/FIRST AND FINAL ADD - TO300 - PrimeWest Energy Trust Earnings/

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Power Integrations	TG:PWI	Tradegate	Ordinary Share

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	-0.50	-0.87%	57.00	56.50	57.00				0.00	22:50:18

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/FIRST AND FINAL ADD - TO300 - PrimeWest Energy Trust Earnings/ Income and Capital Taxes Three Months Ended Six Months Ended -------------------------------------------------- June 30, Mar 31, June 30, June 30, June 30, ($ millions) 2004 2004 2003 2004 2003 ------------------------------------------------------------------------- Income and capital taxes $ 0.5 $ 0.3 $ 1.5 $ 0.8 $ 2.7 Future income taxes recovery (3.4) (18.2) (52.0) (21.6) (62.4) ------------------------------------------------------------------------- Total: $ (2.9) $ (17.9) $ (50.5) $ (20.8) $ (59.7) ------------------------------------------------------------------------- Cash taxes paid $ 1.3 $ 1.0 $ 0.8 $ 2.3 $ 0.8 ------------------------------------------------------------------------- ------------------------------------------------------------------------- The Alberta Government enacted a tax rate reduction of 1% in the first quarter of 2004, reducing the rate from 12.5% to 11.5% effective April 1, 2004. This resulted in an additional tax recovery during the first quarter of approximately $9 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%. The reduction in statutory tax rates resulted in the large income tax recovery in the second quarter of 2003. Cash taxes paid include tax installments for current and prior years and payments for taxes owing upon the filing of year end tax returns. Cash taxes paid in the six months ending June 30, 2004 include $1.3 million relating to prior years. Income and capital tax expense includes the estimate of the current year's taxes and any adjustments resulting from prior year tax assessments. The six months ended June 30, 2004 include a recovery of $0.4 million related to prior years. Net Income Three Months Ended Six Months Ended -------------------------------------------------- June 30, Mar 31, June 30, June 30, June 30, ($ millions) 2004 2004 2003 2004 2003 ------------------------------------------------------------------------- Net income $ 22.4 $ 20.1 $ 61.7 $ 42.6 $ 83.8 ------------------------------------------------------------------------- ------------------------------------------------------------------------- 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, future taxes and non-cash G&A. Net income for the second quarter of 2004 was impacted by lower non-cash general and administrative expense and a lower loss on derivatives offset by a reduced future tax recovery compared to the first quarter of 2004. Future income tax recoveries and foreign exchange gains contributed approximately $52.0 million and $5.6 million respectively, to net income in the second quarter of 2003. Net income for the six months ended June 30, 2004 is lower than the same period in 2003 due to lower net revenues and reduced future income tax recovery offset by lower DD&A. Liquidity & Capital Resources Long Term Debt As at --------------------------------------------- ($ millions) June 30, 2004 Mar 31, 2004 June 30, 2003 ------------------------------------------------------------------------- Long-term debt $ 179.7 $ 299.9 $ 298.4 Deficit/(working capital) (10.5) 5.8 (12.0) ------------------------------------------------------------------------- Net debt $ 169.2 $ 305.7 $ 286.4 Market value of Trust Units and Exchangeable Shares outstanding(1) $ 1,321.6 1,355.7 1,151.7 ------------------------------------------------------------------------- Total capitalization $ 1,490.8 $ 1,661.4 $ 1,438.1 ------------------------------------------------------------------------- Net debt as a % of total capitalization 11.3% 18.4% 19.9% ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Based on June 30, 2004 Trust Unit closing price of $23.25 and exchange ratio of 0.47310:1 Long term debt is comprised of bank credit facilities and senior secured notes of $13.0 million and $166.7 million, respectively. PrimeWest had a borrowing base of $400 million at June 30, 2004, as established by the lenders. The bank credit facilities consist of a revolving term loan of $212.5 million, an operating facility of $25 million, and the balance of $162.5 million of senior secured notes. PrimeWest's second quarter 2004 net debt totaled $169.2 million, 41% lower than the same period in 2003 and 45% lower than the previous quarter. The year over year and quarter over quarter decrease is primarily due to the equity offering proceeds which were used to reduce indebtedness during the quarter. 