------------------------------------------------------- Volume Basis Price Period (mmcf/day) Type ($U.S./mcf) ------------------------------------------------------------------------- Apr - Oct 2004 5 Basis Swap $0.71 ------------------------------------------------------------------------- ------------------------------------------------------------------------- The AECO basis is the difference between the NYMEX gas price in $U.S. per mcf and the AECO price in $U.S. per mcf. Using the basis swap above as an example, PrimeWest has fixed this price difference between the two markets at $U.S. 0.71 per mcf from April 2004 through October 2004. If the NYMEX price for the period turned out to be $U.S. 5.00 per mcf, PrimeWest would receive an AECO equivalent price of $U.S. 4.29 per mcf. Electrical Power ------------------------------------------------------------------------- Power Period Amount (MW) Type Price ($/MW-hr) ------------------------------------------------------------------------- Q2 2004 7.5 Fixed Price Swap 40.25 Q3 2004 5 Fixed Price Swap 46.50 Q4 2004 5 Fixed Price Swap 44.00 Calendar 2004 5 Fixed Price Swap 45.65 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Interest Rate Risk Management ------------------------------------------------------------------------- Term Notional amount ($ millions) Fixed BA rate (%) ------------------------------------------------------------------------- May 24/98 - May 25/04 $25 6.48 Nov 26/01 - May 26/04 $25 3.85 ------------------------------------------------------------------------- ------------------------------------------------------------------------- CICA Accounting Guideline 13 (AcG-13), "Hedging Relationships", became effective for fiscal years beginning on or after July 1, 2003. AcG-13 addresses the identification, designation, documentation and effectiveness of hedging transactions for the purposes of applying hedge accounting. It also establishes conditions for applying or discontinuing hedge accounting. Under the new guideline, hedging transactions must be documented and it must be demonstrated that the hedges are sufficiently effective in order to continue accrual accounting for positions hedged with derivatives. PrimeWest is not applying hedge accounting to its hedging relationships. As of January 1, 2004, the Trust recorded $6.0 million for the mark-to-market value of the outstanding hedges as a derivative liability and a $6.0 million deferred derivative loss, to be realized upon settlement of the corresponding derivative instrument. The deferred loss at January 1, 2004 was comprised of a $3.9 million loss for crude oil, $2.1 million loss for natural gas, $0.6 million loss for interest rate swaps and a gain of $0.6 million for electrical power. As of March 31, 2004, PrimeWest had an outstanding deferred derivative loss of $3.4 million, comprised of $2.3 million for crude oil, $1.5 million for natural gas, $0.1 million for interest rate swaps, and a $0.5 million gain for electrical power. The deferred loss will continue to be amortized to earnings upon settlement of the corresponding hedges. All hedging contracts entered into by PrimeWest subsequent to January 1, 2004 have been recognized as either a deferred derivative asset or liability on the balance sheet with an unrealized hedging gain or loss being recorded on the income statement. The unrealized hedging loss at March 31, 2004 is $12.3 million. This is comprised of a $6.3 million loss for crude oil, $6.0 million loss for natural gas, $0.1 million loss for interest rate swaps and a $0.1 million gain for electrical power. The mark-to-market valuation of hedges in place at March 31, 2004 was a $15.9 million loss consisting of an $8.6 million loss in crude oil, $7.5 million loss in natural gas, $0.7 million gain on electrical power and a $0.4 million loss on interest rate swaps. In the first quarter of 2004, the financial impact of contracts settling in the quarter was a $4.3 million loss consisting of a $3.2 million loss in crude oil, $0.6 million loss in natural gas, $0.1 million loss on electrical power and an increase of $0.4 million in interest paid. Royalties (Net of ARTC) Royalties are paid by PrimeWest to the owners of mineral rights with whom PrimeWest holds leases. PrimeWest has mineral leases with the Crown (Provincial and Federal Governments), freeholders (individuals or other companies) and other operators. ARTC is the Alberta Royalty Tax Credit, a tax rebate provided by the Alberta government to producers that paid eligible Crown royalties in the year. Three months ended ------------------------------------ Mar 31, Dec 31, Mar 31, ($ millions, except per BOE) 2004 2003 2003 ------------------------------------------------------------------------- Royalty expense (net of ARTC) $ 23.3 $ 21.1 $ 32.7 Per BOE $ 8.22 $ 7.13 $ 10.50 Royalties as % of sales revenues With hedge loss 21.5% 21.8% 25.8% Excluding hedge loss 20.8% 21.5% 23.0% ------------------------------------------------------------------------- ------------------------------------------------------------------------- Royalty expense in the first quarter of 2004 is lower than the same period the previous year due to lower crude oil and