EX-19 3 ex10_form40f-1102.txt EXHIBIT 10 EXHIBIT 10 ---------- PRIMEWEST ENERGY TRUST RENEWAL ANNUAL INFORMATION FORM FOR THE YEAR ENDED DECEMBER 31, 2000 MAY 14, 2001 TABLE OF CONTENTS ITEM 1: INCORPORATION.........................................................1 Trust Structure............................................................2 Organization and Structure of PrimeWest Energy Trust.......................3 The Declaration of Trust...................................................3 The Manager................................................................6 Management Policies and Acquisition Strategy...............................7 Decision Making............................................................9 ITEM 2: GENERAL DEVELOPMENT OF THE BUSINESS...................................9 ITEM 3: NARRATIVE DESCRIPTION OF BUSINESS....................................13 The Business of the Trust.................................................13 General...................................................................13 Operatorship..............................................................13 Acquisitions..............................................................13 Risk Management & Marketing...............................................14 Reserve Continuity - PW Holding Entities and the Trust....................18 Drilling Activity - PW Holding Entities...................................18 Capital Expenditures - PW Holding Entities................................19 Recent Developments.......................................................19 Attributes of the Properties - PW Holding Entities and the Trust..........19 Oil and Natural Gas Reserves - PW Holding Entities and the Trust..........20 Principal Properties - PW Holding Entities................................26 Unproved Lands - PW Holding Entities......................................32 Reserve Continuity - Cypress..............................................33 Drilling Activity - Cypress...............................................33 Capital Expenditures - Cypress............................................34 Recent Developments - Cypress.............................................34 Attributes of the Properties - Cypress....................................35 Oil and Natural Gas Reserves - Cypress....................................36 Principal Properties......................................................42 Unproved Lands - Cypress Energy Inc.......................................44 Industry Conditions.......................................................45 Risk Factors..............................................................47 ITEM 4: SELECTED CONSOLIDATED FINANCIAL INFORMATION..........................52 Selected Annual Information...............................................52 Selected Quarterly Information............................................52 ITEM 5: MANAGEMENT'S DISCUSSION AND ANALYSIS.................................53 ITEM 6: MARKET FOR SECURITIES................................................53 ITEM 7: DIRECTORS AND OFFICERS...............................................53 Directors.................................................................53 Officers..................................................................55 Management of the Manager.................................................56 Employees.................................................................57 ITEM 8: ADDITIONAL INFORMATION...............................................57 Glossary of Abbreviations & Terms.........................................58 Abbreviations.............................................................58 Definitions...............................................................58 SCHEDULE A - US GAAP RECONCILIATION SCHEDULE B - FINANCIAL STATEMENTS OF CYPRESS ENERGY INC. SCHEDULE C - FINANCIAL STATEMENTS OF RESERVE ROYALTY CORPORATION NOTE TO READER Beginning with this Annual Information Form, the conversion rate to convert natural gas (mcf) to barrels of oil equivalent (boe) is 6:1. All prior years, a 10:1 conversion rate was used. ITEM 1: INCORPORATION PrimeWest Energy Trust (the "Trust") is an open-end investment trust created under the laws of Alberta pursuant to the Declaration of Trust as amended from time to time. The undertaking of the Trust is to issue Trust Units to the public and to invest the Trust's funds, directly or indirectly, in petroleum and natural gas properties and assets related thereto. The sole beneficiaries of the Trust are the holders of Trust Units. The Trust Company of Bank of Montreal is the trustee of the Trust. The head office and principal place of business of the Trust is 1600, 530 - 8th Avenue S.W., Calgary, Alberta T2P 3S8. Effective May 28, 2001 the new address of the Manager will be 4700, 150-6th Avenue S.W., Calgary, Alberta, T2P 3Y7. The appointment of The Trust Company of Bank of Montreal as Trustee was approved at the May 18, 1999 Annual General and Special Meeting of Unitholders. The current term of the Trustee's appointment expires at the conclusion of the sixth annual meeting of the unitholders, expected to be held in 2002. THE TRUST HAS TWO WHOLLY-OWNED SUBSIDIARIES, PRIMEWEST RESOURCES LTD. AND PRIMEWEST ROYALTY CORP. AND ONE MAJORITY-OWNED SUBSIDIARY PRIMEWEST OIL AND GAS CORP. PrimeWest Energy Inc. ("PrimeWest") was incorporated under the BUSINESS CORPORATIONS ACT (Alberta) on March 4, 1996. PrimeWest's business is the acquisition, development, exploitation, production and marketing of petroleum and natural gas properties and granting the Royalty to the Trust. All of the issued and outstanding shares of PrimeWest are held by the Manager. PrimeWest Management Inc. ("the Manager") was incorporated on March 4, 1996 under the BUSINESS CORPORATIONS ACT (Alberta). The head, principal and registered office of PrimeWest and the Manager is 1600, 530 - 8th Avenue S.W., Calgary, Alberta T2P 3S8. 