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 second quarter of 2004, PrimeWest's debt to annualized cash flow is approximately 0.7 times, and 11.3% 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 72% for the second quarter 2004 versus 92% for the second quarter 2003 enabled the Trust to use internally generated cash to invest in development opportunities and pay down bank debt. Unitholders' Equity At the end of the second quarter 2004, the Trust had 56,218,322 Trust Units outstanding, compared to 44,172,254 Trust Units outstanding at the end of the second quarter 2003. In addition, PrimeWest had 1,320,297 (2003 - 4,435,216) Exchangeable Shares outstanding which are exchangeable into a total of 624,629 (2003 - 1,821,543) Trust Units using the June 15, 2004 exchange ratio of 0.47310:1 (2003 - 0.41070:1). 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. 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 June 30, 2004, there were 1,320,297 Exchangeable Shares outstanding. The exchange ratio on these shares was 0.47310:1 Trust Units for each exchangeable share as at the end of the second 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 industry 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 second quarter of 2004, cash distributions totaled $42.0 million, or $0.75 per Trust Unit representing a payout ratio of 72%, compared to $52.8 million, or $1.20 per Trust Unit (92% payout ratio) for the same period in 2003. In the first quarter of 2004 cash distributions totaled $41.1 million, or $0.82 per Trust Unit representing a payout ratio of approximately 70% 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 June 30, 2004 $0.7 million has been accrued in non-cash general and administrative expenses related to the special employee retention plan. As at June 30, 2004 Payments due by period ($ millions) ------------------------------------------------------------------------- Less than 1-3 4-5 More than Total 1 year years years 5 years ----------------------------------------------- Long-term debt obligations $ 179.7 $ 13.0 $ 41.7 $ 83.4 $ 41.6 Lease rental obligations 5.1 0.9 3.4 0.8 - Pipeline transportation obligations 8.9 2.7 5.4 0.8 - Derivative liabilities 15.6 14.3 1.3 - - ------------------------------------------------------------------------- Total contractual obligations $209.3 $ 30.9 $ 51.8 $ 85.0 $ 41.6 -------------------------------------------------------------------------- ------------------------------------------------------------------------- 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 outstanding hedging contracts, produce cash inflow or outflow variances over the contract period. The estimate of fair value for interest rate and foreign currency hedges is determined primarily through quotes from financial institutions. Asset Retirement Obligations Effective January 1, 2004 PrimeWest changed its accounting policy with respect to accounting for asset retirement obligations. CICA section 3110 requires the fair value of asset retirement obligations to be recorded when they are incurred rather than merely accumulated or accrued over the useful life of the respective asset. PrimeWest, under the current policy, is required to provide for future removal and site restoration costs. PrimeWest must estimate these costs in accordance with existing laws, contracts 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 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 second quarter of 2004, PrimeWest lost $7.5 million from commodity hedges, but has added $26.0 million to revenue from its hedging program from January 1, 2001 to the end of the second quarter of 2004. The two most important factors affecting the level of cash distributions available to unitholders are the level of production achieved by PrimeWest, and the price received for its products. These prices are influenced in varying degrees by factors outside the Trust's control. Some of these factors include: - World market forces, specifically the actions of OPEC and other large crude oil producing countries including Russia, and their implications on the supply of crude oil; - World and North American economic conditions which influence the demand for both crude oil and natural gas and the level of interest rates set by the governments of Canada and the U.S.; - weather conditions that influence the demand for natural gas and heating oil; - the Canadian/U.S. dollar exchange rate that affects the price received for crude oil as the price of crude oil is referenced in U.S. dollars; - transportation availability and costs; and - price differentials among World and North American markets based on transportation costs to major markets and quality of production. To mitigate these risks, PrimeWest has an active hedging program in place based on an established set of criteria that has been approved by the Board of Directors. The results of the hedging program are reviewed against these criteria and the results actively monitored by the Board. Beyond our hedging strategy, PrimeWest also mitigates risk by having a well-diversified marketing portfolio and by transacting with a number of 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. 