natural gas revenues year over year. Sales revenues in the first quarter of 2004 included higher Gross Over Riding Royalties compared to sales revenues in the fourth quarter of 2003, resulting in lower royalties as a percentage of sales revenue excluding hedges in the first quarter. Royalty rates are based on commodity prices so future changes to prices will be accompanied by changes in royalty expense. Operating Expenses Three months ended ------------------------------------ Mar 31, Dec 31, Mar 31, ($ millions, except per BOE) 2004 2003 2003 ------------------------------------------------------------------------- Operating expense ($ millions) $ 19.7 $ 21.2 $ 20.6 Per BOE $ 6.92 $ 7.18 $ 6.63 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Compared to both the first quarter of 2003 and the previous quarter, PrimeWest's total operating expenses for the first quarter 2004 are lower by approximately 4% and 7%, respectively. However, on a per BOE basis, operating costs are 4% higher in the first quarter 2004 compared to the same quarter the previous year, but 4% lower compared to the fourth quarter. Higher operating expense on a per BOE basis in the first quarter 2004 is primarily due to lower production volumes in 2004 than in 2003. Operating Expenses Outlook Operating costs for the year are expected to be higher than in 2003, and PrimeWest continues to target 2004 operating expenses at approximately $6.75/BOE. Operating Margin Three months ended ------------------------------------ Mar 31, Dec 31, Mar 31, ($/BOE) 2004 2003 2003 ------------------------------------------------------------------------- Sales price and other revenue(1) $ 38.42 $ 31.85 $ 40.74 Royalties 8.22 7.13 10.50 Operating expenses 6.92 7.18 6.63 ------------------------------------------------------------------------- Operating margin $ 23.28 $ 17.54 $ 23.61 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Includes hedging and sulphur Operating margin decreased 1% during the first quarter 2004 compared to the same quarter in 2003. This is primarily due to lower sales prices and higher operating expenses, offset by lower royalties. Operating margin is an important measure of our business because it gives an indication of the amount of cash flow PrimeWest realizes per barrel of oil equivalent that is produced, before head office expenses and financing charges. Compared to the previous quarter, operating margin in the first quarter 2004 increased 33%, primarily attributable to higher sales revenue. Based on PrimeWest's commodity price outlook, the Canadian/U.S. dollar exchange rate, operating expense expectations and hedge positions, margins are expected to be lower in 2004 than 2003. 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 Three months ended ------------------------------------ Mar 31, Dec 31, Mar 31, ($ millions, except per BOE) 2004 2003 2003 ------------------------------------------------------------------------- Cash G&A expense ($ millions) $ 4.2 $ 4.1 $ 3.8 Per BOE $ 1.49 $ 1.37 $ 1.23 Non-cash G&A expense ($ millions) $ 0.4 $ 8.5 $ 0.4 Per BOE $ 0.15 $ 2.88 $ 0.12 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Cash G&A expense per BOE increased 21% in the first quarter of 2004 to $1.49/BOE compared to first quarter 2003 levels of $1.23/BOE, primarily due to lower overall sales volumes in the first quarter 2004 versus the first quarter of 2003. In the first quarter of 2004, insurance expense as well as employee salaries and benefits were higher than in 2003. Compared to the same period in 2003, the first quarter 2004 non-cash G&A expense per BOE increased slightly to $0.15/BOE from $0.12/BOE, attributable to lower production volumes year to date in 2004. Quarter over quarter, total cash G&A expense in the first quarter 2004 increased marginally, while cash G&A per BOE increased 9% due to lower production volumes. PrimeWest's total and per BOE non-cash G&A expense decreased approximately 95% from the fourth quarter 2003 due to a lower average Unit Appreciation Rights (UARs) value in the first quarter 2004 under PrimeWest's Long Term Incentive Plan (LTIP). Non-cash G&A expense consists mainly of the change in the value of the 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 LTIP is to align employee and unitholder interests. 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 employees who hold UARs until the unitholders have first achieved a 5% total annual return from the time of grant. Expenses related to the LTIP 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. G&A Expense Outlook Cash G&A expenses in 2004 are expected to increase over 2003 levels and are expected to be approximately $1.25 per BOE for the year. Interest Expense Three months ended ------------------------------------ Mar 31, Dec 31, Mar 31, ($ millions, except per Trust Unit) 2004 2003 2003 ------------------------------------------------------------------------- Interest expense $ 3.2 $ 4.1 $ 3.6 Period end net debt level $ 305.7 $ 255.9 $ 281.5 Debt per Trust Unit $ 5.99 $ 5.07 $ 6.15 ------------------------------------------------------------------------- Average cost of debt 4.4% 4.7% 