PrimeWest Energy Trust announces second quarter 2004 results and increased distribution level for September 2004 CALGARY, Aug. 3 /PRNewswire-FirstCall/ -- (TSX: PWI.UN, PWX; NYSE: PWI) - PrimeWest Energy Trust (PrimeWest or the Trust) today announced interim operating and financial results for the second quarter ended June 30, 2004, and such information is provided as of August 3, 2004. Unless otherwise noted, all figures contained in this report are in Canadian dollars. Second Quarter Highlights: - Second quarter production averaged 31,185 barrels of oil equivalent (BOE) per day, compared to the first quarter 2004 rate of 31,202 BOE/day(1). - Distributions of $0.75 per unit represent a payout ratio of approximately 72%, compared to first quarter 2004 distributions of $0.82 per unit, representing a payout ratio of 70%. - Cash flow from operations of $58.2 million ($1.05 per unit) compared to $58.5 million ($1.15 per unit) in the first quarter of 2004, primarily due to a continued strong commodity price environment and sustained volumes. - At PrimeWest's Annual Meeting of unitholders held May 6th, unitholders voted 98% in favor of an amendment to the Declaration of Trust, which eliminates residency restriction provisions. PrimeWest now has until January 1st, 2007 to develop alternatives to the proposed non-residency requirement of the Canadian federal government budget. PrimeWest believes that a key element of its long-term strategy is continued access to the North American capital markets. - On June 8th the Alberta Energy and Utilities Board (AEUB) definitively issued rulings regarding the natural gas over bitumen issue in the Wabiskaw-McMurray area of Northeast Alberta. Effective July 1st approximately 330 BOE per day of natural gas production from PrimeWest's Ells field has been shut-in to comply with this order. PrimeWest expects to receive compensation from the Province of Alberta for this shut-in volume. - During the quarter, PrimeWest concluded 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 were used to reduce debt, including the debt incurred with respect to the $46 million acquisition cost of Seventh Energy, and funding of the 2004 capital program. Debt to annualized second quarter 2004 cash flow is 0.7 times. Net debt at June 30, 2004, is $2.97 per unit, down $3.02 per unit from March 31, 2004 level of $5.99. Subsequent Events - The distribution payable September 15th, 2004 will increase by 10% to $0.275 Canadian per trust unit payable to all unitholders of record on August 23rd, 2004, with an ex-distribution date of August 19th, 2004. Continued strength in oil and gas prices, higher production, a strong balance sheet, and the expiry of a portion of the out-of-the-money hedges all contributed to this distribution increase. - Following the end of the second quarter, PrimeWest entered into two asset acquisitions, one of which closed on July 12th, 2004 and the other is scheduled to close August 5, 2004. On a net running rate basis PrimeWest will have acquired approximately 700 BOE/D for a total cash consideration of $28.1 million. After the application of enhanced recovery methods, production is expected to increase by approximately 300 BOE per day. - These transactions will increase PrimeWest's working interest in both the Lone Pine Creek and Princess areas. PrimeWest has also entered into agreements to divest of approximately 290 BOE/D of low margin non-core production for proceeds of approximately $5.8 M. 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 June 30, 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 - Second Quarter Financial Highlights Three Months Ended Six Months Ended ------------------------------------------------- (millions of dollars, except per BOE and June 30, Mar 31, June 30, June 30, June 30, per Trust Unit amounts) 2004 2004 2003 2004 2003 ------------------------------------------------------------------------- Net revenue 84.9 85.7 85.6 170.6 179.7 per BOE(1) 29.91 30.20 27.67 30.05 28.96 Cash flow from operations 58.2 58.5 57.2 116.7 122.0 per BOE 20.52 20.59 18.45 20.56 19.67 per Trust Unit(2) 1.05 1.15 1.24 2.20 2.75 Royalty expense 25.7 23.3 25.0 49.0 57.7 per BOE 9.06 8.22 8.08 8.64 9.30 Operating expenses 19.6 19.7 20.3 39.2 41.0 per BOE 6.89 6.92 6.57 6.91 6.60 G&A expenses - Cash 3.5 4.2 