/FIRST AND FINAL ADD - TO153 - PrimeWest Energy Trust Earnings UNITHOLDERS' EQUITY The Trust had 48,751,883 Trust Units outstanding at December 31, 2003 compared to 37,004,522 Trust Units at the end of 2002. In addition, there are 3,041,123 exchangeable shares (see below) outstanding at year end, exchangeable into a total of 1,347,277 Trust Units. The weighted average number of Trust Units, including those issuable by the exchange of exchangeable shares, was 46,015,519 Trust Units for 2003 comparedto 34,135,576 for 2002. During the year, 360,608 Trust Units were issued pursuant to the Unit Appreciation Rights Plan for employees. During the year, PrimeWest completed 2 bought deal financings. The first closed on February 13, 2003 raising net proceeds of $146.6 million on the issuance of 6 million Trust Units at $25.75 per Trust Unit. Proceeds were used to reduce the indebtedness of PrimeWest under its credit facility, including a portion incurred in connection with the January 2003 acquisitionof two private Canadian exploration and production companies with properties in the Caroline and Peace River Arch areas of Alberta. The second financing closed on September 26, 2003 raising net proceeds of $76.1 million on the issuance of 3.1 million Trust Units at $25.90 per Trust Unit. Proceeds were used to reduce bank indebtedness and pursue development opportunities in the Caroline, Valhalla and Brant Farrow areas. PrimeWest issued 465,969 Trust Units for $11.4 million pursuant to the Distribution Reinvestment component (476,106 Trust Units, $10.1 million in 2002), 134,629 Trust Units for $3.4 million pursuant to the Premium Distribution component (0 Trust Units in 2002) and 721,209 Trust Units for $17.6 million pursuant to the Optional Trust Unit Purchase Plan component (OTUPP) in 2003 (503,103 Trust Units, $13.9 million in 2002). For the first time in PrimeWest's history, the OTUPP sold out before the end of the calendar year, demonstrating the strong support of existing unitholders. During the fourth quarter, PrimeWest enhanced its existing plan with the Premium Distribution (PREP) component. As an alternative to the existing DRIP Component of the Plan, the new 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 gives Canadian unitholders the chance to reinvest their monthly distributions at a 5%discount to the 20 day 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 20 day volume weighted average market price. The DRIP and PREP components are mutually exclusive, and participation in the OTUPP requires enrollment in either the DRIP or PREP. These plan components benefit the unitholders by offering alternatives to maximize their investment in PrimeWest, while providing the Trust with an inexpensive method to raise additional capital. The Trust expects interest in these plans in 2004 to be similar to 2003. Proceeds from these plans are used for debt reduction of PrimeWest's credit facility and to help fund ongoing capital development programs. In 2003 PrimeWest completed a review of the requirements necessary for the establishment of a U.S. DRIP program and concluded that such a program for U.S. resident unitholders is not presently feasible. For additional information or to join these plans, 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/. 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. In 2002 1,363,714 exchangeable shares were issued in connection with the management internalization transaction. During 2003, 1,500,000 exchangeable shares were issued in relation to the termination of the management incentive program of PrimeWest Management Inc. (see Note 11 in the Consolidated Financial Statements). 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 December 31, 2003, there were 3,041,123 exchangeable shares outstanding. The exchange ratio on these shares was 0.44302 Trust Units for each exchangeable share as at year-end. For purposes of calculating basic per Trust Unit amounts, these exchangeable shares have been assumed to be exchanged into Trust Units at the current exchange ratio. CASH DISTRIBUTIONS Cash distributions to unitholders are at the discretion of the Board of Directors and can fluctuate depending on the cash flow generated from operations. As discussed previously, the cash flow available for distribution is dependent upon many factors including commodity prices, production levels, debt levels, capital spending requirements, and factors in the overall environment. In 2003, cash distributions totaled $192.6 million, or $4.40 per Trust Unit, compared to $158.0 million, or $4.80 per Trust Unit in 2002. Since inception in October of 1996 to December 31, 2003, PrimeWest has distributed $39.92 per Trust Unit;just under the initial public offering price of $40.00 (through December 31, 2002 - $35.92 per Trust Unit). In June, 2003 PrimeWest's Board of Directors announced its intention to distribute 70-90% of cash flow, as opposed to the Trust's historical 95%average annual payout ratio. Withholding some internally generated cash increases PrimeWest's financial flexibility. Payments to U.S. unitholders are subject to 15% Canadian withholding tax, which applies to the taxable portion of the distribution. CASH FLOW SENSITIVITIES The table below is designed to provide the directional impact on 2004 annual cash available for distribution per unit (increase/decrease) depending on changes in the following: $ per Trust Unit(1) ------------------------------------------------------------------------- Crude oil price ($US 1.00/bbl WTI increase) 0.07 Natural gas price ($0.10/mcf increase) 0.06 Exchange rate ($US 0.01 decrease) 0.07 Interest rate (1% decrease) 0.01 Production (1,000 BOE/day increase) 0.14 ------------------------------------------------------------------------- (1) Without the effect of price protection The figures in this table are provided for directional information only and are based on the units outstanding as at December 31, 2003. Should changes to commodity price, interest rate, exchange rate or production levels noted above take place, it should not be assumed that a corresponding change would be made to the distribution level. CONTRACTUAL OBLIGATIONS PrimeWest enters into many contract obligationsas 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 in2004, $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 Notes to the Consolidated Financial Statements), PrimeWest agreed to pay $3.5 million in exchangeable shares pursuant to a special employee retention plan. Onequarter 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 December 31, 2003 $0.5 million has been accrued in non-cash general and administrative expenses related to the special employee retention plan. RECENT ACCOUNTING PRONOUNCEMENTS ISSUED BUT NOT IMPLEMENTED During 2003, the following new or amended standards and guidelines were issued: Hedging Transactions The CICA has issued Accounting Guideline 13, "Hedging Relationships," (AcG 13) which will be 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. The Trust does not anticipate applying hedge accounting to its hedging relationships. Asset Retirement Obligations In March 2003, the CICA issued a new section in the CICA Handbook, section 3110, Asset Retirement Obligations. This standard focuses on the recognition and measurement of liabilities related to legal obligations associated with the retirement of property, plant and equipment. Under this standard, these obligations are initially measured at fair value and subsequently adjusted for the accretion of discount and any changes in the underlying cash flows. The asset retirement cost is to be capitalized to the related asset and amortized into earnings over time. This section comes into effect for the Trust in 2004. The Trust is currently evaluating the impact of this standard on its consolidated financial statements and does not anticipate it will have a material impact. Oil and Gas Assets - Full Cost Accounting In 2003, the CICA issued Accounting Guideline 16 impacting 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 testis 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 company's risk free rate. The guideline requires disclosure of the prices used for purposes of the impairment test. The impact of this new guideline on the Trust would be an impairment to capital assets of $460 million before tax or $300 million after tax. The after tax impairment of $300 million will be booked to retained earnings in the first