1 TRUST STRUCTURE The following diagram represents the current structure of the Trust and the flow of funds from the petroleum and natural gas properties owned by PrimeWest and the Trust's subsidiaries PrimeWest Resources Ltd. ("Resources") and PrimeWest Royalty Corp. ("Royalty Corp"), and PrimeWest Oil and Gas Corp. ("O&G Corp."), and gross overriding royalties owned directly by the Trust, to PrimeWest, the Manager, and from the Trust to Unitholders: 2 ORGANIZATION AND STRUCTURE OF PRIMEWEST ENERGY TRUST The principal undertaking of the Trust is to acquire and hold, directly and indirectly, interests in petroleum and natural gas properties. One of the Trust's primary assets is currently the Royalty granted by PrimeWest pursuant to the Royalty Agreement. The Royalty entitles the Trust to receive 99 percent of the net cash flow generated by the petroleum and natural gas interests held from time to time by PrimeWest, after certain costs and deductions. The Trust holds similar 99 percent net production royalties granted by each of Resources, Royalty Corp. and O&G Corp., in respect of all of the petroleum and natural gas properties owned by such corporations from time to time. The Distributable Income generated by these royalties is then distributed monthly to Unitholders. The Trust also lends money to PrimeWest, Resources, Royalty Corp. and O&G Corp. to allow these companies to make further acquisitions and develop their properties. The interest income earned on such funds is distributed monthly to Unitholders. THE DECLARATION OF TRUST The Declaration of Trust, among other things, provides for the calling of meetings of Unitholders, the conduct of business at those meetings, notice provisions, the appointment, resignation and removal of the Trustee and the form of Trust Unit certificates. The Declaration of Trust may be amended from time to time. Substantive amendments to the Declaration of Trust, including extension or early termination of the Trust and the sale or transfer of the property of the Trust as an entirety, or substantially as an entirety, requires approval by special resolution of the Unitholders. The following is a summary of certain provisions of the Declaration of Trust. For a complete description of that indenture, reference should be made to the Declaration of Trust, copies of which may be viewed at the offices of, or obtained from, the Trustee. TRUST UNITS An unlimited number of Trust Units may be issued pursuant to the Declaration of Trust, each of which represents an equal fractional undivided beneficial interest in the Trust entitling the holder to receive monthly distributions of Distributable Income. All Trust Units share equally in all distributions from the Trust, carry equal voting rights at meetings of Unitholders, and have a right of redemption on terms set out in the Declaration of Trust. No Unitholder is liable to pay any further calls or assessments in respect of the Trust Units other than any instalment payment arrangements that are applicable to an offering of Trust Units in respect of which the Unitholder acquired his Trust Units. The Trust Units are not "deposits" within the meaning of the Canada Deposit Insurance Corporation Act (CANADA) and are not insured under the provisions of that 3 Act or any other legislation. Furthermore, the Trust is not a trust company and, accordingly, is not registered under any trust and loan company legislation, as it does not carry on or intend to carry on the business of a trust company. EXCHANGEABLE SHARES OF PRIMEWEST RESOURCES LTD. In connection with the Venator transaction PrimeWest Resources Ltd. amended its articles to create an unlimited number of exchangeable shares. The exchangeable shares are exchangeable into trust units at any time up to five years after issuance, based on an exchange ratio that adjusts each time PrimeWest makes a distribution to its unitholders. In certain circumstances, PrimeWest has the right to force redemption prior to the five-year expiry term. Dividends are paid to holders of exchangeable shares based on the estimated taxable portion of the monthly distribution paid. The exchange ratio, which was 1:1 on the closing date of the Venator transaction, is based on the total monthly distribution paid less the dividend paid, divided by the closing trust unit price on the distribution payment date. The exchange ratio at December 31, 2000 was 1.0933:1. TRUSTEE The Trust Company of Bank of Montreal is the current trustee of the Trust and also acts as the transfer agent for the Trust Units. The Trustee is responsible for, among other things (a) accepting subscriptions for Trust Units and issuing Trust Units pursuant thereto; (b) maintaining the books and records of the Trust and providing timely reports to holders of Trust Units; and (c) paying cash distributions to Unitholders. The Declaration of Trust provides that the Trustee is to exercise its powers and carry out its functions thereunder as Trustee honestly, in good faith and in the best interests of the Trust and the Unitholders and, in connection therewith, must exercise that degree of care, diligence and skill that a reasonably prudent trustee would exercise in comparable circumstances. The current term of the Trustee's appointment will expire at the conclusion of the sixth annual meeting of Unitholders, expected to be held in 2002. Thereafter, the Trustee will be reappointed or changed every third annual meeting as may be determined by a majority of the votes cast at a meeting of the Unitholders. The Trustee may also be removed by a majority vote of the Unitholders in that regard. The Trustee may resign on 60 days' notice to PrimeWest. That resignation or removal becomes effective on the appointment of a successor trustee and the acceptance of that appointment and the assumption of the obligations of the Trustee by that successor trustee. 