3.2 7.7 7.0 per BOE 1.23 1.49 1.04 1.36 1.13 G&A expenses - Non-cash (7.3) 0.4 3.2 (6.8) 3.6 per BOE (2.57) 0.15 1.05 (1.21) 0.59 Interest expense 2.8 3.2 3.4 6.0 7.0 per BOE 1.00 1.11 1.11 1.06 1.13 Distributions to unitholders 42.0 41.1 52.8 83.1 102.6 per Trust Unit(3) 0.75 0.82 1.20 1.57 2.40 Net debt(4) 169.2 305.7 286.4 169.2 286.4 per Trust Unit(5) 2.97 5.99 6.17 2.97 6.17 ------------------------------------------------------------------------- (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 excluding financial derivative liabilities. (5) Trust Units and Exchangeable Shares outstanding (diluted) at end of period. Operating Highlights Three Months Ended Six Months Ended -------------------------------------------------- June 30, Mar 31, June 30, June 30, June 30, 2004 2004 2003 2004 2003 ------------------------------------------------------------------------- Daily Sales Volumes Natural gas (mmcf/day) 125.5 123.9 137.9 124.7 139.1 Crude oil (bbls/day) 7,699 7,864 8,222 7,782 8,182 Natural gas liquids (bbls/day) 2,569 2,696 2,800 2,632 2,914 ------------------------------------------------------------------------- Total (BOE/day) 31,185 31,202 34,004 31,193 34,277 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Realized Commodity Prices(1) (Cdn $) Natural gas ($/Mcf) 6.59 6.57 6.10 6.58 6.51 Without hedging 6.82 6.62 6.69 6.72 7.26 Crude oil ($/bbl) 35.83 34.93 33.60 35.38 35.94 Without hedging 43.20 39.44 34.82 41.30 39.19 Natural gas liquids ($/bbl) 41.22 38.54 32.71 39.85 36.88 ------------------------------------------------------------------------- Total ($ per BOE) 38.77 38.21 35.54 38.49 38.13 Without hedging 41.51 39.56 38.23 40.54 41.97 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (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 are made 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 June 30, 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 second 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 into 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 second quarter of 2004, assets acquired from Seventh Energy Ltd. (Seventh) contributed 1,315 BOE per day to production volumes. PrimeWest plans to spend approximately $7 million in 2004 to develop the Seventh assets, and expects this acquisition to be accretive to its unitholders 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 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 second quarter 2004 payout ratio was approximately 72%, 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 0.7 times for the second quarter, significantly less than our internal limit of 2.0 times and less than our level of 1.25 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, and 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. 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 30,500 BOE/day. Full year operating costs are expected to be approximately $6.75/BOE. PrimeWest expects to invest approximately $90 million in its capital development program, with the focus primarily in the core areas of Caroline, Valhalla, Brant/Farrow and Princess/Hays. For unitholders resident in Canada, PrimeWest anticipates that approximately 60% of 2004 distributions will be taxable and 40% will be deemed return of capital. The taxability of 2004 distributions for U.S. unitholders cannot be accurately estimated at this time, but will be confirmed after year end. For residents of the U.S., Canadian withholding tax of 15% applies to the distribution. In addition, the Canadian Federal Government announced a proposal on March 23, 2004 which would expand Canadian withholding tax on non- Canadian residents (15% for U.S. unitholders) by applying it to both the "taxable income" portion, as well as the return of capital portion of the distributions effective January 1, 2005. A withholding tax of 15% has always been applied to the total value of distributions paid to U.S. unitholders. For more details on withholding tax, please visit our website at http://www.primewestenergy.com/. Cash Flow Reconciliation ($ millions) ------------------------------------------------------------------------- First quarter 2004 cash flow from operations $ 58.5 Commodity prices 5.5 Net hedging change from prior quarter (3.9) Operating expenses 0.1 Royalties (2.4) Other 0.4 ------------------------------------------------------------------------- Second quarter 2004 cash flow from operations $ 58.2 ------------------------------------------------------------------------- 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, and 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, except per 2004 2003 2002 Trust Unit -------------------------------------------------------- amounts) Q2 Q1 Q4 Q3 Q2 Q1 Q4 Q3 ------------------------------------------------------------------------- Net Revenues 84.9 85.7 73.0 77.3 85.6 94.0 68.8 63.8 Net Income 22.4 20.1 (0.7) 7.4 61.4 22.4 (7.3) 8.2 Net Income Per Unit - Basic 0.41 0.40 (0.01) 0.16 1.34 0.53 (0.20) 0.24 Net Income Per Unit - Diluted 0.40 0.40 (0.01) 0.16 1.33 0.53 (0.20) 0.24 ------------------------------------------------------------------------- ------------------------------------------------------------------------- The above table highlights PrimeWest's performance for the second quarter ended 2004, and the preceding seven quarters through 2003 and 2002. Net revenues are primarily impacted by commodity prices, production volumes and royalties. As a result of higher royalty expenses, the second quarter 2004 net revenues were slightly lower compared to the first quarter of 2004. 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 Six Months Ended -------------------------------------------------- ($ millions, June 30, Mar 31, June 30, June 30, June 30, except per BOE) 2004 2004 2003 2004 2003 ------------------------------------------------------------------------- Land & lease acquisitions $ 2.7 $ 1.8 $ 1.1 $ 4.5 $ 2.3 Geological and geophysical 0.8 1.7 0.4 2.5 1.0 Drilling and completions 9.0 18.8 7.6 27.8 22.6 Investment in facilities Equipping & tie-in 2.8 4.0 3.7 6.8 6.7 Compression & processing 0.5 2.0 1.0 2.5 2.7 Gas gathering 0.2 0.5 1.7 0.7 4.0 Production facilities 5.1 2.1 2.0 7.2 2.8 Capitalized G&A 0.6 0.4 0.3 1.0 0.5 ------------------------------------------------------------------------- Development capital 21.7 31.3 17.8 53.0 42.6 ------------------------------------------------------------------------- Corporate/property acquisitions 0.4 38.6 7.3 39.0 205.7 Dispositions (1.6) (3.5) 0.0 (5.1) (0.2) Head office equipment 0.5 0.2 0.1 0.6 0.1 ------------------------------------------------------------------------- Total $ 21.0 $ 66.6 $ 25.2 $ 87.5 $ 248.2 ------------------------------------------------------------------------- ------------------------------------------------------------------------- During the second quarter of 2004, PrimeWest's capital expenditures totaled $21.0 million, compared to $25.2 million invested in the same quarter the previous year. Development capital of $21.7 million invested in the second quarter 2004 was higher than the second quarter 2003 investment of $17.8 million. Of the $21.7 million in development capital, $9.0 million or 41.5% was spent on drilling and completions, which contribute to new reserve additions and help offset natural production decline. Of the $8.6 million investments made in facilities, $2.8 million or 32.6% represents equipping and volume tie-ins, with the remainder invested in other activities that contribute to future production volumes. In the second quarter, PrimeWest's capital spending was focused primarily in the areas of Caroline, Brant Farrow, and Valhalla. Gross wells drilled in the second quarter totaled 16 (11.8 net wells), with a success rate of approximately 88%. Year to date 47 gross wells (30.8 net wells) have been drilled with a success rate of approximately 89%. Compared to the first quarter of 2004, development capital spending of $21.7 million in the second quarter of 2004 was lower due to location access as a result of Spring break-up and wet weather. Higher level of drilling activity and gas plant modifications at Valhalla in the first half of 2004 resulted in 2004 development expenses being approximately $10.4 million higher than the same period of 2003, which were $42.6 million. Corporate acquisitions in 2003 included the purchase of two private Canadian companies. In 2004 PrimeWest completed the corporate acquisition of Seventh Energy. 