quarter of 2004. Exchangeable Share Accounting In November 2003 the CICA issued a draft EIC (D37) on "Income Trusts - Exchangeable Units". The EIC proposes that the retained interest of the exchangeable shareholders should be presented on the balance sheet as a non-controlling interest separate and distinct from unitholder's equity. This draft EIC is currently under review and was not enacted in final form as of the time of publication of the Trust's consolidated financial statements. Variable Interest Entities In June 2003 the CICA issued Accounting Guideline 15 "Consolidation of Variable Interest Entities" which deals with the consolidation of entities that are subject to control on a basis otherthan ownership of voting interests. This guideline is effective for annual and interim periods beginning on or after November 1, 2004. The Trust has assessed that this new guideline is not applicable based on the current structure of the Trust and therefore will have no impact on the financial statements of the Trust. BUSINESS RISKS PrimeWest's operations are affected by a number of underlying risks, both internal and external to the Trust. These risks are similar to those affecting others in both the conventional oil and gas royalty trust sector and the conventional oil and gas producers sector. The Trust's financial position, results of operations, and cash available for distribution to unitholders are directly impacted by these factors. These factors are discussed under two broad categories - Commodity Price, Foreign Exchange and Interest Rate Risk; and Operational and Other Business Risks. Commodity Price, Foreign Exchange And Interest Rate Risk The two most important factors affecting the level of cash distributions available to unitholders are the level of production achieved by PrimeWest, and the price received for its products. These prices are influenced in varying degrees by factors outside the Trust's control. Some of these factors include: - world market forces, specifically the actions of OPEC and other large crude oil producing countries including Russia, and their implications on the supply of crude oil; - world and North American economic conditions which influence the demand for both crude oil and natural gas and the level of interest rates set by the governments of Canada and the U.S.; - weather conditions that influence the demand for natural gas and heating oil; - the Canadian/U.S. exchange rate that affects the price received for crude oil as the price of crude oil is referenced in U.S. dollars; - transportation availability and costs; and - price differentials among world and North American markets based on transportation costs to major markets and quality of production. To mitigate these risks, PrimeWest has an active hedging program in place based on an established set of criteria that has been approved by the Board of Directors. The results of the hedging program are reviewed against these criteria and the results actively monitored by the Board. Beyond our hedging strategy, PrimeWest also mitigates risk by having a well-diversified marketing portfolio and by transacting with a number of counter-parties and limiting exposure to each counter-party. In 2003, approximately 25% of natural gas production was sold to aggregators and 75% into the Alberta short-term or export long-term markets. The contracts that PrimeWest has with aggregators vary in length. They represent a blend of domestic and U.S. markets and fixed and floating prices designed to provide price diversification to our revenue stream. The primary objective of our commodity risk management program is to reduce the volatility of our cash distributions, to lock in the economics on major acquisitions and to protect our capital structure when commodity prices cycle downwards. In 2003, PrimeWest lost $30.5 million from commodity hedges ($0.66 per trust unit), while in 2002,PrimeWest added $28.1 million ($0.82 per Trust Unit) to our cash flow through various physical and financial hedging transactions. Over the three year period 2001 to 2003, PrimeWest's hedging program has added $37.1 million to revenue. Operational AndOther Business Risks PrimeWest is also exposed to a number of risks related to its activities within the oil and gas industry that also have an impact on the amount of cash available to unitholders. These risks, and the ways 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 2003 Hedging Results 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 suchas 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 too much 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, GLJ. The work and independence of GLJ is reviewed by the Audit andReserves Committee of the Board of Directors of PrimeWest. Our strategy is to invest in mature, longer life properties having a higher proved producing component where the reserve risk is generally lower and cash flows are more stable and predictable. Environmental Health and Safety (EH&S) -------------------------------------- Environmental, health and safety risks associated with oil and gas properties and facilities. We mitigate by: Establishing and adhering to strict guidelines for EH&S including training, proper reporting of incidents, supervision and awareness. PrimeWest has active community involvement in field locations including regular meetings with stakeholders in the area. PrimeWest carries adequate insurance to cover property losses, liability and business interruption. These risks are reviewed regularly by the Corporate Governance and Nominating Committee of the Board, which acts as PrimeWest's Environmental, Health and Safety Committee. Regulation, Tax and Royalties ----------------------------- Changes in government regulations including reporting requirements, income tax laws, operating practices and 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. All of the oil and gas business operations of PrimeWest are conducted by PrimeWest Energy Inc. PrimeWest Energy Inc. has a vigorous EH&S program as well as significant insurance protection. INCOME TAXES - UNITHOLDERS - 2003 For the 2003 taxation year, Canadian unitholders of PrimeWest were paid $4.40 Canadian per Trust Unit in distributions. Of this distribution amount, 42% or $1.85 per Trust Unit is deemed a tax deferred return of capital, and 58% or $2.55 per Trust Unit is taxable to unitholders as other income (taxed at the same rate as interest income). For unitholders resident in the United States, the taxability of distributions is calculated using U.S. tax rules which allow for the deduction of crown royalties and accounting based depletion. As a result of these deductions, none of the 2003 distribution is taxable as dividends and 100% of the 2003 distributions are atax deferred return of capital. A 15% withholding tax applies to distributions paid to U.S. unitholders. Further details regarding the withholding tax is available on PrimeWest's website at http://www.primewestenergy.com/. For both Canadian and UnitedStates unitholders, the tax deferred return of capital portion reduces the unitholder's adjusted cost base for purposes of calculating a capital gain or loss upon ultimate disposition of their Trust Units. Unitholders contemplating a disposition may wish to consult the "Unitholder Info" section on PrimeWest's website and use the adjusted cost base calculator. QUARTERLY PERFORMANCE 2003 2002 ------------------------------------------------------ ($ millions, except per Trust Unit amounts) Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 ------------------------------------------------------------------------- Net Revenues 94.0 85.6 77.273.1 69.4 62.3 63.8 68.8 Net Income 22.1 61.7 7.3 (0.7) 6.0 (6.2) 8.2 (7.4) Income Per Unit 0.52 1.35 0.16 (0.10) 0.20 (0.05) 0.24 (0.20) ------------------------------------------------------------------------- The above table highlights PrimeWest's quarterly performance for the years ended 2003 and 2002. Net revenues were primarily impacted by higher commodity prices and production volumes in 2003. Net income was higher in 2003 as a result of foreign exchange gains along with increased tax recoveries. FOURTH QUARTER AND YEAR END 2003 CONFERENCE CALL AND WEBCAST PrimeWest will be conducting a conference call and Web cast for interested analysts, brokers, investors and media representatives about its fourth quarter and year end 2003 results at 9:00 a.m. Mountain time (11:00 a.m. Eastern time) on