4.8% ------------------------------------------------------------------------- ------------------------------------------------------------------------- Interest expense, representing interest on bank debt and private placement debt, decreased in the first quarter 2004 to $3.2 million from $3.6 million in the same quarter 2003, and from $4.1 million in the previous quarter due to lower average interest rates in 2004 compared to 2003. In May of 2003, PrimeWest closed a private placement debt financing of $U.S. 125 million at a U.S. fixed coupon rate of 4.19%, successfully diversifying its debt. The actual Canadian interest expense will fluctuate with any changes in the Canadian/U.S. foreign exchange rates. Canadian interest rates are expected to be lower through 2004 compared to 2003, as the Bank of Canada again reduced its overnight rate by 25 basis points on April 13, 2004. Foreign Exchange Loss The foreign exchange loss of $1.7 million in the first quarter 2004 results from the translation of the U.S. dollar denominated secured notes and related interest payable in Canadian dollars. Depletion, Depreciation and Amortization Three months ended ------------------------------------ Mar 31, Dec 31, Mar 31, ($ millions, except per BOE) 2004 2003 2003 ------------------------------------------------------------------------- Depletion, depreciation and amortization $ 41.7 $ 53.9 $ 52.0 ------------------------------------------------------------------------- $/BOE $ 14.68 $ 18.26 $ 16.72 ------------------------------------------------------------------------- ------------------------------------------------------------------------- The first quarter 2004 DD&A rate of $14.68/BOE is lower than the 2003 first quarter rate of $16.72/BOE and the fourth quarter 2003 rate of $18.26 due to the January 1, 2004 ceiling test write down of $309 million. Ceiling Test Effective January 1, 2004, PrimeWest has adopted CICA Accounting Guideline 16 (AcG-16), "Oil and Gas Accounting - Full Cost". This new standard replaces the CICA Accounting Guideline 5 (AcG-5), "Full Cost Accounting in the Oil and Gas Industry". Under AcG-5, the cost recovery test is calculated based on undiscounted future net revenues for proved reserves, less general and administrative expenses, site restoration, future financing costs and applicable income taxes. The aggregate result is limited to capitalized costs, less accumulated depletion and site restoration, the lower of cost and market value of unproved land and future income taxes. The cost recovery test is based on costs and commodity prices existing at the balance sheet date. AcG-16 impacts the application of the cost centre impairment test (ceiling test). The guideline is effective for fiscal years beginning on or after January 1, 2004. The cost impairment test is now a two stage process which is to be performed at least annually. The first stage of the test determines if the cost pool is impaired. An impairment loss exists when the carrying amount of an asset is not recoverable and exceeds its fair value. The carrying amount is not recoverable if it exceeds the sum of the undiscounted cash flows from Proved reserves plus unproved costs using management's best estimate of future prices. The second stage determines the amount of the impairment loss to be recorded. The impairment is measured as the amount by which the carrying amount of capitalized assets exceeds the future discounted cash flows from Proved plus Probable reserves. The discount rate used is the risk free rate. Performing this test at January 1, 2004, using consultant's average prices as at January 1, 2004 of AECO $5.90 per mcf for natural gas, $U.S. 29.21 per barrel WTI for crude oil results in a before tax impairment of $308.9 million, and an after tax impairment of $233.2 million. The write down was booked to accumulated income 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. The fund is used to pay for such costs as they are incurred. The 2004 contribution rate for the fund is unchanged from 2003 at $0.50/BOE, which is expected to be sufficient to meet expenditure requirements for the future. The reclamation and abandonment costs in the first quarter of 2004 were $0.9 million, compared to $0.1 million for the same period in 2003. Asset Retirement Obligation In the first quarter of 2004, PrimeWest adopted the new CICA Handbook section 3110, "Asset Retirement Obligations". This standard focuses on the recognition and measurement of liabilities related to legal obligations associated with the retirement of property, plant and equipment. Under this standard, these obligations are initially measured at fair value and subsequently adjusted for the accretion of discount and any changes in the underlying cash flows. The asset retirement cost is to be capitalized to the related asset and amortized into earnings over time. The adoption of CICA Handbook section 3110 allows for the cumulative effect of the change in accounting policy to be booked to accumulated income with the restatement of prior period comparatives. At January 1, 2004, this resulted in an increase to the asset retirement obligation of $19.7 million (2003 - $15.3 million), an increase to property, plant and equipment (PP&E) of $10.6 million (2003 - $9.0 million), a $5.6 million (2003 - $0.04 million) increase to accumulated income, a decrease of site restoration provision of $17.8 million (2003 - $6.2 million) and an increase to the future tax liability of $3.1 million (2003 - $(0.03) million). Income and Capital Taxes Three months ended ------------------------------------ Mar 31, Dec 31, Mar 31, ($ millions) 2004 2003 2003 ------------------------------------------------------------------------- Income and capital taxes $ 0.3 $ 0.3 $ 1.2 Future income taxes recovery (18.2) (11.8) (10.4) ------------------------------------------------------------------------- $ (17.9) $ (11.5) $ (9.2) ------------------------------------------------------------------------- ------------------------------------------------------------------------- During the first quarter of 2004, the Alberta Government substantially enacted a tax rate reduction of 1% reducing the rate from 12.5% to 11.5% effective April 1, 2004. This resulted in an additional tax recovery during the quarter of approximately $9.0 million. During 2003, the Canadian Government enacted Federal income tax changes for the oil and gas resource sector. The Federal income tax changes effectively reduced the statutory tax rates for current and future periods. Specifically, the 100% deductibility of the resource allowance will be completely phased out by the year 2007. During the same time frame, Crown charges will become 100% deductible and resource tax rates will decline from the current 27% to 21%. Net Income Three months ended ------------------------------------ Mar 31, Dec 31, Mar 31, ($ millions) 2004 2003 2003 ------------------------------------------------------------------------- Net income (loss) $ 20.1 $ 0.7 $ 22.1 ------------------------------------------------------------------------- ------------------------------------------------------------------------- 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 for an energy trust to continue paying its distributions 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 DD&A and future taxes. Net income for the first quarter of 2004 was impacted by lower sales revenue as a result of lower commodity prices and production volumes compared to the first quarter of 2003. Future income tax recoveries contributed approximately $10.4 million to net income in 2003, while PrimeWest realized $1.7 million in foreign exchange losses and future income tax recoveries of $18.2 million in the same period in 2004. Compared to the previous quarter, the first quarter 2004 net income was higher due to higher commodity prices, offset by lower production volumes, and higher future income tax recoveries. Liquidity & Capital Resources Long Term Debt Three months ended ------------------------------------ Mar 31, Dec 31, Mar 31, ($ millions) 2004 2003 2003 ------------------------------------------------------------------------- Long-term debt $ 299.9 $ 250.1 $ 300.0 Deficit/(working capital) 5.8 5.8 (18.5) ------------------------------------------------------------------------- Net debt $ 305.7 $ 255.9 $ 281.5 Market value of Trust Units and exchangeable shares outstanding(1) 1,355.7 1,380.7 1,154.0 ------------------------------------------------------------------------- Total capitalization $ 1,661.4 $ 1,636.6 $ 1,435.5 ------------------------------------------------------------------------- Net debt as a % of total capitalization 18% 16% 19% ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Based on March 31, 2004 Trust Unit closing price of $26.65 and exchange ratio of 0.45885:1 Long term debt is comprised of bank credit facilities and senior secured notes for $136.0 million and $163.9 million, respectively. PrimeWest had a borrowing base of $390 million at March 31, 2004. The bank credit facilities consist of a revolving term loan of $188 million and an operating facility of $25 million. In addition to amounts outstanding under the facility, at the end of the first quarter, PrimeWest has outstanding letters of credit in the amount of $4.8 million, compared to $4.5 million in the same period in 2003. The credit facility revolves until June 30, 2004, by which time the lenders will have conducted their annual borrowing base review. PrimeWest's first quarter 2004 net debt totaled $305.7 million, 9% higher than the same period in 2003 and 20% higher than the previous quarter. The year over year and quarter over quarter increase is primarily due to the debt incurred with the acquisition of Seventh in the first quarter 2004. 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 total capitalization. For the first quarter of 2004, PrimeWest's debt to annualized cash flow is approximately 1.3 times, and 18% of our total capitalization. 