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 Energy 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 Six Months Ended -------------------------------------------------- June 30, Mar 31, June 30, June 30, June 30, 2004 2004 2003 2004 2003 ------------------------------------------------------------------------- Natural gas (mmcf/day) 125.5 123.9 137.9 124.7 139.1 Crude oil (bbls/day) 7,699 7,864 8,222 7,782 8,182 Natural gas liquids (bbls/day) 2,569 2,696 2,800 2,632 2,914 ------------------------------------------------------------------------- Total (BOE/day) 31,185 31,202 34,004 31,193 34,277 ------------------------------------------------------------------------- Gross Overriding Royalty volumes included above (BOE/day) 1,355 1,397 1,754 1,355 1,727 ------------------------------------------------------------------------- ------------------------------------------------------------------------- All production information is reported before the deduction of crown and freehold royalties. PrimeWest's production volumes in the second quarter remained relatively flat when compared with the first quarter of 2004 due to additional volumes contributed by the Seventh Energy assets and volumes resulting from development activity offsetting natural production decline. Compared to the first six months of 2003, production in the first half of 2004 was 9% lower, primarily attributable to production decline. In the second quarter of 2004, the Alberta Energy and Utilities Board ruled on the natural gas over bitumen issue, which resulted in approximately 330 BOE/day of production at Ells being permanently shut-in effective July 1, 2004. The impact of this shut-in has already been factored into PrimeWest's 2004 full year production guidance. With the operator, PrimeWest intends to seek compensation for the shut-in production from the Province of Alberta. Production at PrimeWest's non-operated Whiskey Creek area is expected to remain restricted for the remainder of 2004 due to third party facility capacity constraints. PrimeWest expects full year 2004 production to average approximately 30,500 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, the acquired production from Seventh Energy and recent acquisitions through swaps. Commodity Prices Three Months Ended Six Months Ended -------------------------------------------------- June 30, Mar 31, June 30, June 30, June 30, Benchmark Prices 2004 2004 2003 2004 2003 ------------------------------------------------------------------------- Natural gas ($/mcf AECO) 6.80 6.61 7.00 6.71 7.46 Crude oil (U.S.$/bbl WTI) 38.32 35.15 28.91 36.74 31.39 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Average realized prices in the marketplace are indicated by these benchmark prices. Average Realized Sales Prices Three Months Ended Six Months Ended -------------------------------------------------- June 30, Mar 31, June 30, June 30, June 30, (Canadian Dollars) 2004 2004 2003 2004 2003 ------------------------------------------------------------------------- Natural gas ($/mcf)(1)(2) 6.59 6.57 6.10 6.58 6.51 Without hedging 6.82 6.62 6.69 6.72 7.26 Crude oil ($/bbl)(1) 35.83 34.93 33.60 35.38 35.94 Without hedging 43.20 39.44 34.82 41.30 39.19 Natural gas liquids ($/bbl) 41.22 38.54 32.71 39.85 36.88 ------------------------------------------------------------------------- Total Oil Equivalent(2) ($/BOE) 38.77 38.21 35.54 38.49 38.13 Without hedging 41.51 39.56 38.23 40.54 41.97 ------------------------------------------------------------------------- Realized hedging gain (loss) included in prices above ($/BOE) (2.74) (1.35) (2.69) (2.05) (3.84) ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Includes hedging gains/losses. (2) Excludes sulphur. Canadian commodity prices were higher in the second quarter 2004 than during the same period in 2003 resulting in higher average realized selling prices per BOE. 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. Compared to the first quarter 2004, average realized sales prices per BOE increased marginally in the second quarter 2004 due to higher average prices for crude oil, natural gas and liquids. In the first half of 2004, PrimeWest has realized higher average prices for its product relative to prices realized in the first six months of 2003. 