February 20th, 2004. Callers may dial 800-814-3911 a few minutes prior to start and request the PrimeWest conference call. The call also will be available for replay by dialing 1-877-289-8525, and entering pass code 21028779 followed by the pound key. Webcast listeners are invited to go to http://www.newswire.ca/en/webcast/viewEvent.cgi?eventID(equal sign)701580 for the live Web cast and/or replay or access the Web cast at the PrimeWest website, http://www.primewestenergy.com/. QUESTIONS PrimeWest Energy Trust 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 on the Internet at our website, http://www.primewestenergy.com/. We make every effort to reply within 2 business days, but during periods of heavy call volume, our response time may increase. On behalf of the Board of Directors: February 19, 2004 Don Garner President and Chief Executive Officer CONSOLIDATED BALANCE SHEETS As at December 31 (millions of dollars) 2003 2002 2001 ------------------------------------------------------------------------- ASSETS Current assets Cash and short term deposits $ 2.5 $ - $ - Accounts receivable 65.4 71.6 60.6 Prepaid expenses 6.5 9.8 9.1 Inventory 2.1 2.2 3.2 ------------------------------------------------------------------------- 76.5 83.6 72.9 Cash reserved for site restoration and reclamation (note 7) 8.2 - 0.7 Other assets (note 5) 0.2 14.4 - Deferred charges 1.3 - - Property, plant and equipment (note 4) 1,537.6 1,404.5 1,448.7 Goodwill (note 3) 56.1 - - ------------------------------------------------------------------------- $ 1,679.9 $ 1,502.5 $ 1,522.3 ------------------------------------------------------------------------- ------------------------------------------------------------------------- LIABILITIES AND UNITHOLDERS' EQUITY Current liabilities Bank overdraft $ - $ 3.1 $ 14.6 Accounts payable 26.7 43.1 26.2 Accrued liabilities 45.3 24.2 39.4 Accrued distributions to unitholders 10.3 13.9 12.0 Due to related company (note 11) - - 10.1 ------------------------------------------------------------------------- 82.3 84.3 102.3 Long-term debt (note 6) 250.1 225.0 195.0 Future income taxes (note 12) 310.1 339.9 362.6 Site restoration and reclamation provision 17.8 6.2 6.1 ------------------------------------------------------------------------- 660.3 655.4 666.0 UNITHOLDERS' EQUITY Net capital contributions (note 8) 1,565.9 1,300.0 1,152.6 Capital issued but not distributed 5.2 0.9 1.0 Long-term incentive plan equity (note 9) 14.6 10.0 7.9 Accumulated income 213.5 123.2 122.6 Accumulated cash distributions (771.5) (578.9) (421.0) Accumulated dividends (8.1) (8.1) (6.8) ------------------------------------------------------------------------- 1,019.6 847.1 856.3 ------------------------------------------------------------------------- $ 1,679.9 $ 1,502.5 $ 1,522.3 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Commitments and Contingencies (Note 14) The accompanying notes form an integral part of these financial statements. CONSOLIDATED STATEMENTS OF UNITHOLDERS' EQUITY For the years ended December 31 (millions of dollars) 2003 2002 2001 ------------------------------------------------------------------------- Unitholders' equity, beginning of year $ 847.1 $ 856.3 $ 298.6 Net income for the year 90.3 0.6 79.5 Net capital contributions 265.9 147.4 717.2 Capital issued but not distributed 4.3 (0.1) 0.4 Long-term incentive plan equity 4.6 2.1 (1.0) Cash distributions (192.6) (158.0) (234.4) Dividends - (1.2) (4.0) ------------------------------------------------------------------------- Unitholders' equity, end of year $ 1,019.6 $ 847.1 $ 856.3 ------------------------------------------------------------------------- ------------------------------------------------------------------------- CONSOLIDATED STATEMENTS OF CASH FLOW For the years ended December 31 (millions of dollars) 2003 2002 2001 ------------------------------------------------------------------------- OPERATING ACTIVITIES Net income for the year $ 90.3 $ 0.6 $ 79.5 Add/(deduct): Items not involving cash from operations Depletion, depreciation and amortization 207.3 182.0 159.3 Non-cash general & administrative 14.4 6.1 4.2 Non-cash foreign exchange gain (12.1) - - Non-cash management fees - 1.4 1.8 Non-cash internalization - 13.1 - Future income taxes recovery (83.0) (32.3) (30.3) Other non-cash items (0.3) - - ------------------------------------------------------------------------- Cash flow from operations 216.6 170.9 214.5 Expenditures on site restoration and reclamation (2.2) (3.9) (3.7) Change in non-cash working capital 5.3 (10.7) (20.5) ------------------------------------------------------------------------- $ 219.7 $ 156.3 $ 190.3 ------------------------------------------------------------------------- FINANCING ACTIVITIES Proceeds from issue of Trust Units (net of costs) $ 240.3 $ 118.3 $ 159.5 Net cash distributions to unitholders (note 10) (172.5) (145.1) (222.7) Dividends - (1.2) (0.6) Increase (decrease) in bank credit facilities (137.0) 29.9 (62.9) Increase in senior secured notes 174.0 - - Increase in deferred charges (1.5) - - Change in non-cash working capital (3.6) 1.0 1.0 ------------------------------------------------------------------------- $ 99.7 $ 2.9 $ (125.7) ------------------------------------------------------------------------- INVESTING ACTIVITIES Expenditures on property, plant & equipment $ (105.8) $ (69.1) $ (84.2) Acquisition of capital / corporate assets (210.1) (59.6) (84.1) Proceeds on disposal of property, plant & equipment 2.3 4.5 78.1 (Increase) decrease in cash reserved for future site restoration and reclamation (6.6) 0.7 (0.3) Expenditures on future acquisitions - (14.1) - Change in non-cash working capital 6.4 (10.1) 12.1 ------------------------------------------------------------------------- $ (313.8) $ (147.7) $ (78.4) ------------------------------------------------------------------------- INCREASE (DECREASE) IN CASH FOR THE YEAR $ 5.6 $ 11.5 $ (13.8) BANK OVERDRAFT BEGINNING OF THE YEAR (3.1) (14.6) (0.8) ------------------------------------------------------------------------- CASH (BANK OVERDRAFT) END OF THE YEAR $ 2.5 $ (3.1) $ (14.6) ------------------------------------------------------------------------- ------------------------------------------------------------------------- CASH INTEREST PAID $ 13.1 $ 10.3 $ 13.2 ------------------------------------------------------------------------- ------------------------------------------------------------------------- CASH TAXES PAID $ 3.9 $ 4.0 $ 0.5 ------------------------------------------------------------------------- ------------------------------------------------------------------------- CONSOLIDATED STATEMENTS OF INCOME For the years ended December 31 (millions of dollars, except for per Trust Unit amounts) 2003 2002 2001 ------------------------------------------------------------------------- ------------------------------------------------------------------------- REVENUES Sales of crude oil, natural gas and natural gas liquids $ 434.6 $ 320.5 $ 378.2 Crown and other royalties, net of ARTC (101.9) (56.5) (73.2) Other income (2.8) 0.3 1.5 ------------------------------------------------------------------------- 329.9 264.3 306.5 ------------------------------------------------------------------------- EXPENSES Operating 79.4 60.8 59.0 Cash general and administrative 14.5 11.3 10.4 Non-cash general and administrative 14.4 6.1 4.2 Interest 15.1 10.8 13.8 Cash management fees (note 11) - 4.0 6.4 Cash internalization costs - 3.6 - Non-cash management fees (note 11) - 1.4 1.8 Non-cash internalization costs (note 11) - 13.1 - Foreign exchange (gain)/loss (11.9) - - Depletion, depreciation and amortization 207.3 182.0 159.3 ------------------------------------------------------------------------- 318.8 293.1 254.9 ------------------------------------------------------------------------- Income (loss) before taxes for the year 11.1 (28.8) 51.6 ------------------------------------------------------------------------- Income and capital taxes 3.8 2.9 2.4 Future income taxes recovery (note 12) (83.0) (32.3) (30.3) ------------------------------------------------------------------------- (79.2) (29.4) (27.9) ------------------------------------------------------------------------- Net income for the year $ 90.3 $ 0.6 $ 79.5 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Net income per Trust Unit $ 1.96 $ 0.02 $ 3.12 Diluted net income per Trust Unit $ 1.95 $ 0.02 $ 3.08 ------------------------------------------------------------------------- ------------------------------------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (all amounts areexpressed in millions of Canadian dollars unless otherwise indicated) 1. Structure Of The Trust -------------------------- PrimeWest Energy Trust (the Trust) is an open-ended investment trust formed under the laws of Alberta in accordancewith a declaration of trust dated August 2, 1996, as Amended. The beneficiaries of the Trust are the holders of Trust Units (the unitholders). The principal undertaking of the Trust's operating companies, PrimeWest Energy Inc. and PrimeWest Gas Corp. (collectively referred to as PrimeWest), is to acquire and hold, directly and indirectly, interests in oil and gas properties. One of the Trust's primary assets is a royalty entitling it to receive 99% of the net cash flow generated by theoil and gas interests owned by PrimeWest. The royalty acquired by the Trust effectively transfers substantially all of the economic interest in the properties to the Trust. The common shares of PrimeWest Energy Inc. are 100% owned by the Trust. PrimeWest Gas Corp. is a wholly owned subsidiary of PrimeWest Energy Inc. On November 4, 2002, unitholders voted, by a 92% majority, to internalize management. PrimeWest Management Inc. and its shareholders received a total of $26.3 million in connection with that transaction. Approximately $13.2 million related to the acquisition of the 1% retained royalty and was recorded as an acquisition in property, plant and equipment. The balance was charged to non-cash internalization expense.In addition, retention provisions for senior management totaling $3.5 million were agreed to and $1.5 million was accrued relating to the termination of the management incentive program (see Note 11). 2. Accounting Policies ----------------------- Consolidation These consolidated financial statements include the accounts of the Trust and its wholly-owned subsidiaries, PrimeWest Energy Inc and PrimeWest Gas Corp. The Trust, through the royalty, obtains substantially all of the economic benefits of the operations of PrimeWest. Cash And Short Term Investments Short term investments, with maturities less than three months at the date of acquisition, are considered to be cash equivalents and are recorded at cost, which approximates market value. Inventory Inventory is measured at lower of cost and net realizable value. Goodwill Goodwill represents the excess of purchase price over fair value of net assets acquired and liabilities assumed. Goodwill is assessed for impairment at least annually. To assess impairment, the fair value of each reporting unit is determined and compared to the book value of the reporting unit. The amount of the impairment is determined by deducting the fair value of the reporting unit's assets and liabilities from the fair value of the reporting unit to determine the implied fair value of goodwill and comparing that amount to the book value of the reporting unit's goodwill. Any excess of the book value of goodwill over the implied fair value of goodwill is the impairment amount. Property, Plant And Equipment PrimeWest follows the full cost method of accounting. All costs of acquiring oil and gas properties and related development costs are capitalized and accumulated in one cost centre. Maintenance and repairs are charged against earnings. Renewals and enhancements that extend the economic life of the capital asset are capitalized. Gains and losses are not recognized on disposition of oil and gas properties unless that disposition would alter the rate of depletion by 20% or more. i) Ceiling test --------------- PrimeWest places a limit on the aggregate cost of capital assets which may be carried forward for depletion against netrevenues of future periods (the ceiling test). The ceiling test is a cost recovery test whereby; capitalized costs, less accumulated depletion and site restoration, the lower of cost and market value of unproved land and future income taxes, are limited to an amount equal to estimated undiscounted future net revenues from Proved reserves, less general and administrative expenses, site restoration, future financing costs and applicable income taxes. Costs and prices at the balance sheet date are used. Any costs carried on the balance sheet in excess of the ceiling test limitation are charged to income. ii) Site restoration and reclamation provision ---------------------------------------------- PrimeWest provides for the cost of future site restoration and reclamation, based on estimates by management, using the unit-of-production method. Actual site restoration costs are charged against the accumulated liability. PrimeWest places cash in reserve to fund actual expenditures as they are incurred. iii) Depletion, depreciation and amortization --------------------------------------------- Provision for depletion and depreciation is calculated on the unit-of-production method, based on Proved reserves beforeroyalties. Reserves are estimated by independent petroleum engineers. Reserves are converted to equivalent units on the basis of approximate relative energy content. Depreciation and amortization of head office furniture and equipment is provided for at rates ranging from 10% to 30%. Joint Venture Accounting PrimeWest conducts substantially all of its oil and gas production activities through joint ventures, and the accounts reflect only PrimeWest's proportionate interest in such activities. Long-Term Incentive Plan Liabilities under the Trust's Long-term Incentive Plan are estimated at each balance sheet date, based on the amount of Unit Appreciation Rights that are in the money using the unit price as at that date. Expenses are recorded through non-cash general and administrative costs, with an offsetting amount in long-term incentive plan equity. As Trust Units are issued under the plan, the exercise value is recorded in net capital contributions. Income Taxes The Trust is considered an inter-vivos trust for income tax purposes. As such, the Trust is subject to tax on any taxable income that is not allocated to the unitholders. Periodically, current taxes may be payable by PrimeWest, depending upon the timing of income tax deductions. Should these taxes prove to be unrecoverable, they will be deducted from royalty income in accordance with the royalty agreement. Future income taxes are recorded for PrimeWest using the liability method of accounting. Future income taxes are recorded to the extent that the carrying value of PrimeWest's capital assets exceeds the available tax pools. Financial Instruments PrimeWest uses financial instruments to manage its exposure to fluctuations in commodity prices and interest rates. PrimeWest does not use financial instruments for speculative trading purposes and, accordingly, they are accounted for as hedges. Gains and losses on hedging activity are reflected in revenue, or in the case of interest rate hedges, in interest expense, at the time of sale of the related hedged production, or when the monthly exchange contracts expire. Measurement Uncertainty Certain items recognized in the financial statements are subject to measurement uncertainty. The recognized amounts of such items are based on PrimeWest's best information and judgment. Such amounts are not expected to change materially in the near term. They include the amounts recorded for depletion, depreciation and future site restoration costs which depend on estimates of oil and gas reserves or the economic lives and future cash flows from related assets. 