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's lower payout ratio of 70% for the first quarter 2004 versus 77% for the first quarter 2003 enabled the Trust to use internally generated cash to invest in development opportunities and pay down bank debt. PrimeWest has no material capital commitments at the end of the first quarter, 2004. Unitholders' Equity At the end of the first quarter 2004, the Trust had 50,223,123 Trust Units outstanding, compared to 43,668,118 Trust Units outstanding at the end of the first quarter 2003. In addition, PrimeWest had 1,407,357 (2003 - 4,494,475) exchangeable shares outstanding which are exchangeable into a total of 645,767 (2003 - 1,762,868) Trust Units using the March 15, 2004 exchange ratio of 0.45885:1 (2003 - 0.39223:1). For Canadian resident unitholders, PrimeWest offers a Distribution Reinvestment Plan (DRIP), and components of it include the Optional Trust Unit Purchase Plan (OTUPP) and the Premium Distribution Plan (PREP). The DRIP gives Canadian unitholders the chance to reinvest their monthly distributions at a 5% discount to the volume weighted average market price, while the OTUPP gives Canadian unitholders an opportunity to purchase additional Trust Units directly from PrimeWest at the same 5% discount to the volume weighted average market price. 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 DRIP and PREP components are mutually exclusive, and participation in the OTUPP requires enrollment in either the DRIP or PREP. For further details on these plans or to obtain the enrolment forms, please contact PrimeWest's Plan Agent, Computershare Trust Company of Canada at 1-800-564-6253, or visit PrimeWest's website at http://www.primewestenergy.com/. These plan components benefit unitholders by offering alternatives to maximize their investment in PrimeWest while providing the Trust with an inexpensive method to raise additional capital. Proceeds from these plans are used for debt reduction of PrimeWest's credit facility and to help fund ongoing capital development programs. Exchangeable Shares Exchangeable shares were issued in connection with both the Venator Petroleum Company Ltd. acquisition in April 2000 and the Cypress Energy Inc. acquisition in March 2001. These shares were issued to provide a tax deferred rollover of the adjusted cost base from the shares being exchanged to the exchangeable shares of PrimeWest. A tax deferral is not permitted by Canadian tax law when shares are exchanged for Trust Units. The exchangeable shares do not receive cash distributions. In lieu of receiving cash distributions, the number of Trust Units that the exchangeable shareholder will receive upon exchange increases each month based on the distribution amount divided by the market price of the Trust Units on the 15th day of each month. At March 31, 2004, there were 1,407,357 exchangeable shares outstanding. The exchange ratio on these shares was 0.45885:1 Trust Units for each exchangeable share as at the end of the first quarter. For purposes of calculating basic per Trust Unit amounts, these exchangeable shares have been assumed to be exchanged into Trust Units at the current exchange ratio. Cash Distributions Cash distributions to unitholders are at the discretion of the Board of Directors and can fluctuate depending on the cash flow generated from operations. As discussed previously, 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 environment. In order to increase PrimeWest's financial flexibility, the Board of Directors maintains a longer term target distribution payout ratio of approximately 70-90% of cash flow from operations. In the first quarter of 2004, cash distributions totaled $41.1 million, or $0.82 per Trust Unit representing a payout ratio of 70%, compared to $49.8 million, or $1.20 per Trust Unit (77% payout ratio) for the same period in 2003. In the fourth quarter of 2003 cash distributions totaled $46.3 million, or $0.96 per Trust Unit representing a payout ratio of approximately 107% in that quarter. Distribution payments to U.S. unitholders are subject to 15% Canadian withholding tax, which is deducted from the distribution amount prior to deposit into accounts. For Trust Units held in tax sheltered accounts, withholding tax should not apply. Contractual Obligations PrimeWest enters into many contract obligations as part of conducting day- to-day business. Material contract obligations that PrimeWest has currently in place are lease rental commitments that run from 2004 through 2009 and require annual payments after deducting sub-lease income of $1.2 million in 2004, $1.1 million in 2005 and 2006, and $2.4 million in 2007 through 2009, the remaining term of the lease. In addition, PrimeWest also has a pipeline transportation commitment that runs to October 31, 2007 and has minimum annual payment requirements of $U.S. 2.1 million. As part of PrimeWest's internalization transaction (see Note 11 in the Consolidated Financial Statements of the 2003 Annual Report), PrimeWest agreed to pay $3.5 million in exchangeable shares pursuant to a special employee retention plan. One quarter of the exchangeable shares will be issuable to the senior managers of PrimeWest on each of the second, third, fourth and fifth anniversary of transaction closing, November 6, 2002. As at March 31, 2004 $0.6 million has been accrued in non-cash general and administrative expenses related to the special employee retention plan. As at March 31, 2004 Payments due by period ($ millions) ------------------------------------------------------------------------- Less than 1-3 4-5 More than Total 1 year years years 5 years ----------------------------------------------- Long-term debt obligations $299.9 136.0 41.0 82.0 40.9 Lease rental obligations $5.9 1.3 3.5 1.1 - Pipeline transportation obligations $9.6 2.7 5.4 1.5 - Derivative liabilities $15.9 13.9 2.0 - - ------------------------------------------------------------------------- Total contractual obligations $331.3 153.9 51.9 84.6 40.9 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Critical Accounting Estimates PrimeWest's financial statements have been prepared in accordance with generally accepted accounting principles. Certain accounting policies require that management make appropriate decisions with respect to the formulation of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. The following discussion reviews such accounting policies and is included in Management's Discussion and Analysis to aid the reader in assessing the critical accounting policies and practices of the Trust and the likelihood of materially different results being reported. PrimeWest's management reviews its estimates regularly, but new information and changed circumstances may result in actual results or changes to estimated amounts that differ materially from current estimates. The following assessment of significant accounting policies is not meant to be exhaustive. The Trust may realize different results from the application of new accounting standards proposed and/or implemented, from time to time, by various rule-making bodies. Proved and Probable Oil and Gas Reserves Proved oil and gas reserves, as defined by the Canadian Securities Administrators' National Instrument 51-101 (NI 51-101), are the estimated quantities of crude oil, natural gas liquids, including condensate, and natural gas that geological and engineering data demonstrate with reasonable certainty can be recovered in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Proved reserves are those reserves that can be estimated with a high degree of certainty to be recoverable (i.e. it is likely that the actual remaining quantities recovered will exceed the estimated proved reserves). In accordance with this definition, the level of certainty targeted by the reporting company should result in at least a 90% probability that the quantities actually recovered will equal or exceed the estimated proved reserves. For probable reserves, which are by definition less certain to be recovered than proved reserves, NI 51-101 states that it must be equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves. With respect to the consideration of certainty, in order to report reserves as proved plus probable, the level of certainty targeted by the reporting company should result in at least a 50% probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus probable reserves. The oil and gas reserve estimates are made using all available geological and reservoir data as well as historical production data. Estimates are reviewed and revised as appropriate. Revisions occur as a result of changes in prices, costs, fiscal regimes, reservoir performance or a change in PrimeWest's plans. The effect of changes in proved oil and gas reserves on the financial results and position of PrimeWest is described under the heading "Full Cost Accounting for Oil and Gas Activities". Full Cost Accounting For Oil and Gas Activities PrimeWest has adopted CICA Accounting Guideline 16 (AcG-16), "Oil and Gas Accounting - Full Costs". The new guideline modifies how the ceiling test is performed and requires cost centers be tested for recoverability using undiscounted future cash flows from proved reserves which are determined by using forward indexed prices. When the carrying amount of a cost center is not recoverable, the cost center would be written down to its fair value. Fair value is estimated using accepted present value techniques which incorporate risks and other uncertainties when determining expected cash flows. Depletion Expense ----------------- PrimeWest uses the full cost method of accounting for exploration and development activities. In accordance with this method of accounting, all costs associated with exploration and development are capitalized whether successful or not. The aggregate of net capitalized costs and estimated future development costs less estimated salvage values is amortized using the unit of production method based on estimated proved oil and gas reserves.An increase in estimated proved oil and gas reserves would result in a corresponding reduction in depletion expense. A decrease in estimated future development costs would result in a corresponding reduction in depletion expense. Fair Value of Derivative Instruments As part of its financial management strategy, PrimeWest utilizes financial derivatives to manage market risk. The purpose of the hedge is to provide an element of stability to PrimeWest's cash flow in a volatile commodity price environment. Effective January 1, 2004 PrimeWest adopted CICA Accounting Guideline 13, "Hedging Relationships" ("AcG-13"). The estimation of the fair value of certain hedging derivatives requires considerable judgment. The estimation of the fair value of commodity price hedges requires sophisticated financial models that incorporate