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 second quarter of 2004, PrimeWest had a $7.8 million hedging loss compared to a loss of $8.3 million for the same period in 2003. The following table sets forth benchmark historical and estimated future commodity prices. Benchmark Past Four Quarters Next Four Quarters Commodity Prices (Actual) (Forward Markets)(1) ------------------------------------------------------------------------- Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 2003 2003 2004 2004 2004 2004 2005 2005 ------------------------------------------------------------------------- Natural gas NYMEX ($U.S./Mcf) 5.10 4.58 5.69 5.97 6.17 6.45 6.73 5.88 AECO ($Cdn/Mcf) 6.29 5.59 6.61 6.80 6.75 7.39 7.88 6.76 Crude oil WTI ($U.S./bbl) 30.20 31.18 35.15 38.32 37.04 36.55 35.81 35.18 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) As at June 30, 2004 Sales Revenue Three Months Ended Six Months Ended -------------------------------------------------------------- Revenue June 30, % of Mar 31, % of June 30, % of June 30, June 30, ($ millions) 2004 total 2004 total 2003 total 2004 2003 ------------------------------------------------------------------------- Natural gas(1) $ 75.3 68% $ 74.0 68% $ 76.5 70% $149.3 $163.9 Crude oil 25.1 23% 25.0 23% 25.1 23% 50.1 53.2 Natural gas liquids 9.6 9% 9.5 9% 8.3 7% 19.1 19.5 ------------------------------------------------------------------------- Total $110.0 100% $108.5 100% $109.9 100% $218.5 $236.6 ------------------------------------------------------------------------- Hedging (loss)/ gains included above(2) $ (7.8) $ (3.8) $ (8.3) $(11.6) $(23.8) ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Excludes sulphur. (2) Net of amortized premiums. Second quarter 2004 revenues were marginally higher than the same period in 2003, due to higher commodity prices offset by lower production volumes. Revenues are higher in the second quarter 2004 compared to the first quarter 2004 due to the higher commodity price environment. Revenues are lower in the first six months of 2004 compared to the same period in 2003 due to reduced production volumes offset by higher commodity prices. 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 $26.0 million over the period from January 1, 2001 to June 30, 2004. Hedging is an important element in PrimeWest's financial management strategy. It is designed to reduce commodity price volatility, increase cash flow stability, and protect the economics of asset acquisitions. The hedging policy reflects a willingness to forfeit a portion of the pricing upside in return for protection against a significant downturn in prices. Approximate percentage of future anticipated production volumes hedged at June 30, 2004, net of anticipated royalties, reflecting full production declines with no offsetting additions: -------------------------- 2004 Q3 Q4 Q3-Q4 ------------------------------------------------------------------------- Crude Oil 59% 55% 57% Natural Gas 57% 36% 47% ------------------------------------------------------------------------- ------------------------------------------------------------------------- ---------------------------------------------- Full 2005 Q1 Q2 Q3 Q4 Year ------------------------------------------------------------------------- Crude Oil 41% 34% 18% 9% 26% Natural Gas 25% 0% 0% 0% 6% ------------------------------------------------------------------------- PrimeWest generally sells its oil and gas under short-term market-based contracts. Derivative financial instruments, options and swaps may be used to hedge the impact of oil and gas price fluctuations. A listing of these contracts in place at June 30, 2004 follows: Crude Oil ($U.S./bbl) ------------------------------------------------------------------------- Period Volume (bbls/d) Type WTI Price ($U.S./bbl) ------------------------------------------------------------------------- Jul - Aug 2004 500 Swap 31.55 Jul - Sep 2004 500 Swap 26.07 Jul - Sep 2004 500 Swap 27.04 Jul - Sep 2004 500 Swap 28.51 Jul - Sep 2004 500 Swap 30.23 Jul - Sep 2004 500 Costless Collar 24.00/30.75 Jul - Sep 2004 500 Costless Collar 25.00/28.30 Jul - Sep 2004 500 Costless Collar 26.00/32.05 Oct - Dec 2004 500 Swap 26.00 Oct - Dec 2004 500 Swap 27.03 Oct - Dec 2004 500 Swap 28.53 Oct - Dec 2004 500 Swap 30.10 Oct - Dec 2004 500 Costless Collar 24.00/30.00 Oct - Dec 2004 500 Costless Collar 25.00/28.30 Oct - Dec 2004 500 Costless Collar 26.00/32.72 Jan - Mar 2005 