3. Corporate Acquisitions -------------------------- a) On January 23, 2003, PrimeWestGas Inc. completed the acquisition of two private Canadian oil and gas companies. Subsequent to the transaction, PrimeWest Gas Inc. was wound up into PrimeWest Energy Inc. The acquired companies were 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 Consideration Assigned Values Paid ------------------------------------------------------------------------- Petroleum and natural gas assets $ 220.9 Goodwill 56.1 Working capital, including cash of $3.9 0.7 Site restoration provision (5.4) Cash $ 212.7 Future income taxes (53.2) Costs associated with acquisition 6.4 ------------------------------------------------------------------------- $ 219.1 $ 219.1 ------------------------------------------------------------------------- ------------------------------------------------------------------------- b) On March 29, 2001, PrimeWest Oil & Gas Corp. (Oil & Gas) completed the acquisition of all of the issued and outstanding shares of Cypress Energy Inc. (Cypress) pursuant to a takeover bid. In aggregate, PrimeWest issued 50.2 million Trust Units and PrimeWest issued 5.2 million exchangeable shares of Oil & Gas and paid $59.2 million in exchange for the shares of Cypress. Subsequent to the transaction, Cypress and Oil & Gas were amalgamated. On January 1, 2002, PrimeWest Oil and Gas Corp. and PrimeWest Energy Inc. were amalgamated. The acquisition was accounted for using the purchase method of accounting with net assets acquired and consideration paid as follows: Net Assets Acquired at Consideration Assigned Values Paid ------------------------------------------------------------------------- Petroleum and natural gas assets $ 1,201.5 Working capital deficit assumed (19.2) Cash $ 59.2 Long-term debt assumed (179.0) Trust Units issued 489.8 Site restoration provision (4.3) Exchangeable shares issued 50.3 Futureincome taxes (376.3) Costs associated with acquisition 23.4 ------------------------------------------------------------------------- $ 622.7 $ 622.7 ------------------------------------------------------------------------- ------------------------------------------------------------------------- 4. Property, Plant and Equipment --------------------------------- 2003 ----------------------------------------- Accumulated depletion depreciation and Net book Cost amortization value ----------------------------------------- Property acquisition oil and gas rights $ 1,917.4 $ (607.0) $ 1,310.4 Drilling and completion 208.0 (52.1) 155.9 Production facilities and equipment 91.0 (23.1) 67.9 Head office furniture and equipment 8.0 (4.6) 3.4 ------------------------------------------------------------------------- $ 2,224.4 $ (686.8) $ 1,537.6 ------------------------------------------------------------------------- ------------------------------------------------------------------------- 2002 ----------------------------------------- Accumulated depletion depreciation and Net book Cost amortization value ----------------------------------------- Property acquisition oil and gas rights $ 1,682.6 $ (430.6) $ 1,252.0 Drilling and completion 139.9 (34.7) 105.2 Production facilities and equipment 60.5 (15.4) 45.1 Head office furniture and equipment 5.2 (3.0) 2.2 ------------------------------------------------------------------------- $ 1,888.2 $ (483.7) $ 1,404.5 ------------------------------------------------------------------------- ------------------------------------------------------------------------- 2001 ----------------------------------------- Accumulated depletion depreciation and Net book Cost amortization value ----------------------------------------- Property acquisition oil and gas rights $ 1,608.4 $ (268.1) $ 1,340.3 Drilling and completion 103.6 (24.1) 79.5 Production facilities and equipment 38.2 (11.5) 26.7 Head office furniture and equipment 4.2 (2.0) 2.2 ------------------------------------------------------------------------- $ 1,754.4 $ (305.7) $ 1,448.7 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Unproved land costs of $ 36.0 million (2002 - $44.2 million, 2001 - $55.7 million) are excluded from costs subject to depletion and depreciation. PrimeWest capitalized $2.5 million of general and administrative costs in 2003 ($2.5 million in 2002; $2.2 million in 2001). In accordance with stated accounting policies, PrimeWest has performed a ceiling test using commodity prices as at the measurement date of December 31, 2003. Using December 31, 2003 commodity prices of AECO $6.09 per mcf for natural gas and WTI $US 32.52 per barrel for crude oil, results in a ceiling test surplus. A ceiling test surplus existed as at December 31, 2002. At December 31, 2001, PrimeWest performed its ceiling test using commodity prices as at that measurement date of AECO $3.67 per mcf for natural gas, and WTI $U.S. 19.84 per barrel for crude oil. The ceiling test resulted in a deficiency of $150 million. PrimeWest did not record a write-down at that time as the write-down occurred within the first two years of the acquisition of Cypress Energy Inc. 5. Other Assets ---------------- 2003 2002 2001 ----------------------------------------- Deposit on acquisition $ - $ 10.9 $ - Expenditures incurred on acquisition - 3.3 - Other assets 0.2 0.2 - ------------------------------------------------------------------------- $ 0.2 $ 14.4 $ - ------------------------------------------------------------------------- ------------------------------------------------------------------------- 6. Long-Term Debt ------------------ 2003 2002 2001 ----------------------------------------- Revolving credit facility $ 88.0 $ 225.0 $ 195.0 Senior secured notes 162.1 - - ------------------------------------------------------------------------- 250.1 225.0 195.0 ------------------------------------------------------------------------- ------------------------------------------------------------------------- PrimeWest and the Trust (as co-borrowers) have combined revolving credit facilities in the amount of $213 million (2002 - $335 million; 2001 - $350 million), with a borrowing base at December 31, 2003 of $390 million (2002 - $335 million; 2001 - $350 million). The facilities consists of a revolving term loan of $188 million and an operating facility of $25 million. In addition to amounts outstanding under the facilities as indicated in the table above, PrimeWest has outstanding letters of credit in theamount of $5.1 million (2002 - $3.8 million; 2001 - $2.8 million). Advances under the facility are made in the form of Banker's Acceptances (BA), prime rate loans or letters of credit. In the case of BA, interest is a function of the BA rate plus a stamping fee based on the Trust's current ratio of debt to cash flow. In the case of prime rate loans, interest is charged at the bank's prime rate. While any amounts are outstanding under the bridge facility, the interest rates and stamping fees increase by 50 basis points. For 2003, the effective interest rate was 4.7% (2002 - 4.6%, 2001 - 5.6%). The credit facility revolves until June 30, 2004, by which time the lenders will have conducted their annual borrowing base review. The lender also has the right to re-determine the borrowing base at one other time during the year. During the revolving phase, the facility has no specific terms of repayment. At the end of the revolving period, the lender has the right to extendthe revolving period for a further 364-day period or to convert the facility to a term facility. If the lender converts to a non-revolving facility, 60% of the aggregate principal amount of the loan shall be repayable on the date which is 366 days after such conversion date and the remaining 40% of the aggregate principal amount outstanding shall be repayable on the date which is 365 days after the initial term repayment date. On May 7, 2003, PrimeWest replaced a portion of its bank debt with Senior Secured Notes (the "Notes") in the amount of $U.S. 125 million. They have a final maturity of May 7, 2010, and bear interest at 4.19% per annum, with interest paid semi-annually on November 7 and May 7 of each year. The Note Purchase Agreement requires PrimeWest to make four annual principal repayments of $U.S. 31,250,000 commencing May 7, 2007. Collateral for the secured note and credit facility is a floating charge debenture covering all existing and after acquired property in the principal amount of $U.S. 1 billion. The secured parties for the revolving credit facility and senior secured notes have agreed to share the security interests on a pari passu basis. The costs incurred in connection with the Notes, in the amount of $1.5 million, are classified as deferred charges on the balance sheet and are being amortized over the term of the Notes. The Senior Secured Notes are the legal obligation of PrimeWest Energy Inc. and are guaranteed by PrimeWest Energy Trust. 