4 CASH DISTRIBUTIONS Cash distributions of Distributable Income are made on a monthly basis on the Cash Distribution Date following the end of each month, to Unitholders of record on the Record Date in that month. REDEMPTION RIGHT Trust Units are redeemable at any time on demand by the holder thereof upon delivery to the Trust of the certificates representing such Trust Units accompanied by a duly completed and properly executed notice requesting redemption. Upon such receipt of the redemption request, all of the Unitholder's rights to and under the Trust Units tendered for redemption are surrendered and the Unitholder becomes entitled to receive a price per Trust Unit as determined by a market price formula, subject to a monthly aggregate cash cap of up to $100,000. The redemption price payable by the Trust may be satisfied by way of a cash payment, or in certain circumstances, including where such payment would cause the monthly cash cap to be exceeded, by way of an in SPECIE distribution. MEETINGS AND VOTING Annual meetings of the Unitholders commenced in 1997. Special meetings of Unitholders may be called at any time by the Trustee and will be called by the Trustee on the written request of Unitholders holding in aggregate not less than 20 percent of the Trust Units. Notice of all meetings of Unitholders will be given to Unitholders at least 21 days and not more than 50 days prior to the meeting. Unitholders may attend and vote at all meetings of such Unitholders either in person or by proxy and a proxy holder need not be a holder of Trust Units. At least two persons present in person or represented by proxy and representing in the aggregate not less than five percent of the votes attaching to all outstanding Trust Units constitute a quorum for the transaction of business at all those meetings. Unitholders are entitled to one vote per Trust Unit. LIMITATION ON NON-RESIDENT OWNERSHIP In order for the Trust to maintain its status as a mutual fund trust under the INCOME TAX ACT (CANADA), the Trust must not be established or maintained primarily for the benefit of non-residents of Canada ("non-residents") within the meaning of the INCOME TAX ACT (CANADA). Accordingly, the Declaration of Trust provides that at no time may non-residents be the beneficial owners of a majority of the Trust Units. If the Trustee becomes aware that the beneficial owners of 49 percent of the Trust Units then outstanding are or may be non-residents or that situation is imminent, the Trustee may make a public announcement in that regard and will not accept a subscription for Trust Units from or issue or register a transfer of Trust Units to a person unless the person 5 provides a declaration that the person is not a non-resident. Notwithstanding the foregoing, if the Trustee determines that a majority of the Trust Units are beneficially held by non-residents, the Trustee may send a notice to non-resident Unitholders, chosen in inverse order to the order of acquisition or registration or in such other manner as the Trustee may consider equitable and practicable, requiring those non-resident Unitholders to sell their Trust Units or part of them within a specified period of not less than 60 days. If the non-resident Unitholders receiving that notice have not sold the specified number of Trust Units or provided the Trustee with satisfactory evidence that they are not non-residents within that period, the Trustee may on behalf of those Unitholders sell those Trust Units and, in the interim, will suspend the voting and distribution rights attached to those Trust Units. When that sale by the Trustee occurs, the affected Unitholders will cease to be holders of Trust Units and their rights will be limited to receiving the net proceeds of sale on surrender of the certificates representing those Trust Units. COMPULSORY ACQUISITION The Declaration of Trust provides that if a person within either 120 days of making an offer to purchase all outstanding Trust Units or the time for acceptance provided in that offer (provided that such offer is open for acceptance for a period of not less than 45 days), whichever period is the shorter, acquires not less than 90 percent of the outstanding Trust Units (other than those held by that person and its affiliates), that person may acquire the Trust Units of the Unitholders who did not accept the offer on the same terms as those offered to those Unitholders who accepted the offer. TERMINATION OF THE TRUST The Unitholders may vote to terminate the Trust at any meeting of the Unitholders, provided that the termination must be approved by special resolution of the Unitholders. Unless the Trust is terminated or extended by vote of the Unitholders earlier, the Trustee will