500 Swap 27.25 Jan - Mar 2005 500 Swap 28.60 Jan - Mar 2005 500 Swap 30.00 Jan - Mar 2005 500 Costless Collar 28.00/34.35 Jan - Mar 2005 500 3 Way 25.00/30.00/35.50 Apr - Jun 2005 500 Swap 27.07 Apr - Jun 2005 500 Swap 28.50 Apr - Jun 2005 500 Swap 30.00 Apr - June 2005 500 3 Way 25.00/30.00/36.75 Jul - Sep 2005 500 Swap 27.05 Jul - Sep 2005 500 Swap 28.50 Oct - Dec 2005 500 Swap 27.18 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Natural Gas (Cdn$/mcf) ------------------------------------------------------------------------- Period Volume (mmcf/d) Type AECO Price (Cdn$/bbl) ------------------------------------------------------------------------- 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 Nov 2004 - Mar 2005 4.7 Costless Collar 6.33/11.87 Nov 2004 - Mar 2005 4.7 Costless Collar 6.86/11.61 ------------------------------------------------------------------------- ------------------------------------------------------------------------- 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 $6.09, PrimeWest would receive the market price. Natural Gas Basis Differential ------------------------------------------------------------------------- Period Volume (mmcf/day) Type Basis Price ($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 $U.S. 4.29 per mcf. Electrical Power ------------------------------------------------------------------------- Period Power Amount (MW) Type Price ($/MW-hr) ------------------------------------------------------------------------- Q3 2004 5 Fixed Price Swap 46.50 Q4 2004 5 Fixed Price Swap 44.00 Calendar 2004 5 Fixed Price Swap 45.65 ------------------------------------------------------------------------- ------------------------------------------------------------------------- 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 June 30, 2004, PrimeWest had an outstanding derivative loss of $1.5 million, comprised of $1.0 million loss for crude oil, $0.9 million for natural gas, and a $0.4 million gain for electrical power. The derivative loss is shown as a current asset on the balance sheet. The loss will continue to be amortized to earnings upon settlement of the corresponding hedges, which are expected to expire by March 2005. The unrealized loss on derivatives on the income statement results from the change in the mark-to-market valuation of the derivative financial instruments during the period. It represents the loss that would be incurred if the contracts were settled on the period end date. The unrealized loss on derivatives for the six months ended June 30, 2004 was $14.1 million. The loss was comprised of a $10.3 million loss for crude oil, $4.2 million loss for natural gas, and a $0.4 million gain for electrical power. The $1.8 million unrealized derivative loss for the three months ended June 30, 2004 was comprised of a $4.0 million loss on crude oil, $1.8 million gain on natural gas, $0.3 million gain on electrical power and a $0.1 million gain upon the settlement of the interest rate swaps. The mark-to-market valuation of the derivatives in place at June 30, 2004 was a $15.6 million loss consisting of an $11.3 million loss in crude oil, $5.1 million loss in natural gas, and a $0.8 million gain on electrical power. $14.3 million of the derivative loss is shown as a current liability on the balance sheet as these derivatives will be settled in the next twelve months. The remaining liability of $1.3 million is reported as a long term derivative liability. For the three months ended June 30, 2004, the cash impact of contracts settling was a $7.5 million loss consisting of a $5.2 million loss in crude oil, $2.6 million loss in natural gas, $0.5 million gain on electrical power and a $0.2 million loss in interest rate swaps. For the six months ended June 30, 2004 the cash impact of contracts settling was a $11.9 million loss comprised of a $8.4 loss in crude oil, $3.2 million loss in natural gas, a $0.4 million gain on electrical power and a $0.7 million loss in interest rate swaps. Royalties (Net of ARTC) Royalties are paid by PrimeWest to the owners of mineral rights with whom PrimeWest holds leases. PrimeWest has mineral leases with the Crown (Provincial and Federal Governments), freeholders (individuals or other companies) and other operators. ARTC is the Alberta Royalty Tax Credit, a