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 page 11 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 Laustsen Jung (GLJ). The work and independence of GLJ is reviewed by the Operations and Reserves Committee of the Board of Directors of PrimeWest. Our strategy is to invest in mature, longer life properties having a higher proved producing component 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 EH&S 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. 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. PrimeWest Energy Trust ------------------------------------------------------------------------- Consolidated Balance Sheet (Unaudited) (Audited) (millions of dollars) June 30, 2004 Dec 31, 2003 ------------------------------------------------------------------------- (Restated - Note 2) ASSETS Current assets Cash and short term deposits $ 12.5 $ 2.5 Accounts receivable 66.5 65.4 Derivative loss (Note 4) 1.5 - Prepaid expenses 7.1 6.5 Inventory 2.5 2.1 ------------------------------------------------------------------------- 90.1 76.5 Cash reserved for site restoration and reclamation 9.8 8.2 Other assets and deferred charges 1.7 1.5 Property, plant and equipment 1,255.8 1,548.2 Goodwill 68.8 56.1 ------------------------------------------------------------------------- $ 1,426.2 $ 1,690.5 ------------------------------------------------------------------------- ------------------------------------------------------------------------- LIABILITIES AND UNITHOLDERS' EQUITY Current liabilities Accounts payable $ 18.5 $ 26.7 Accrued liabilities 47.8 45.3 Derivative liabilities (Note 4) 14.3 - Accrued distributions to unitholders 11.8 10.3 ------------------------------------------------------------------------- 92.4 82.3 Derivative liabilities (Note 4) 1.3 - Long-term debt (Note 6) 179.7 250.1 Future income taxes 227.6 313.2 Asset retirement obligation (Note 5) 19.9 19.7 ------------------------------------------------------------------------- 520.9 665.3 UNITHOLDERS' EQUITY Net capital contributions (Note 7) 1,732.0 1,565.9 Capital issued but not distributed 2.3 5.2 Long-term incentive plan equity 5.3 14.6 Accumulated income 28.4 219.1 Accumulated cash distributions (854.7) (771.6) Accumulated dividends (8.0) (8.0) ------------------------------------------------------------------------- 905.3 1,025.2 ------------------------------------------------------------------------- $ 1,426.2 $ 1,690.5 ------------------------------------------------------------------------- ------------------------------------------------------------------------- The accompanying notes form an integral part of these financial statements. Consolidated Statements of Unitholders' Equity (Unaudited) For the six months ended (millions of dollars) June 30, 2004 June 30, 2003 ------------------------------------------------------------------------- (Restated - Note 2) Unitholders' equity, beginning of period $ 1,019.6 $ 847.2 Adjustment to Unitholders' equity at beginning of period to adopt: New Asset Retirement Obligation (Note 2) 5.6 - New Oil and Gas Accounting Standard (Note 2) (233.3) - Net income for the period 42.6 83.2 Net capital contributions 166.1 168.0 Capital issued but not distributed (2.9) 0.2 Long-term incentive plan equity (9.3) 1.6 Cash distributions (83.1) (102.6) ------------------------------------------------------------------------- Unitholders' equity, end of period $ 905.3 $ 997.6 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Consolidated Statements of Cash Flow (Unaudited) Three Months Ended Six Months Ended --------------------------------------- June 30, June 30, June 30, June 30, (millions of dollars) 2004 2003 2004 2003 ------------------------------------------------------------------------- (Restated - (Restated - Note 2) Note 2) OPERATING ACTIVITIES Net income for the period $ 22.4 $ 61.4 $ 42.6 $ 83.2 Add/(deduct): Items not involving cash from operations Depletion, depreciation and amortization 41.4 49.9 83.0 102.6 Non-cash general & administrative (7.3) 3.2 (6.8) 3.6 Non-cash foreign exchange loss (gain) 2.9 (5.6) 4.7 (5.6) Accretion on asset retirement obligation 0.4 0.3 0.7 0.6 Future income taxes recovery (3.4) (52.0) (21.6) (62.4) Unrealized loss on derivatives 1.8 - 14.1 - ------------------------------------------------------------------------- Cash flow from operations 58.2 57.2 116.7 122.0 Expenditures on site restoration and reclamation (0.3) (0.3) (1.3) (0.4) Change in non-cash working capital (8.0) 5.7 (6.8) (5.3) ------------------------------------------------------------------------- 49.9 62.6 108.6 116.3 ------------------------------------------------------------------------- FINANCING ACTIVITIES Proceeds from issue of Trust Units, net of issue costs 140.0 7.0 142.8 160.2 Net cash distributions to unitholders (35.1) (49.4) (65.0) (96.5) Decrease in bank credit facilities (123.1) (170.0) (84.9) (95.0) Increase in senior secured notes - 174.0 - 174.0 Increase in deferred charges - (1.4) - (1.4) Change in non-cash working capital 1.6 0.2 1.4 2.9 ------------------------------------------------------------------------- (16.6) (39.6) (5.7) 144.2 ------------------------------------------------------------------------- INVESTING ACTIVITIES Expenditures on property, plant & equipment (22.2) (18.8) (53.6) (44.2) Corporate acquisitions (Note 3) - (2.9) (34.8) (200.4) Acquisition of capital assets (0.4) (3.5) (4.2) (3.8) Proceeds on disposal of property, plant & equipment 1.6 - 5.1 0.2 Increase in cash reserved for future site restoration and reclamation (1.1) (1.3) (1.7) (2.7) Change in non-cash working capital (5.1) (4.1) (3.7) 2.7 ------------------------------------------------------------------------- (27.2) (30.6) (92.9) (248.2) ------------------------------------------------------------------------- INCREASE IN CASH FOR THE PERIOD 6.1 (7.6) 10.0 12.3 CASH (BANK OVERDRAFT) BEGINNING OF THE PERIOD 6.4 16.8 2.5 (3.1) ------------------------------------------------------------------------- CASH END OF THE PERIOD $ 12.5 $ 9.2 $ 12.5 $ 9.2 ------------------------------------------------------------------------- ------------------------------------------------------------------------- CASH INTEREST PAID $ 4.2 $ 2.5 $ 5.4 $ 4.6 ------------------------------------------------------------------------- ------------------------------------------------------------------------- CASH TAXES PAID $ 1.3 $ 0.8 $ 2.3 $ 0.8 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Consolidated Statements of Income (Unaudited) Three Months Ended Six Months Ended ------------------------------------------------------------------------- (millions of dollars, June 30, June 30, June 30, June 30, except per Trust Unit amounts) 2004 2003 2004 2003 ------------------------------------------------------------------------- (Restated - (Restated - Note 2) Note 2) REVENUES Sales of crude oil, natural gas and natural gas liquids $ 112.2 $ 112.7 $ 222.8 $ 241.4 Transportation expenses (1.8) (2.3) (3.7) (4.2) Crown and other royalties, net of ARTC (25.7) (25.0) (49.0) (57.7) Other income 0.2 0.2 0.5 0.2 ------------------------------------------------------------------------- 84.9 85.6 170.6 179.7 ------------------------------------------------------------------------- EXPENSES Operating 19.6 20.3 39.2 41.0 Cash general and administrative 3.5 3.2 7.7 7.0 Non-cash general and administrative (7.3) 3.2 (6.8) 3.6 Interest 2.8 3.4 6.0 7.0 Accretion on asset retirement obligation 0.4 0.3 0.7 0.6 Unrealized loss on derivatives 1.8 - 14.1 - Foreign exchange loss (gain) 3.2 (5.6) 4.9 (5.6) Depletion, depreciation and amortization 41.4 49.9 83.0 102.6 ------------------------------------------------------------------------- $ 65.4 $ 74.7 $ 148.8 $ 156.2 ------------------------------------------------------------------------- Income before taxes for the period $ 19.5 $ 10.9 $ 21.8 $ 23.5 ------------------------------------------------------------------------- Income and capital taxes 0.5 1.5 0.8 2.7 Future income taxes recovery (3.4) (52.0) (21.6) (62.4) ------------------------------------------------------------------------- (2.9) (50.5) (20.8) (59.7) ------------------------------------------------------------------------- Net income for the period $ 22.4 $ 61.4 $ 42.6 $ 83.2 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Net income per Trust Unit - basic $ 0.41 $ 1.34 $ 0.80 $ 1.89 Net income per Trust Unit - diluted $ 0.40 $ 1.33 $ 0.80 $ 1.88 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Notes to Consolidated Financial Statements For the six months ended June 30, 2004 (millions of dollars except per Trust Unit/share amounts). All amounts are expressed in millions of Canadian dollars unless otherwise indicated. 1. Significant Accounting Policies ----------------------------------- These interim consolidated financial statements of PrimeWest Energy Trust have been prepared in accordance with Canadian generally accepted accounting principles. The specific accounting principles used are described in the annual consolidated financial statements of the Trust appearing on pages 69 through 91 of the Trust's 2003 annual report and should be read in conjunction with these interim financial statements. 2. Changes in Accounting Policies ---------------------------------- Full Cost Accounting The adoption of AcG-16 modifies how the ceiling test is performed resulting in a two stage process. The first stage requires the carrying amount of the cost centers to be tested for recoverability using undiscounted future cash flows from proved reserves using management's best estimate of forward indexed prices. When the carrying amount of a cost center is not recoverable, the second stage of the process will determine the impairment whereby the cost center would be written down to its fair value. The second stage requires the calculation of discounted future cash flows from proved plus probable reserves. The fair value is estimated using accepted present value techniques, which incorporate risks and other uncertainties when determining expected cash flows. PrimeWest has performed the ceiling test under AcG-16 as of January 1, 2004. The impairment test was