commence to wind-up the affairs of the Trust on December 31, 2095. In the event that the Trust is wound-up, the Trustee will liquidate all the assets of the Trust, pay, retire, discharge or make provision for some or all obligations of the Trust and then distribute the remaining proceeds of the liquidation to Unitholders. THE MANAGER BUSINESS The principal business of the Manager is to provide administrative services to the Trust and to carry out the management of the business and affairs of PrimeWest, Resources, Royalty Corp. and O&G Corp. (collectively, the "PW Holding Entities"), including managing the operation (where a PW Holding Entity has been appointed 6 operator) and administration of the petroleum and natural gas properties owned by the PW Holding Entities. MANAGER COMPENSATION The Manager is compensated for its services to the PW Holding Entities and the Trust as follows: (a) a management fee equal to 2.5 percent of the net production revenue generated by the petroleum and natural gas interests held by the PW Holding Entities or otherwise held directly or indirectly by the Trust, plus Alberta royalty tax credit, after certain adjustments for hedging activities, Crown royalties and other Crown charges, third-party processing and other income and certain non-capital operating costs; (b) quarterly incentive payments of Trust Units. The first quarterly incentive payment was 12,500 Trust Units and subsequent payments have increased in proportion to the number of additional Trust Units issued by the Trust. The most recent quarterly incentive payment was 53,616 Trust Units for the quarter ended March 31, 2001; (c) an acquisition fee equal to 1.5 percent of the purchase price of any properties acquired by the PW Holding Entities or the Trust or of the enterprise value of the Person which owns petroleum and natural gas rights or interests in the event of the acquisition of that Person by the PW Holding Entities or the Trust, and a disposition fee equal to 1.25 percent of the sale price of any properties sold by the PW Holding Entities, the Trust or any Person acquired by the PW Holding Entities or the Trust; (d) reimbursement for general and administrative costs based on time spent and direct costs incurred in providing management and administrative services to the PW Holding Entities and the Trust; and (e) one percent of the net cash flow generated by the petroleum and natural gas interests held by the PW Holding Entities, the Trust or any Person acquired by the PW Holding Entities or the Trust (without duplication), after certain costs, expenditures and deductions. MANAGEMENT POLICIES AND ACQUISITION STRATEGY Activities undertaken by the Manager in overseeing the operations and administration of the PW Holding Entities are directed toward achieving stable long-term growth in Distributable Income paid to the Unitholders and in the value of the properties owned by the PW Holding Entities and the Trust. These two objectives are fundamental to the operation of the Trust and are balanced to enhance benefits to the Unitholders. 7 Unless the PW Holding Entities is able to acquire additional petroleum and natural gas reserves or increase reserves through development activities, production from the properties owned by it will eventually decline. Accordingly, the Manager presents proposals to PrimeWest and the Trust to acquire producing properties or to participate in development activities that are considered to be of a low-risk nature in the oil and natural gas industry. When considering the acquisition of any petroleum and natural gas producing property, the Manager focuses on long-life properties with low reservoir risk. The properties may be operated either by PrimeWest or by other acceptable operators and must have the potential to increase Distributable Income and enhance the Trust's value through exploitation of those properties. The Manager's acquisition strategy uses the following procedures and targets individual properties, or groups of properties, that generally comply with the following guidelines: (a) a property, or group of properties, acquired, directly or indirectly, pursuant to an acquisition will provide a forecast internal rate of return that is greater than 400 basis points above the yield of long-term (ten-year) Government of Canada bonds over the life of the reserves associated with that property or group of properties, after deducting general and administrative expenses and management fees and incorporating the impact of debt financing, but before income taxes; (b) properties where PrimeWest will become the operator are preferred; (c) commodity price and exchange rate assumptions used in acquisition evaluations will be from a major independent petroleum engineering firm; (d) each acquisition having a purchase price of $5,000,000 or more will be based on an independent petroleum engineering report, the results of which report may be modified to incorporate the Manager's view of the engineering analysis contained in that report; (e) at no time will more than 25 percent of the total reserve value of the properties owned by PrimeWest or the Trust be attributable to a single property; and (f) the expected economic life of a property, or group of properties, acquired in a single transaction will not be less than 20 years. The board of directors of PrimeWest may at its discretion approve acquisitions that do not conform to these guidelines, based on the board's consideration of other qualitative aspects of the subject properties including risk profile, technical upside, reserve life and asset quality. 