forward price and volatility data and, which when compared with PrimeWest's open hedging contracts, produce cash inflow or outflow variances over the contract period. The estimate of fair value for interest rate and foreign currency hedges is determined primarily through quotes from financial institutions. Asset Retirement Obligations Effective January 1, 2004 PrimeWest changed its accounting policy with respect to accounting for asset retirement obligations. CICA section 3110 requires the fair value of asset retirement obligations to be recorded when they are incurred rather than merely accumulated or accrued over the useful life of the respective asset. PrimeWest, under the current policy, is required to provide for future removal and site restoration costs. PrimeWest must estimate these costs in accordance with existing laws, contracts or other policies. These estimated costs are charged to earnings and the appropriate liability account over the expected service life of the asset. When the future removal and site restoration costs cannot be reasonably determined, a contingent liability may exist. Contingent liabilities are charged to earnings when management is able to determine the amount and the likelihood of the future obligation. Legal, Environmental Remediation and Other Contingent Matters The Trust is required to both determine whether a loss is probable based on judgment and interpretation of laws and regulations and whether that loss can reasonably be estimated. When the loss is determined, it is charged to earnings. PrimeWest's management must continually monitor known and potential contingent matters and make appropriate provisions by charges to earnings when warranted by circumstance. Income Tax Accounting The determination of the Trust's income and other tax liabilities requires interpretation of complex laws and regulations. All tax filings are subject to audit and potential reassessment after the lapse of considerable time. Accordingly, the actual income tax liability may differ significantly from that estimated and recorded by management. Business Combinations Since inception, PrimeWest has grown considerably through combining with other businesses. PrimeWest acquired Seventh Energy Ltd in the first quarter of 2004. This transaction was accounted for using what is now the only accounting method available, the purchase method. Under the purchase method, the acquiring company includes the fair value of the assets of the acquired entity on its balance sheet. The determination of fair value necessarily involves many assumptions. The valuation of oil and gas properties primarily involves placing a value on the oil and gas reserves. The valuation of oil and gas reserves entails the process described above under the caption "Proved and Probable Oil and Gas Reserves" but also incorporates the use of economic forecasts that estimate future changes in prices and costs. This methodology is also used to value unproved oil and gas reserves. The valuation of these reserves, by their nature, is less certain than the valuation of proved reserves. Goodwill The process of accounting for the purchase of a company, described above, results in recognizing the fair value of the acquired company's assets on the balance sheet of the acquiring company. Any excess of the purchase price over fair value is recorded as goodwill. Since goodwill results from the culmination of a process that is inherently imprecise, the determination of goodwill is also imprecise. In accordance with the recent issuance of CICA section 3062, "Goodwill and Other Intangible Assets", goodwill is no longer amortized but assessed periodically for impairment. The process of assessing goodwill for impairment necessarily requires PrimeWest to determine the fair value of its assets and liabilities. Such a process involves considerable judgment. 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. 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. 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 counter-parties and limiting exposure to each counter-party. In 2003, approximately 25% of natural gas production was sold to aggregators and 75% into the Alberta short-term or export long-term markets, and for 2004 we do not anticipate any material change to this breakdown. 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 of 2004, PrimeWest lost $3.8 million from commodity hedges, but has added $33.3 million to revenue from its hedging program from January 1, 2001 to the end of the first quarter of 2004. 