7. Cash Reserve For Site Restoration And Reclamation ----------------------------------------------------- Commencing in 1998, funding for the reserve was provided for by reducing distributions otherwise payable based on an amount per BOE produced ($0.15 per BOE produced for 1998 and 1999, $0.24 per BOE produced in 2000, $0.32 per BOE produced in 2001, $0.37 per BOE produced in 2002 and $0.50 per BOE produced in 2003). The cash amount contributed, including interestearned, was $6.2 million in 2003 (2002 - $4.1 million; 2001 - $4.2 million). During 2003, an additional contribution of $4.2 million was made to fund reclamation expenditures associated with properties acquired in 2002. Actual costs of site restoration and abandonment totaling $2.2 million were paid out of this cash reserve for the year ended December 31, 2003 (2002 - $3.9 million; 2001 - $3.8 million). 8. Unitholders' Equity ----------------------- PrimeWest Energy Trust Theauthorized capital of the Trust consists of an unlimited number of Trust Units. Trust Units Number of Units Amounts ($) ------------------------------------------------------------------------- Balance, December 31, 2000 50,982,093 $ 428.0 Issued for cash 19,790,000 165.2 Issue expenses - (9.0) Issued to acquire Cypress Energy Inc. 50,234,771 489.8 Issued for payment of management fees 199,841 1.7 Issued on exchange of exchangeable shares 2,415,363 20.3 Issued pursuant to Distribution Reinvestment Plan 1,623,171 10.8 Issued pursuant to Long-Term Incentive Plan 577,840 5.2 Issued pursuant to Optional Trust Unit Purchase Plan 142,528 3.3 ------------------------------------------------------------------------- Balance, December 31, 2001 125,965,607 $ 1,115.3 Restated giving effect for 4 to 1 Trust Unit consolidation on August 16, 2002 31,491,402 $ - Issued for cash 4,200,000 $ 110.0 Issue expenses - (5.6) Issued for payment of management fees 66,853 1.8 Issued on exchange of exchangeable shares 106,934 2.7 Issued pursuant to Distribution Reinvestment Plan 476,106 10.1 Issued pursuant to Long-Term Incentive Plan 153,749 4.0 Issue of units due to odd lot program 111 - Issue of fractional units due to 4 to 1 consolidation 6,264 - Issued pursuant to Optional Trust Unit Purchase Plan 503,103 13.9 ------------------------------------------------------------------------- Balance, December 31, 2002 37,004,522 $ 1,252.2 Issued for cash 9,100,000 $ 234.8 Issue expenses - (12.1) Issued on exchange of exchangeable shares 964,897 21.2 Issued pursuant to Distribution Reinvestment Plan 600,598 14.8 Issued pursuant to Long-Term Incentive Plan 360,608 9.4 Issue of units due to odd lot program 38 - Issue of fractional units due to 4 to 1 consolidation 11 - Issued pursuant to Optional Trust Unit Purchase Plan 721,209 17.6 ------------------------------------------------------------------------- Balance, December 31, 2003 48,751,883 $ 1,537.9 ------------------------------------------------------------------------- ------------------------------------------------------------------------- The number of units was restated giving effect of four for one Trust Unit consolidation effective August 16, 2002. The weighted average number of Trust Units and exchangeable shares outstanding in 2003 was 46,015,519 (2002 - 34,135,576; 2001 - 25,633,271). For purposes of calculating diluted net income per Trust Unit, 345,278 Trust Units (2002 - 341,315; 2001 - 311,789) 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 declaredto Trust Units outstanding on the record dates. PrimeWest Exchangeable Class A Shares In connection with the Cypress transaction (see Note 3b), PrimeWest Oil & Gas Corp. (now amalgamated with PrimeWest Energy Inc.) amended its articles to create an unlimited number of exchangeable 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 distribution to its unitholders. The exchange ratio, which was 1:1 on the date that the transaction closed, is based on the total monthly distribution, divided by the closing unit price on the distribution payment date. The exchange ratio on December 31, 2003 was 0.44302:1 (2002 - 0.37454:1; 2001 - 0.3126:1, restated effecting 4 to 1 Trust Unit consolidation). Exchangeable Shares No. of shares Amounts ($) ------------------------------------------------------------------------- Balance,December 31, 2001 3,316,742 $ 32.3 Issued for internalization 1,363,714 13.1 Conversion of Class B shares 710,795 4.3 Exchanged for Trust Units (211,973) (2.0) ------------------------------------------------------------------------- Balance, December 31, 2002 5,179,278 47.7 Issued for management incentive program 161,717 1.5 Exchanged for Trust Units (2,299,872) $ (21.2) ------------------------------------------------------------------------- Balance, December 31, 2003 3,041,123 $ 28.0 ------------------------------------------------------------------------- ------------------------------------------------------------------------- PrimeWest Exchangeable Class B Shares In connection with a transaction in 2000, PrimeWest Resources Ltd. (now amalgamated with PrimeWest Energy Inc.) amended its articles to create an unlimited number of exchangeable shares. At special meetings held in May and June of 2002, holders of Class B Exchangeable Shares and Class A Exchangeable shares voted to approve a special resolution amending the articles of the Corporation to convert all Class B Exchangeable shares to Class A Exchangeable Shares. As at June 14, 2002, 649,561 Class B Exchangeable shares were converted to Class A Exchangeable Sharesusing an exchange ratio of 1.09427:1. Exchangeable Shares No. of shares Amounts ($) ------------------------------------------------------------------------- Balance, December 31, 2001 751,532 $ 5.0 Exchanged for Trust Units (101,971) (0.7) Converted to Class A Exchangeable Shares (649,561) (4.3) ------------------------------------------------------------------------- Balance, December 31, 2002 - $ - ------------------------------------------------------------------------- ------------------------------------------------------------------------- Trust Units and Exchangeable Shares Issued & Outstanding(1) 2003 2002 2001 ----------------------------------------- Trust Units issued & outstanding 48,751,883 37,004,522 31,491,402 Exchangeable shares Class A Shares (2003 - 3,041,123 shares exchangeable at 0.44302; 2002 - 5,179,278 shares exchangeable at 0.37454; 2001 - 3,316,742 shares exchangeable at 0.3126) 1,347,277 1,939,864 1,036,648 Class B Shares (2001 - 751,532 shares exchangeable at 0.34201) - - 257,035 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Total units and exchangeable shares issued & outstanding 50,099,160 38,944,386 32,785,085 Unit Appreciation Rights 345,278 341,315 311,788 ------------------------------------------------------------------------- Total units and exchangeable shares issued & outstanding - diluted 50,444,438 39,285,701 33,096,873 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Restated Trust Units to give effect to 4 for 1 unit consolidation effective August 16, 2002. 9. Trust Unit Incentive Plan ----------------------------- Under the terms of the Trust Unit 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 December 31, 2003 ------------------------------------------------------------------------- Current return Trust Year UARs issued per "in the Total Unit of Grant & outstanding UARs vested money" UARs equity dilution ------------------------------------------------------------------------- 1998 10,391 10,391 $ 49.98 $ 0.5 18,844 1999 55,160 55,160 34.92 1.9 69,892 2000 120,137 119,387 16.40 2.0 71,007 2001 383,424 265,645 7.81 3.0 74,891 2002 961,405 447,562 6.09 4.7 86,694 2003 1,085,031 141,896 4.75 2.5 23,950 ------------------------------------------------------------------------- Total 2,615,548 1,040,041 $ 14.6 345,278 ------------------------------------------------------------------------- ------------------------------------------------------------------------- As at December 31, 2002 ------------------------------------------------------------------------- Current return Trust Year UARs issued per "in the Total Unit of Grant & outstanding UARs vested money" UARs equity dilution ------------------------------------------------------------------------- 1997 52,927 52,927 $ 22.98 $ 1.2 47,883 1998 105,798 105,798 33.99 3.6 141,563 1999 115,215 114,667 22.38 2.6 101,076 2000 187,984 125,661 8.22 1.5 37,831 2001 515,634 185,780 2.12 0.6 12,861 2002 1,120,142 82,097 1.97 0.5 101 ------------------------------------------------------------------------- Total 2,097,700 666,930 $ 10.0 341,315 ------------------------------------------------------------------------- ------------------------------------------------------------------------- As at December 31, 2001 ------------------------------------------------------------------------- Current return Trust Year UARs issued per "in the Total Unit of Grant & outstanding UARs vested money" UARs equity dilution ------------------------------------------------------------------------- 1996 131,719 131,719 $ 15.84 $ 2.1 82,010 1997 79,839 79,839 13.76 1.1 43,165 1998 127,956 127,957 24.80 3.2 124,654 1999 148,416 89,566 14.76 1.3 52,025 2000 240,914 86,951 2.92 0.2 9,935 2001 629,343 25,211 - - - ------------------------------------------------------------------------- Total 1,358,187 541,243 $ 7.9 311,789 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Cumulative to December 31, 2003, 1,030,850 UARs have been exercised (Cumulative to December 31, 2002 - 640,503; Cumulative to December 31, 2001 - 399,199), resulting in the issuance of 719,374 Trust Units from treasury (Cumulative to December 31, 2002 - 358,766; Cumulative to December 31, 2001 - 205,017). 