calculated using the consultant's average prices at January 1 for the years 2004 to 2008 as follows: Consultant's Average Price Forecasts Year ------------------------------------------------------------------------- 2004 2005 2006 2007 2008 ------------------------------------------------------------------------- WTI ($U.S./bbl) 29.21 26.43 25.42 25.38 25.51 AECO ($Cdn/mcf) 5.90 5.33 4.98 4.95 4.92 ------------------------------------------------------------------------- ------------------------------------------------------------------------- The ceiling test resulted in a before tax impairment of $308.9 million and an after tax impairment of $233.2 million. This write down was recorded to accumulated income in the first quarter of 2004 with the adoption of AcG-16. Asset Retirement Obligation Effective January 1, 2004, the Trust retroactively adopted the CICA Handbook section 3110, "Asset Retirement Obligations". The new standard requires the recognition of the liability associated with the future site reclamation costs of tangible long-lived assets. This liability would be comprised of the Trust's net ownership interest in producing wells and processing plant facilities. The liability for future retirement obligations is to be recorded in the financial statements at the time the liability is incurred. The asset retirement obligation is initially recorded at the estimated fair value as a long-term liability with a corresponding increase to property, plant and equipment. The depreciation of property, plant and equipment is allocated to expense on the unit-of-production basis. The liability is increased each reporting period for the fair value of any new future site reclamation costs and the corresponding accretion on the original provision. The accretion is charged to earnings in the period incurred. The provision will also be revised for any changes to timing related to cash flows or undiscounted reclamation costs. Actual expenditures incurred for the purpose of site reclamation are charged to the asset retirement obligation to the extent that the liability exists on the balance sheet. Differences between the actual costs incurred and the fair value of the liability recorded are recognized to earnings in the period incurred. The Trust previously estimated the costs of dismantlement, removal, abandonment and site reclamation on a unit-of-production basis over the remaining life of the estimated proved reserves. This estimate was charged to earnings with a corresponding offset to the accumulated site provision liability on the balance sheet. The adoption of CICA Handbook section 3110 allows for the cumulative effect of the change in accounting policy to be recorded to accumulated income with retroactive 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 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). See Note 5 for the reconciliation of the asset retirement obligation. Implementation of this accounting standard did not affect the Trust's cash flow or liquidity. Financial Derivatives Effective January 1, 2004, the Trust has implemented CICA Accounting Guideline (AcG-13), "Hedging Relationships", which is 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 established 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 position hedges with derivatives. The trust 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 $0.6 million for electrical power. See Note 4 for the reconciliation of the derivative liability and deferred derivative loss. 3. Corporate Acquisition ------------------------- a) On March 16, 2004, PrimeWest Gas Corp. completed the acquisition of Seventh Energy Ltd. Subsequent to the acquisition, Seventh Energy was amalgamated with PrimeWest Gas Corp. The acquisition was accounted for using the purchase method of accounting with net assets acquired and consideration paid as follows: ------------------------------------------------------------------------- Net Assets Acquired at Assigned Values ($ millions) Consideration Paid ($ millions) ------------------------------------------------------------------------- Petroleum and natural gas assets $ 46.5 Goodwill 12.8 Working capital (2.5) Long-term debt assumed (9.9) Office lease obligation (0.1) Asset retirement obligation (0.5) Cash $ 34.6 Future income taxes (11.5) Costs associated with acquisition 0.2 ------------------------------------------------------------------------- $ 34.8 $ 34.8 ------------------------------------------------------------------------- ------------------------------------------------------------------------- 4. Derivative Liabilities -------------------------- Derivative Liability ($ millions) ------------------------------------------------------------------------- Derivative Liability, January 1, 2004 $ 6.0 Derivative instruments settled (11.9) Mark-to-market unrealized loss 21.5 ------------------------------------------------------------------------- Derivative Liability, June 30, 2004 $ 15.6 ------------------------------------------------------------------------- ------------------------------------------------------------------------- ------------------------------------------------------------------------- Current Derivative Liability $ 14.3 Long term Derivative Liability 1.3 ------------------------------------------------------------------------- Derivative Liability, June 30, 2004 $ 15.6 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Derivative Loss ($ millions) ------------------------------------------------------------------------- Derivative Loss, January 1, 2004 $ 6.0 Derivative instruments settled that existed on January 1, 2004 or prior (4.5) ------------------------------------------------------------------------- Derivative Loss, June 30, 2004 $ 1.5 ------------------------------------------------------------------------- ------------------------------------------------------------------------- 5. Asset Retirement Obligations -------------------------------- Management has estimated the total future asset retirement obligation based on the Trust's net ownership interest in all wells and facilities. This includes all estimated costs to dismantle, remove, reclaim and abandon the wells and facilities and the estimated time period during which these costs will be incurred in the future. The following table reconciles the asset retirement obligation associated with the retirement of oil and gas properties: Asset Retirement Obligation ($ millions) ------------------------------------------------------------------------- Asset Retirement Obligation, December 31, 2003 $ 19.7 Liabilities incurred 0.3 Liabilities settled (1.3) Accretion expense 0.7 Acquisition of Seventh Energy 0.5 ------------------------------------------------------------------------- Asset Retirement Obligation, June 30, 2004 $ 19.9 ------------------------------------------------------------------------- ------------------------------------------------------------------------- As at June 30, 2004, the undiscounted amount of estimated cash flows required to settle the obligation is $124.6 million. The estimated cash flow has been discounted using a credit-adjusted risk free rate of 7.0 percent and an inflation rate of 1.5 percent. Although the expected period until settlement ranges from a minimum of 7 years to a maximum of 50 years, the costs are expected to be paid over an average of 34 years. These future asset retirement costs will be funded from the cash reserved for site restoration and reclamation. This cash reserve is currently funded at $0.50 per boe from PrimeWest's operating resources. 6. Long-Term Debt ------------------ ($ millions) June 30, 2004 Dec 31, 2003 ------------------------------------------------------------------------- Bank credit facilities $ 13.0 $ 88.0 Senior secured notes 166.7 162.1 ------------------------------------------------------------------------- $ 179.7 $ 250.1 ------------------------------------------------------------------------- ------------------------------------------------------------------------- 7. Unitholders' Equity ----------------------- The authorized capital of the Trust consists of an unlimited number of Trust Units. Trust Units Number of Units ($ millions) ------------------------------------------------------------------------- Balance, December 31, 2003 48,751,883 $ 1,537.9 Issued pursuant to equity offering 5,400,000 134.7 Issued on exchange of Exchangeable Shares 773,150 15.8 Issued pursuant to Distribution Reinvestment Plan 144,910 3.5 Issued pursuant to the Premium Distribution Plan 720,102 17.6 Issued pursuant to Long-Term Incentive Plan 83,524 2.2 Issued pursuant to Optional Trust Unit Purchase Plan 344,753 8.1 ------------------------------------------------------------------------- Balance, June 30, 2004 56,218,322 $ 1,719.8 ------------------------------------------------------------------------- ------------------------------------------------------------------------- The weighted average number of Trust Units and Exchangeable Shares outstanding for the three and six months ended June 30, 2004 were 55,296,924 (2003 - 45,714,429) and 52,886,415 (2003 - 43,927,753) respectively. For purposes of calculating diluted net income per Trust Unit, 165,830 Trust Units (2003 - 405,357) issuable pursuant to the Long- Term Incentive Plan were added to the weighted average number. The per unit cash distribution amounts paid or declared reflects distributions paid or declared to Trust Units outstanding on the record dates. PrimeWest Exchangeable Class A Shares The Exchangeable Shares are exchangeable into PrimeWest Trust Units at any time up to March 29, 2010 based on an exchange ratio that adjusts each time the Trust makes a distribution to its unitholders. The exchange ratio, which was 1:1 on the date that the Exchangeable Shares were first issued, is based on the total monthly distribution, divided by the closing unit price on the distribution payment date. The exchange ratio effective June 15, 2004 was 0.47310:1 and December 31, 2003 was 0.44302:1. Exchangeable Shares No. of shares ($ millions) ------------------------------------------------------------------------- Balance, December 31, 2003 3,041,123 $ 28.0 Exchanged for Trust Units (1,720,826) (15.8) ------------------------------------------------------------------------- Balance, June 30, 2004 1,320,297 $ 12.2 ------------------------------------------------------------------------- ------------------------------------------------------------------------- 8. Long-Term Incentive Plan ---------------------------- Under the terms of the Long Term Incentive Plan, a maximum of 1,800,000 Trust Units are reserved for issuance pursuant to the exercise of Unit Appreciation Rights (UARs) granted to employees of PrimeWest. Payouts under the plan are based on total unitholder return, calculated using both the change in the Trust Unit price as well as cumulative distributions paid. The plan requires that a hurdle return of 5% per annum be achieved before payouts accrue. UARs have a term of up to six years and vest equally over a three-year period, except for the members of the Board, whose UARs vest immediately. The Board of Directors has the option of settling payouts under the plan in PrimeWest Trust Units or in cash. To date, all payouts under the plan have been in the form of Trust Units. As at June 30, 2004 ------------------------------------------------------------------------- Current UARs return per issued & UARs "in the Total Trust Unit Year of Grant outstanding vested money" UARs equity dilution ------------------------------------------------------------------------- 1999 grants 38,331 38,331 $ 26.88 $ 1.0 44,317 2000 grants 111,318 111,318 9.32 1.0 44,602 2001 grants 355,297 294,750 3.28 1.2 35,772 2002 grants 871,819 456,961 2.23 1.4 25,232 2003 grants 1,018,043 263,861 1.13 0.7 15,907 2004 grants 632,305 72,489 $ 0.01 - - ------------------------------------------------------------------------- Total grants 3,027,113 1,237,710 $ 5.3 165,830 ------------------------------------------------------------------------- ------------------------------------------------------------------------- 9. Cash Distributions ---------------------- Three Months Ended Six Months Ended ------------------------------------------------------------------------- (millions of dollars, June 30, June 30, June 30, June 30, except per Trust Unit amounts) 2004 2003 2004 2003 ------------------------------------------------------------------------- Net income for the period Add back (deduct) amounts to reconcile to distribution: $ 22.4 $ 61.4 $ 42.6 $ 83.2 Depletion, depreciation and amortization 41.4 49.9 83.0 102.6 Cash retained from cash available for distribution (14.7) (2.8) (30.6) (16.3) Contribution to reclamation fund (1.5) (1.6) (3.0) (3.1) Non-cash general and administrative (7.3) 3.2 (6.8) 3.6 Unrealized loss on derivatives 1.8 - 14.1 - Non-cash foreign exchange loss (gain) 2.9 (5.6) 4.7 (5.6) Accretion on asset retirement obligation 0.4 0.3 0.7 0.6 Future income taxes recovery (3.4) (52.0) (21.6) (62.4) ------------------------------------------------------------------------- $ 42.0 $ 52.8 $ 83.1 $ 102.6 ------------------------------------------------------------------------- Cash Distributions to Trust Unitholders $ 42.0 $ 52.8 $ 83.1 $ 102.6 ------------------------------------------------------------------------- Cash Distributions per Trust Unit $ 0.75 $ 1.20 $ 1.57 $ 2.40 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Trading Performance For the quarter ended Jun 30/04 Mar 31/04 Dec 31/03 Sep 30/03 Jun 30/03 ------------------------------------------------------------------------- TSX Trust Unit prices ($ per Trust Unit) High 26.80 28.35 28.15 26.80 27.75 Low 22.18 22.70 23.40 25.19 23.40 Close 23.25 26.65 27.56 25.19 25.04 ------------------------------------------------------------------------- Average daily traded volume 187,767 256,922 202,661 149,148 234,477 ------------------------------------------------------------------------- ------------------------------------------------------------------------- For the quarter ended Jun 30/04 Mar 31/04 Dec 31/03 Sep 30/03 Jun 30/03 ------------------------------------------------------------------------- TSX Trust Unit prices ($U.S. per Trust Unit) High 20.44 22.14 21.48 19.29 20.60 Low 16.00 17.31 18.67 18.08 15.97 Close 17.43 20.31 21.27 18.68 18.53 ------------------------------------------------------------------------- Average daily traded volume 279,882 469,694 243,921 151,813 166,722 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Number of Trust Units outstanding including Exchangeable Shares (millions of units) 56.8 50.87 50.10 49.52 45.99 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Distribution paid per Trust Unit $0.75 $0.82 $0.96 $0.96 $1.20 ------------------------------------------------------------------------- ------------------------------------------------------------------------- END FIRST AND FINAL ADD DATASOURCE: PrimeWest Energy Trust CONTACT: PR Newswire -- Aug. 3

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