tax rebate provided by the Alberta government to producers that paid eligible Crown royalties in the year. Three Months Ended Six Months Ended -------------------------------------------------- ($ millions, June 30, Mar 31, June 30, June 30, June 30, except per BOE) 2004 2004 2003 2004 2003 ------------------------------------------------------------------------- Royalty expense (net of ARTC) $ 25.7 $ 23.3 $ 25.0 $ 49.0 $ 57.7 Per BOE $ 9.06 $ 8.22 $ 8.08 $ 8.64 $ 9.30 ------------------------------------------------------------------------- Royalties as % of sales revenues With hedge loss 23.4% 21.5% 22.7% 22.4% 24.4% Excluding hedge loss 21.8% 20.8% 21.1% 21.3% 22.1% ------------------------------------------------------------------------- ------------------------------------------------------------------------- Royalty expense in the second quarter of 2004 is marginally higher than the same period the previous year. For the first half of 2004, royalties were $49.0 million, lower than the same period in 2003 due to lower production volumes. Royalty rates are based on commodity prices so future changes to prices will be accompanied by changes in royalty expense. Operating Expenses Three Months Ended Six Months Ended -------------------------------------------------- ($ millions, June 30, Mar 31, June 30, June 30, June 30, except per BOE) 2004 2004 2003 2004 2003 ------------------------------------------------------------------------- Operating expense ($ millions) $ 19.6 $ 19.7 $ 20.3 $ 39.2 $ 41.0 Per BOE $ 6.89 $ 6.92 $ 6.57 $ 6.91 $ 6.60 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Compared to both the second quarter of 2003 and the previous quarter in 2004, PrimeWest's total operating expenses for the second quarter 2004 are virtually unchanged. On a per BOE basis, operating costs are higher in the second quarter in 2004 compared to the same quarter in the previous year due to lower production volumes. Operating expenses are slightly lower in the first half of 2004 compared to the first half of 2003, but are higher on a per BOE basis due to lower volumes. Operating Expenses Outlook Operating costs for the year are expected to be higher than in 2003, and PrimeWest expects 2004 operating expenses to be approximately $6.75/BOE. Operating Margin Three Months Ended Six Months Ended -------------------------------------------------- June 30, Mar 31, June 30, June 30, June 30, ($/BOE) 2004 2004 2003 2004 2003 ------------------------------------------------------------------------- Sales price and other revenue(1) $ 38.96 $ 38.42 $ 35.75 $ 38.69 $ 38.26 Royalties 9.06 8.22 8.08 8.64 9.30 Operating expenses 6.89 6.92 6.57 6.91 6.60 ------------------------------------------------------------------------- Operating margin $ 23.01 $ 23.28 $ 21.10 $ 23.14 $ 22.36 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Includes hedging and sulphur Operating margin per BOE increased 9% during the second quarter 2004 compared to the same quarter in 2003. This 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 the amount of cash flow PrimeWest realizes per barrel of oil equivalent that is produced, before head office expenses and financing charges. Operating margin decreased in the second quarter compared to the first quarter 2004, primarily as a result of higher royalty expense. Compared to the first six months of 2003, operating margin in the first half of 2004 was 3% higher. Based on PrimeWest's outlook on commodity prices, the Canadian / U.S. dollar exchange rate, operating expense expectations and hedge positions, margins are expected to be higher in 2004 than 2003. PrimeWest will continue to focus on achieving 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 Six Months Ended -------------------------------------------------- ($ millions, June 30, Mar 31, June 30, June 30, June 30, except per BOE) 2004 2004 2003 2004 2003 ------------------------------------------------------------------------- Cash G&A expense ($ millions) $ 3.5 $ 4.2 $ 3.2 $ 7.7 $ 7.0 Per BOE $ 1.23 $ 1.49 $ 1.04 $ 1.36 $ 1.13 Non-cash G&A expense ($ millions) $ (7.3) $ 0.4 $ 3.2 $ (6.8) $ 3.6 Per BOE $ (2.57) $ 0.15 $ 1.05 $ (1.21) $ 0.59 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Cash G&A expense in the second quarter 2004 decreased 17% on a gross and per