8 DECISION MAKING PrimeWest, the Manager and the Trust are parties to a unanimous shareholder agreement which provides that Unitholders will be entitled to notice of and to attend all meetings of shareholders of PrimeWest and except as set forth below, to direct the manner in which the Manager will vote its shares in PrimeWest at all of those meetings. Accordingly, the Unitholders are entitled to direct the Manager as to the election of directors of PrimeWest (other than the nominees of the Manager), the approval of the financial statements of PrimeWest and the appointment of its auditors. The unanimous shareholder agreement also provides that the board of directors of PrimeWest will, subject to complying with applicable laws regarding the declaration of dividends, declare and pay dividends to the Manager in an amount representing one percent of its net cash flow. The board of directors of PrimeWest is responsible for making significant decisions with respect to the PW Holding Entities, including all decisions relating to (a)the acquisition, directly or indirectly, of petroleum and natural gas properties at a cost in excess of $5,000,000 and the disposition of petroleum and natural gas properties for a sale price or proceeds in excess of $2,000,000; (b)the approval of capital expenditure budgets; (c)the approval of risk management activities proposed to be undertaken by the Manager; and (d)the establishment of credit facilities. In addition, the Trustee has delegated certain matters regarding the Trust to PrimeWest, including all decisions relating to (i) issuances of Trust Units, (ii) the determination of the amount of distributions to be made by the Trust, (iii) approvals required with regard to any proposed amendment to the Declaration of Trust, the management agreement, the royalty agreement or the unanimous shareholder agreement respecting the relationships among the Trust, PrimeWest and the Manager, and (iv) responding to unsolicited take-over or merger proposals. The board of directors of PrimeWest holds regularly scheduled meetings to review the business and affairs of PrimeWest and the Trust. ITEM 2: GENERAL DEVELOPMENT OF THE BUSINESS On October 16, 1996, the Trust completed an initial public offering of 24,900,000 Trust Units on an instalment receipt basis of $6.00 payable on October 16, 1996 and $4.00 payable one year later, for total gross proceeds of $249,000,000. The Trust used the net proceeds of that offering plus the assignment of the right to be paid the final instalment of $4.00 per Trust Unit, to purchase the Royalty from PrimeWest. PrimeWest used the net proceeds from the sale of the Royalty to the Trust and debt in the amount of $12,071,000 to acquire certain oil and gas properties. During the year ended December 31, 1997, PrimeWest completed the acquisition of additional petroleum and natural gas reserves having an aggregate acquisition cost of approximately $35 million. 9 On February 25, 1998, PrimeWest implemented a Distribution Reinvestment Plan (the "DRIP") and Optional Trust Unit Purchase Plan of the Trust. The DRIP allows Unitholders to elect to reinvest cash distributions to purchase additional Trust Units from the Trust. In March 1998, the Trust completed two acquisitions of petroleum and natural gas reserves in the Grand Forks and Medicine Hat areas of Alberta. Pursuant to those acquisitions, PrimeWest acquired approximately 11.8 million boe of Established Reserves, plus an amount for interests in certain facilities, for an aggregate purchase price of approximately $60.2 million. Substantially all of the purchase price was financed by an equity offering of 8,000,000 Trust Units at $7.80 per unit, for net proceeds of $59,280,000. On May 21, 1998, the Trust held a Special and Annual General Meeting of Unitholders at which the Unitholders authorized the reorganization of the Trust from a closed-end investment trust to an open-end investment trust. This change was made in order to add flexibility to the investments that the Trust is allowed to make. As a closed-end trust, the Trust was restricted to owning certain types of assets, principally royalty interests. As an open-end trust, the Trust is able to invest in shares of other corporations and in other types of income producing assets. On March 31, 1999, PrimeWest announced that it had adopted a Unitholder Rights Plan (the "Rights Plan"). The Rights Plan was approved by PrimeWest Unitholders at the Annual General and Special Meeting of the PrimeWest Unitholders held on May 18, 1999. Under the terms of the Rights Plan, a prospective bidder would be encouraged to negotiate the terms of a bid with the board of directors of PrimeWest, or to make a "permitted bid", not requiring the approval of the board of directors of PrimeWest but having terms and conditions designed to provide the board of directors of PrimeWest with sufficient time to properly evaluate a take-over bid and its effects, and to seek alternative bidders or to explore other ways of maximizing PrimeWest Unitholder value in the event of an unsolicited take-over bid. If a person acquires more than 20 percent of the PrimeWest units other than by way of a permitted bid, other PrimeWest Unitholders may, at the discretion of the board of directors of PrimeWest, acquire a number of PrimeWest Units at 50 percent of the then prevailing market price, so as to cause significant dilution to the acquiring person. The