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: Production ---------- Risk associated with the production of oil and gas - includes well operations, processing and the physical delivery of commodities to market. We mitigate by: Performing regular and proactive protective well, facility and pipeline maintenance supported by telemetry, physical inspection and diagnostic tools. Commodity Price --------------- Fluctuations in natural gas, crude oil and natural gas liquid prices We mitigate by: Hedging. See "Financial Derivatives" section of this press release. Transportation -------------- Market risk related to the availability of transportation to market and potential disruption in delivery systems. We mitigate by: Diversifying the transportation systems on which we rely to get our product to market. Natural decline --------------- Development risk associated with capital enhancement activities undertaken - the risk that capital spending on activities such as drilling, well completions, well workovers and other capital activities will not result in reserve additions or in quantities sufficient to replace annual production declines. We mitigate by: Diversifying our capital spending program over a large number of projects so that significant capital is not risked on any one activity. We also have a highly skilled technical team of geologists, geophysicists and engineers working to apply the latest technology in planning and executing capital programs. Capital is spent only after strict economic criteria for production and reserve additions are assessed. Acquisitions ------------ Acquisition risk associated with acquiring producing properties at low cost to renew our inventory of assets. We mitigate by: Continually scanning the marketplace for opportunities to acquire assets. Our technical acquisition specialists evaluate potential corporate or property acquisitions and identify areas for value enhancement through operational efficiencies or capital investment. All prospects are subjected to rigorous economic review against established acquisition and economic hurdle rates. In some cases we may also hedge commodity prices to protect the acquisition economics in the near term period. Reserves -------- Reserve risk in respect of the quantity and quality of recoverable reserves. We mitigate by: Contracting our reserves evaluation to a reputable third party consultant, Gilbert Lausten Jung (GLJ). The work and independence of GLJ is reviewed by the Audit and Reserves Committee of the Board of Directors of PrimeWest. Our strategy is to invest in mature, longer life properties having a higher proved producing component 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 risks associated with oil and gas properties and facilities. We mitigate by: Establishing and adhering to strict guidelines for EH&S including training, proper reporting of incidents, supervision and awareness. PrimeWest has active community involvement in field locations including regular meetings with stakeholders in the area. PrimeWest carries adequate insurance to cover property losses, liability and business interruption. These risks are reviewed regularly by the Corporate Governance and Nominating Committee of the Board, which acts as PrimeWest's Environmental, Health and Safety Committee. Regulation, Tax and Royalties ----------------------------- Changes in government regulations including reporting requirements, income tax laws, operating practices, environmental protection requirements and royalty rates. We mitigate by: Keeping informed of proposed changes in regulations and laws to properly respond to and plan for the effects that these changes may have on our operations. Liability to unitholders ------------------------ There is no statutory protection for unitholders from liabilities of the Trust. We mitigate by: Limiting the business of the Trust to the right to receive the net cash flow of PrimeWest Energy Inc. and its subsidiaries. All of the oil and gas business operations of PrimeWest are conducted by PrimeWest Energy Inc. and its subsidiaries. PrimeWest Energy Inc. has a vigorous EH&S program as well as significant insurance protection. First Quarter 2004 Conference Call and Webcast PrimeWest will be conducting a conference call and Web cast for interested analysts, brokers, investors and media representatives about its first quarter 2004 results at 9:00 a.m. Mountain time (11:00 a.m. Eastern time) on April 28th, 2004. Callers may dial 1-800-814-4857 a few minutes prior to start and request the PrimeWest conference call. The call also will be available for replay by dialing 1-877-289-8525, and entering pass code 21043127 followed by the pound (No.) key. Webcast listeners are invited to go to: http://www.newswire.ca/en/webcast/viewEvent.cgi?eventID(equal sign)759660 for the live Web cast and/or replay or access the Web cast at the PrimeWest website, http://www.primewestenergy.com/. Additional Information Additional information pertaining to PrimeWest, including the Trust's most recently filed Annual Report and Annual Information Form, is available on SEDAR at http://www.sedar.com/ and on the PrimeWest website at http://www.primewestenergy.com/. PrimeWest welcomes questions from unitholders and potential investors; call Investor Relations at 403-234-6600 or toll-free in Canada and the U.S. at 1-877-968-7878; or visit us at our website, http://www.primewestenergy.com/. We make every effort to respond to queries as quickly as possible, but during periods of heavy call volume, our response time may take up to 2 business days. FIRST AND FINAL ADD TO FOLLOW DATASOURCE: PrimeWest Energy Trust CONTACT: Investor Relations at (403) 234-6600 or toll-free in Canada and the U.S. at 1-877-968-7878; or visit us at our website, http://www.primewestenergy.co/

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