BOE basis from the previous quarter due to lower salaries, benefits, legal costs and engineering fees. Cash G&A expense in the second quarter has increased marginally compared to the second quarter of 2003. Due to lower production volumes in 2004 G&A on a per BOE basis increased 18% for the period compared to 2003. The increase in the year to date gross and per BOE cash G&A compared to the same period in 2003 is mainly due to increases in salaries associated with higher technical staff levels and lower production volumes. PrimeWest's total and per BOE non-cash G&A expense has decreased significantly in the second quarter of 2004 and on a year to date basis compared to the prior quarter and same periods in 2003 due to a lower average Unit Appreciation Rights (UARs) value under PrimeWest's Long Term Incentive Plan (LTIP). The large negative non-cash G&A number reflects the movement in the trading price of PrimeWest units during the first half of 2004. Non-cash G&A expense consists mainly of the change in the value of the UARs. UARs 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 be higher than in 2003 and are expected to be approximately $1.25 per BOE for the year. Interest Expense Three Months Ended Six Months Ended -------------------------------------------------- ($ millions, June 30, Mar 31, June 30, June 30, June 30, except per Trust Unit) 2004 2004 2003 2004 2003 ------------------------------------------------------------------------- Interest expense $ 2.8 $ 3.2 $ 3.4 $ 6.0 $ 7.0 Period end net debt level $ 169.2 $ 305.7 $ 286.4 $ 169.2 $ 286.4 Debt per Trust Unit $ 2.97 $ 5.99 $ 6.17 $ 2.97 $ 6.17 ------------------------------------------------------------------------- Average cost of debt 4.4% 4.4% 4.9% 4.4% 4.8% ------------------------------------------------------------------------- ------------------------------------------------------------------------- Interest expense, representing interest on bank debt and private placement debt, decreased in the second quarter 2004 to $2.8 million from $3.4 million in the same quarter 2003, and decreased from $3.2 million in the previous quarter due to lower average interest rates and a lower debt balance in 2004 compared to 2003. For the first six months of 2004, interest expense was $6.0 million, compared to $7.0 million for the same period in 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. Foreign Exchange Loss The foreign exchange loss of $3.2 million for the three months ended June 30, 2004 and $4.9 million for the six months ended June 30, 2004, results from the translation of the U.S. dollar denominated secured notes and related interest payable in Canadian dollars. Depletion, Depreciation and Amortization Three Months Ended Six Months Ended -------------------------------------------------- ($ millions, June 30, Mar 31, June 30, June 30, June 30, except per BOE) 2004 2004 2003 2004 2003 ------------------------------------------------------------------------- Depletion, depreciation and amortization $ 41.4 $ 41.7 $ 49.9 $ 83.0 $ 102.6 ------------------------------------------------------------------------- $/BOE $ 14.59 $ 14.68 $ 16.13 $ 14.63 $ 16.54 ------------------------------------------------------------------------- ------------------------------------------------------------------------- The second quarter 2004 DD&A rate of $14.59/BOE is lower than the 2003 second quarter rate of $16.13/BOE 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 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 a site reclamation fund to pay for future costs related to well abandonment and site clean-up. The fund is used to pay for such costs as they are incurred. The 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 second quarter of 2004 were $0.3 million, compared to $0.3 million for the same period in 2003, and $0.9 million for the previous quarter. Asset Retirement Obligation PrimeWest adopted the new CICA Handbook section 3110, "Asset Retirement Obligations" in the first quarter of 2004. 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 capitalized to the related asset and amortized into earnings over time. 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, 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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