Rights Plan provides that a permitted bid is a take-over bid meeting the following requirements: (a) The bid must be made to all PrimeWest Unitholders; 10 (b) The bid must be open for a minimum of 45 days following the date of the bid, and no PrimeWest units may be taken up prior to such time; (c) Take-up and payment of PrimeWest units may not occur unless the bid is accepted by PrimeWest Unitholders holding more than 50 percent of the outstanding PrimeWest units, excluding PrimeWest units held by the bidder and its associates; (d) PrimeWest units may be deposited to or withdrawn from the bid at any time prior to the take-up date; and (e) If the bid is accepted by PrimeWest Unitholders holding the requisite percentage of PrimeWest units, the bidder must extend the bid for an additional ten business days to permit other PrimeWest Unitholders to tender into the bid, should they so wish. The Rights Plan expires on the date of PrimeWest's annual meeting in 2002. On October 5, 1999, the Trust closed the issue of 2.75 million Trust Units at a price of $7.20 per Trust Unit. The issue was done on a bought-deal basis for gross proceeds of $19.8 million. On November 3, 1999, Resources completed the acquisition of gas reserves in southeast Alberta. PrimeWest paid $13.6 million for 16.3 bcf of established reserves which produce 3.04 million cubic feet of natural gas per day. On November 26, 1999, the Trust received approval from The Toronto Stock Exchange to make a normal course issuer bid. The bid commenced November 30, 1999 and terminated on November 29, 2000. From November 30, 1999 to the expiry date of this Bid, the Trust purchased 263,100 Units at an average cost of $6.39 per Trust Unit under this Bid. On January 5, 2000, PrimeWest completed the purchase of a 34.6 percent interest in the Crossfield natural gas processing plant and associated gathering system. That transaction increased PrimeWest's stake in the facilities to 54 percent and enabled PrimeWest to become the operator of the facilities. In June 2000, PrimeWest sold a 25.8 percent interest in the facilities to a third party for cash and a life of reserves contract whereby the third party dedicated processing of all of its operated production from three nearby fields to the plant. On April 19, 2000 Resources completed the purchase of all of the issued and outstanding shares of Venator Petroleum Company Limited. The purchase price of the transaction, including assumed debt, was $32.5 million. The transaction added 3.0 million BOE of established reserves and approximately 1,500 BOE per day of daily working interest production. The purchase price consisted of the issuance of 2.4 million Trust Units and 2 million Resources exchangeable shares exchangeable into Trust Units. 11 Immediately after this acquisition, the assets of Venator were transferred to Resources and Venator was dissolved. On May 25, 2000, the Trust held its annual general and special meeting of Unitholders. At this meeting, the Unitholders adopted the following resolutions: 1) an enhancement to the Distribution Reinvestment Plan whereby units issued pursuant to the plan would be eligible for a 5 percent discount to the market price; 2) an amendment to the Declaration of the Trust permitting the independent directors to appoint up to two additional independent directors to the board of directors of PrimeWest; 3) an amendment to the Declaration of Trust that modifies borrowing covenants to be based on discounted cash flows at a discount rate equivalent to the then current Government of Canada 10 year bond rate plus 400 basis points (to a maximum of 15 percent); 4) an amendment to the Declaration of Trust permitting the creation of special voting units to allow holders of Resources exchangeable shares to vote at meetings of unitholders; and 5) an amendment to the Declaration of Trust that gives the board of directors of PrimeWest the sole responsibility for dealing with all matters related to any unsolicited take-over bids. On May 31, 2000, the Trust announced the appointment of Michael W. O'Brien as an additional independent director of the board of directors of PrimeWest. Mr. O'Brien is Executive VP, Corporate Development and CFO of Suncor Energy Inc. On July 27, 2000, Royalty Corp. completed the purchase of all of the issued and outstanding shares of Reserve Royalty Corp. on a unit for share exchange. The Trust issued 6.67 million Trust Units and assumed debt for total consideration of $84.0 million. The transaction added approximately 6.1 million BOE of established reserves and approximately 1,700 BOE per day of mainly Gross Overriding Royalty production. Subsequent to the transaction, Reserve Royalty was amalgamated into Royalty Corp. and the majority of its assets were transferred to the Trust. On September 28, 2000, the Trust closed the issue of 4.83 million Trust Units at a price of $8.35 per Trust Unit. The issue was done on a bought-deal basis for gross proceeds of $40.3 million. On December 15, 2000, the Trust received approval from the Toronto Stock Exchange to make a normal course issuer bid. The bid commenced December 19, 2000 and will terminate on December 18, 2001. From December 19, 2000 to the date of this Annual Information Form, the Trust has not made any purchase of Trust Units under this bid. On March 29, 2001, O&G Corp. completed the purchase of all of the issued and outstanding shares of Cypress Energy Inc. by way of an offer of $14.00 per Cypress share up to a maximum of $60 million, or, at the