10. Cash Distributions ---------------------- 2003 2002 2001 ------------------------------------------------------------------------- Netincome for the year $ 90.3 $ 0.6 $ 79.5 Add back (deduct) amounts to reconcile to distribution: Depletion, depreciation and amortization 207.3 182.0 159.3 Cash (retained) / paid from cash available for distribution (15.6) (7.3) 25.8 Contribution to reclamation fund (8.7) (4.1) (3.5) Non-cash general and administrative 14.4 6.14.2 Non-cash foreign exchange (12.1) - - Internalization costs paid in trust units - 13.1 - Management fees paid in Trust Units - 1.4 1.8 Future income taxes recovery (83.0) (32.3) (30.3) ------------------------------------------------------------------------- $ 192.6 $ 159.5 $ 236.8 Cash Distributions to Trust Unitholders $ 192.6 $ 158.0 $ 234.5 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Cash Distributions per Trust Unit $ 4.40 $ 4.80 $ 9.24 ------------------------------------------------------------------------- ------------------------------------------------------------------------- 11. Related - Party Transactions -------------------------------- On September 26, 2002, the Trust announced the planned elimination, effective October 1, 2002, of its external management structure and all related management, acquisition and disposition fees, as well as the acquisition of the right to mandatory quarterly dividends commonly referred to as the "1% retained royalty". The transaction was approved by the Unitholders and the holders of Exchangeable Shares on November 4, 2002 and closed November 6, 2002. The transaction resulted in the elimination of the 2.5% management fee on net production revenue, quarterly incentive payments payable in the form of Trust Units, the 1.5% acquisition fee and the 1.25% disposition fee, which resulted in payments to PrimeWest Management Inc. in 2002 totaling $5.8 million (2001 - $21.3 million). In addition, the amount of the 1% retained royalty paid in 2002 was $1.3 million (2001 - $3.4 million). As at December 31, 2002, the Trust and PrimeWest owed $nil (2001 - $10.1 million) to PrimeWest Management Inc. for unpaid management and other fees and reimbursement of general and administrative costs. The internalization transaction was achieved through the purchase by PrimeWest of all of the issued and outstanding shares of PrimeWest Management Inc. for a total consideration of approximately $26.3 million comprised of a cash payment of $13.2 million and the issuance of Exchangeable Shares exchangeable, based on an agreed exchange ratio, for approximately 491,000 Trust Units and valued at approximately $13.1 million based on the closing price of the Trust Units on the TSX on September 26, 2002. The $13.2 million that related to the acquisition of the 1% retained royalty was capitalized; an additional $9.5 million was capitalized with an offset to future tax liability as a result of the property, plant and equipment having no tax basis. In addition, PrimeWest agreed to issue Exchangeable Shares valued at $1.5 million to certain senior managers to terminate a management incentive program of PrimeWest Management Inc. and to create a special employee retention plan for those senior managers which provides for long term incentive bonuses in the form of Exchangeable Shares valued, in the aggregate, at $3.5 million. Exchangeable Shares will be issued pursuant to the retention plan on each of the second, third, fourth and fifth anniversaries of the completion of the internalization transaction. As at December 31, 2003, $0.5 million has been accrued in non-cash general and administrative expenses related to the special employee retention plan. 12. Income Taxes ---------------- PrimeWest and its subsidiaries had no taxable income for 2003, 2002, and 2001, as tax-pool deductions and the royalty payable were sufficient to reduce taxable income in these entities to nil. The future tax provision results from temporary differences between the financial statement carrying amounts of assets and liabilities and their respective tax bases. 2003 2002 2001 ------------------------------------------------------------------------- Loss carry forwards $ - $ (5.0) $ (10.6) Capital assets 318.9 350.0 378.0 Foreign exchange gain on long term debt 2.1 - - Site restoration provision (6.0) (1.9) (2.3) Long-term incentive liability (4.9) (3.2) (2.5) ------------------------------------------------------------------------- $ 310.1 $ 339.9 $ 362.6 ------------------------------------------------------------------------- ------------------------------------------------------------------------- The provisions for income taxes varies from the amounts that would be computed by applying the combined Canadian federal and provincial income tax rates for the following reasons: 2003 2002 2001 ------------------------------------------------------------------------- Net income (loss) before taxes $ 11.1 $ (28.8) $ 51.6 ------------------------------------------------------------------------- Computed income tax expense (recovery) at the Canadian statutory rate of 40.62% (2002 - 42.12%; 2001 - 43.12%) 4.5 (12.1) 22.3 Increase (decrease) resulting from: Non-deductible crown royalties and other payments, net of ARTC 0.3 5.7 0.2 Federalresource allowance (16.2) (3.5) (9.7) Change in income tax rate (43.1) (4.2) - Amounts included in trust income and other (28.5) (18.2) (43.1) ------------------------------------------------------------------------- Future income taxes $ (83.0) $ (32.3) $ (30.3) ------------------------------------------------------------------------- ------------------------------------------------------------------------- 13. Financial Instruments ------------------------- a) Commodity Price Risk Management 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 summary of these contracts in place at December 31, 2003 follows: CRUDE OIL Period Volume (bbls/d) Type WTI Price ($U.S./bbl) ------------------------------------------------------------------------- Jan - Jan 2004 500 Swap $ 33.30 Jan - Mar 2004 1000 Swap 27.29 Jan - Mar 2004 500 Swap 28.87 Jan - Mar 2004 500 Swap 30.21 Jan - Mar 2004 500 Swap 31.60 Jan - Mar 2004 500 Costless Collar 22.00/26.70 Jan - Mar 2004 500 Costless Collar 23.00/33.30 Jan - Mar 2004 500 Costless Collar 24.00/31.20 Jan - Mar 2004 500 Costless Collar 25.00/28.16 Apr - Jun 2004 1000 Swap 27.13 Apr - Jun 2004 500 Swap 28.64 Apr - Jun 2004 500 Swap 30.06 Apr - Jun 2004 500 Costless Collar 22.00/26.12 Apr - Jun 2004 500 Costless Collar 24.00/30.50 Apr - Jun 2004 500 Costless Collar 25.00/28.07 Apr - Jun 2004 500 Costless Collar 26.00/32.07 Jul - Sep 2004 500 Swap 26.07 Jul - Sep 2004 500 Swap 27.04 Jul - Sep 2004 500 Swap 28.51 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 Costless Collar 24.00/30.00 Oct - Dec 2004 500 Costless Collar 25.00/28.30 Jan 2005 - Mar 2005 500 Swap 27.25 Apr 2005 - Jun 2005 500 Swap 27.07 Jul 2005 - Sep 2005 500 Swap 27.05 ------------------------------------------------------------------------- ------------------------------------------------------------------------- NATURAL GAS (AECO) Period Volume (mmcf/day) Type AECO Price (Cdn$/mcf) ------------------------------------------------------------------------- Jan 2004 - Mar 2004 4.7 Swap $ 6.19 Jan 2004 - Mar 2004 4.7 3 Way 4.22/5.28/8.23 Jan 2004 - Mar 2004 4.7 3 Way 4.48/5.54/6.52 Jan 2004 - Mar 2004 4.7 Costless Collar 6.33/7.91 Jan 2004 - Mar 2004 4.7 Costless Collar 6.33/11.87 Jan 2004 - Mar 2004 4.7 Costless Collar 5.80/8.23 Jan 2004 - Mar 2004 4.7 Costless Collar 5.80/8.33 Jan 2004 - Mar 2004 4.7 Costless Collar 6.33/8.58 Jan 2004 - Mar 2004 4.7 Costless Collar 4.75/7.91 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 ------------------------------------------------------------------------- ------------------------------------------------------------------------- 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 $8.23, purchased a put at $5.28, and resold the put at $4.22. Should the market price drop below $5.28 PrimeWest will receive $5.28 until the price is less than $4.22, at which time PrimeWest would then receive market price plus $1.06. However, should market prices rise above $8.23, PrimeWest would receive a maximum of $8.23. Should the market price remain between $5.28 and $8.23, PrimeWest would receive the market price. NATURAL GAS (BASIS DIFFERENTIAL $US / MCF) Period Volume (mmcf/day) Type Basis Price ($US/mcf) ------------------------------------------------------------------------- Jan - Mar 2004 10.0 Basis Swap $ 0.63 Apr - Oct 2004 5.0 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 first basis swap above as an example, PrimeWest has fixed this price difference between the two markets at $U.S. 0.63 per mcf from January 2004 through March 2004. If the NYMEX price for the period turned out to be $U.S. 4.00 per mcf, PrimeWest would receive an AECO equivalent price of $U.S. 3.37 per mcf. In 2003, the financial impact of contracts settling in the year was a decrease in sales revenues of $30.5 million (2002 - $28.1 million increase in sales revenues; 2001 - $39.5 million increase in sales revenues). The mark-to-market value of the hedges in place as at December 31, 2003 is a $6.0 million loss of which $2.1 million is attributable to natural gas and $3.9 million is attributable to crude oil. Electrical Power Period Power Amount (MW) Type Price ($/MW-hr) ------------------------------------------------------------------------- Q1 2004 5 Fixed Price Swap $ 58.50 Q2 2004 7.5 Fixed Price Swap 40.25 Q3 2004 5 Fixed Price Swap 46.50 Q4 2004 5 Fixed Price Swap 44.00 Calendar 2004 5 Fixed Price Swap 45.65 ------------------------------------------------------------------------- ------------------------------------------------------------------------- The mark to market value of the hedges at December 31, 2003 is a $0.6 million gain. b) InterestRate Risk Management PrimeWest has the following interest rate swaps outstanding at December 31, 2003. Interest Rate Risk Management Notional amount Term ($ millions) Fixed BA rate (%) ------------------------------------------------------------------------- May 24/98 - May 25/04 $25 6.48 Nov 26/01 - May 26/04 $25 3.85 ------------------------------------------------------------------------- ------------------------------------------------------------------------- The mark to market value of the interest rate swaps is a $0.6 million loss at December 31, 2003. The effect of the interest rates swaps was to increase interest paid in 2003 by $0.9 million (2002 - $1.5 million; 2001 - $0.4 million). c) Fair Value Of Financial Instruments Financial instruments include cash, accounts receivable, accounts payable and accrued liabilities, accrued distributions to unitholders, long-term debt and financial hedges. As at December 31, 2003, 2002, and 2001, the fair market value of the financial instruments, other than long-term debt and financial hedges, approximate their carrying value, due to the short term maturity of these instruments. The fair value of long-term debt approximates its carrying value in all material respects, because the cost of borrowing approximates the market rate for similar borrowings. 14. Commitments And Contingencies --------------------------------- a) PrimeWest has lease commitments relating to office buildings. The estimated annual minimum operating lease rental payments for the buildings, after deducting sublease income will be $1.2 million in 2004, $1.1 million in 2005, $1.1 million in 2006 and $2.4 million in 2007 - 2009, the remaining term of the leases. b) As part of PrimeWest's internalization transaction (see Note 11), PrimeWest agreed to pay $3.5 million in exchangeable shares as 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 December 31, 2003 $0.5million has been accrued in non-cash general and administrative expenses. c) PrimeWest is engaged in a number of matters of litigation, none of which could reasonably be expected to result in any material adverse consequence. d) PrimeWest has a pipeline transportation commitment that runs to October 31, 2007 and has a minimum annual payment requirement of $U.S. 2.1 million. 15. Subsequent Event -------------------- On January 27th, 2004, PrimeWest announced that it had agreedto make an offer to acquire all of the shares of Seventh Energy. Seventh Energy's Board and executive unanimously approved the transaction and have agreed to tender their approximately 24% ownership interest. The acquisition cost is expected tobe $42.6 million comprised of the assumption of $8.3 million of debt and working capital and a cash payment of $34.3 million. To protect the transaction economics, PrimeWest hedged approximately 70% of Seventh Energy's gas production at a price of $6.18 per mcf for one year. PrimeWest's existing credit line will be used to fund the cash portion of the acquisition. The offer is currently set to expire on March 15, 2004. 16. Prior Years' Comparative Numbers ------------------------------------ Certain prior years' comparative numbers have been restated to conform with the current year's presentation. 17. Differences Between Canadian And United States Generally Accepted --------------------------------------------------------------------- Accounting Principles --------------------- PrimeWest's financial statements are prepared in accordance with accounting principles generally accepted (GAAP) in Canada which, in some respects, differ from those generally accepted in the United States (U.S.). Those policies that result in measurement differences will be available under the "Investor Relations - Financial Information" section of PrimeWest's website at a later date. TRADING PERFORMANCE For the quarter ended Dec 31/03 Sep 30/03 Jun 30/03 Mar 31/03 Dec 31/02 ------------------------------------------------------------------------- TSX Trust Unit prices ($ per Trust Unit) High $ 28.15 $ 26.80 $ 27.75 $ 27.34 $ 27.68 Low $ 25.06 $ 25.19 $ 23.40 $ 24.48 $ 24.23 Close $ 27.56 $ 25.19 $ 25.04 $ 24.51 $ 25.40 ------------------------------------------------------------------------- Average daily traded volume 202,661 149,148 234,477 184,428 123,964 ------------------------------------------------------------------------- ------------------------------------------------------------------------- For the quarter ended Dec 31/03 Sep 30/03 Jun 30/03 Mar 31/03 Dec 31/02 ------------------------------------------------------------------------- NYSE Trust Unit prices ($U.S. per Trust Unit) High $ 21.48 $ 19.29 $ 20.60 $ 17.96 $ 16.69 Low $ 18.67 $ 18.08 $ 15.97 $ 16.05 $ 15.62 Close $ 21.27 $ 18.68 $ 18.53 $ 16.73 $ 16.16 -------------------------------------------------------------------------- Average daily traded volume 243,921 151,813 166,722 111,605 39,276 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Number of TrustUnits outstanding including exchangeable shares (millions of units) 50.44 49.52 45.99 45.43 39.29 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Distribution paid per Trust Unit $0.96 $1.04 $1.20 $1.20 $1.20 ------------------------------------------------------------------------- ------------------------------------------------------------------------- TOTAL COMPOUND ANNUAL RETURN (%) (1) ------------------------------------------------------------------------- S&P TSX Cdn Energy S&P 500 S&P 500 Trust PrimeWest OGPI TSX S&P $Cdn $US Index ------------------------------------------------------------------------- Five Year 30.3% 20.8% 6.3% (4.0)% (0.9)% ------------------------------------------------------------------------- Three Year 12.7% 12.7% (1.4)% (8.8)% (4.5)% ------------------------------------------------------------------------- One Year 28.0% 20.1% 26.7% 5.9% 28.5% 46.4% ------------------------------------------------------------------------- (1) Total return is equal to unit price plus distributionsre-invested END FIRST AND FINAL ADD DATASOURCE: PrimeWest Energy Trust CONTACT: PR NewsWire -- Feb. 20

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