option of the Cypress shareholder, 1.45 Trust Units or 1.45 exchangeable shares of O&G Corp. (subject to a maximum of 5.44 million exchangeable shares). In aggregate, the Trust issued 50.2 million trust units, 12 O&G Corp issued 5.44 million exchangeable shares and paid $58.4 million in cash pursuant to the purchase. The transaction added approximately 57.5 million BOE of established reserves (as at December 31, 2000) and approximately 15,000 BOE per day of production. On closing of the transaction, Cypress Energy Inc. and a number of its subsidiaries and O&G Corp. were amalgamated under the name PrimeWest Oil and Gas Corp. ITEM 3: NARRATIVE DESCRIPTION OF BUSINESS THE BUSINESS OF THE TRUST GENERAL The undertaking of the Trust is to directly and indirectly acquire and hold petroleum and natural gas properties and to distribute the Distributable Income generated therefrom to Unitholders. It is therefore the mandate of PrimeWest and the Manager to continue to source and acquire petroleum and natural gas properties both for and on behalf of PrimeWest and the Trust, and to enhance the production from both acquired and existing properties in order to increase the amount of Distributable Income distributed to Unitholders. OPERATORSHIP The Manager, on behalf of PrimeWest, manages the operation of those properties in respect of which PrimeWest is the operator. PrimeWest believes that although operatorship of the properties generally involves higher General and Administrative Costs than would be required for non-operated properties, those higher costs will generally result in more opportunities to enhance value to Unitholders through production enhancement, control of facilities and increased access to acquisition opportunities in core areas. ACQUISITIONS Unless PrimeWest and the Trust are able to acquire additional petroleum and natural gas reserves or increase reserves through development activities, production from the currently held properties will eventually decline. The Manager, on behalf of PrimeWest and the Trust, continually reviews opportunities for the acquisition of producing oil and natural gas properties. When considering the acquisition of any petroleum and natural gas producing property, the Manager focuses on long-life properties, with low reservoir risk, that may be operated by either PrimeWest or other acceptable operators and that have the potential to increase Distributable Income and enhance the Trust's value through exploitation of those properties. See "Management Policies and Acquisition Strategy". 13 RISK MANAGEMENT & MARKETING Prices received for production are impacted in varying degrees by factors outside the Trust's control. These include but are not limited to: (a) World market forces, most importantly the actions of OPEC, and their implications for the price of crude oil; (b) Increases or decreases in crude-oil quality differentials, and their implications for prices received by PrimeWest on the portion of our oil production that is medium gravity crude (about 40 percent at year-end); (c) North American market forces, most notably shifts in the balance between supply and demand for natural gas and the implications for the price of natural gas; and (d) To the extent that crude oil and natural gas prices received by PrimeWest are referenced to WTI oil, which is denominated in U.S. dollars, prices and revenue streams are impacted by changes in value between the Canadian and U.S. dollars. Fluctuations in commodity prices, quality differentials, foreign exchange and interest rates are outside the control of PrimeWest and yet can have a significant impact on the level of cash available for distribution to unitholders. To mitigate a portion of this risk, PrimeWest actively initiates, manages and discloses the effects of hedging activities. PrimeWest evaluates these activities against criteria established under a commodity risk-assessment and management program, which is regularly reviewed by the Board. As part of PrimeWest's risk-management strategy in 2000, 44 percent of our full-year crude oil production and 27 percent of our full-year natural gas production was hedged, net of royalties. Strategies utilized included both physical and financial instruments with the primary objective of enhancing the stability of cash distributions. In connection with the acquisition of Cypress Energy Inc. in March 2001, PrimeWest entered into a series of price hedging contracts on 8,400 BOE per day of natural gas production and 6,000 BOE per day of crude oil production (annualized). The gas hedging instruments are floors, swaptions and swaps. The swaptions will give PrimeWest the future right to enter into swap transactions for fixed prices and terms. The oil hedging transactions consist of floors, swaps, costless collars and calls. The natural gas hedges have an effective term until the end of the 2002 summer season. The crude oil hedges are for the period April through December 2001. The cost of these risk-management activities equates to approximately $0.06 per trust unit over 2001 and approximately $0.03 per trust unit in 2002. 14 The combined effect of all oil-related transactions executed at the date of this Annual Information Form is downside protection below $U.S. 25.00 per barrel on approximately 99 percent of annualized overall crude production, net of royalties. As conditions warrant, PrimeWest may layer in additional risk-management instruments throughout the year. For gas for 2001, PrimeWest has layered in other hedging structures - swaps, floors and costless collars - representing about 38 percent of total gas production, net of royalties. PrimeWest's marketing portfolio for natural gas is well diversified. Approximately 46 percent of natural gas production is sold to aggregators and 54 percent of production is sold into the Alberta short-and long-term markets. The contracts that PrimeWest has with aggregators vary in length. They have a blend of domestic and U.S. markets, with fixed and floating prices which provide price diversification to our revenue stream. In addition to these noted risk-management practices, PrimeWest also works to maintain a relatively balanced production portfolio. Because oil and gas price cycles do not necessarily coincide, such a balance often provides a natural mitigation of price risk. For 2000, PrimeWest's commodity mix was 50 percent oil and NGLs, and 50 percent natural gas, the same as it as at year-beginning 2000. After the acquisition of Cypress, the ratio became 66 percent gas and 34 percent oil and NGLs. 15 The following is a summary of commodity hedges in place as of May 9, 2001 for the next 12 months:
SUMMARY OF COMMODITY HEDGES CRUDE OIL (as an approximate percentage of QUARTER ENDING QUARTER ENDING QUARTER ENDING QUARTER ENDING total anticipated crude oil JUNE 30, 2001 SEPT. 30, 2001 DEC. 31, 2001 MAR. 31, 2002 production after royalties) -------------------------------------------------------------------------- VOLUME HEDGED, FIXED PRICE(1) 45% 45% 45% 0% VOLUME HEDGED, INSURED(1) 51% 51% 51% 0% (U.S. dollars per barrel) PRIMEWEST PRIMEWEST PRIMEWEST PRIMEWEST IF WTI IS: RECEIVES RECEIVES RECEIVES RECEIVES -------------------------------------------------------------------------- 30.00 28.54 28.57 28.72 30.00 28.00 27.64 27.65 27.69 28.00 26.00 26.57 26.55 26.55 26.00 24.00 25.95 25.90 25.84 24.00 22.00 25.83 25.74 25.55 22.00 20.00 25.71 25.57 25.27 20.00
1. Fixed price (swap) is for a specified term. Insured volumes include puts that limit the downside below US $25.00 per barrel. 16 NATURAL GAS (AS MAY 9, 2001) APPROXIMATELY 44 PERCENT OF 2001 GAS VOLUMES IS MARKETED THROUGH AGGREGATORS, WITH THE REMAINING 56 PERCENT MARKETED DIRECTLY TO PRIMEWEST IN THE ALBERTA SHORT- AND LONG-TERM MARKETS. VOLUMES SOLD THROUGH AGGREGATORS RECEIVE PRICES THAT ARE DERIVED FROM A NUMBER OF MARKETS ACROSS NORTH AMERICA. THE FOLLOWING TABLE REFERS ONLY TO THE PRODUCTION THAT PRIMEWEST SELLS DIRECTLY.
(as an approximate percentage of QUARTER ENDING QUARTER ENDING QUARTER ENDING QUARTER ENDING direct marketed volumes) JUNE 30, 2001 SEPT. 30, 2001 DEC. 31, 2001 MAR. 31, 2002 -------------------------------------------------------------------------- VOLUME HEDGED, FIXED PRICE(2) 40% 58% 23% 5% VOLUME HEDGED, INSURED(2) 39% 15% 37% 54% (Canadian dollars per Mcf) PRIMEWEST PRIMEWEST PRIMEWEST PRIMEWEST IF AECO IS: RECEIVES(1) RECEIVES(1) RECEIVES(1) RECEIVES(1) -------------------------------------------------------------------------- 7.50 7.39 7.39 7.46 7.50 7.00 7.08 7.18 7.08 7.03 6.50 6.78 6.96 6.78 6.69 6.00 6.64 6.80 6.57 6.49 5.50 6.54 6.67 6.36 6.29 5.00 6.43 6.54 6.16 6.09 4.50 6.33 6.41 5.96 5.89 4.00 6.56 6.62 6.07 5.69
1. The blended prices PrimeWest would expect to receive on gas it markets directly. These prices are a weighted average blend of prices received on hedged volumes and prevailing market prices received for unhedged sales. 2. Fixed price (swap) is for a specified term. Insured volumes include puts and put swaptions. This Annual Information Form contains information respecting the reserves, production and activity of the PW Holding Entities and the Trust as of December 31, 2000. On March 29, 2001, O&G Corp. acquired all of the outstanding shares of Cypress Energy Inc. and was amalgamated with Cypress Energy Inc. and a number of its subsidiaries, including Ranchero Energy Inc., under the name PrimeWest Oil and Gas Corp. Accordingly, this Annual Information Form also contains information respecting the reserves, production and activity of Cypress Energy Inc. as of December 31, 2000, all of which are in addition to the reserves, production and activities disclosed in respect of the PW Holding Entities and the Trust. 17 RESERVE CONTINUITY - PW HOLDING ENTITIES AND THE TRUST Gilbert Laustsen Jung Associates Ltd., independent petroleum consultants, ("Gilbert"), has prepared a reserves report ("Gilbert Report") evaluating the crude oil, natural gas, natural gas liquids and sulphur reserves attributable to properties owned by PrimeWest, Resources, Royalty Corp. and the Trust as at January 1, 2001. The following table sets forth the reconciliation of the Established Reserves of the PW Holding Entities and the Trust for the year ended December 31, 2000.
RECONCILIATION OF NET COMPANY INTEREST RESERVES OIL & NATURAL ----------------------------------------------- GAS LIQUIDS NATURAL GAS TOTAL(1)(2) (MMBBLS) (BCF) (MMBOE) ----------------- -------------- ------------------ As at January 1, 2000 26.20 224.50 63.60 Capital Development Program and Revisions 2.32 (1.50) 2.10 Acquisitions, net of dispositions 5.17 27.60 9.80 Production (2.90) (17.88) (5.90) ----------------- -------------- ------------------ As at January 1, 2001 30.80 232.80 69.60 ================= ============== ================== Net Increase in Reserves 4.6 8.3 6.00 Percent Increase 18% 4% 9% ================= ============== ==================
(1) may not add due to rounding (2) gas reserves converted to mmboe on the basis of 6:1 DRILLING ACTIVITY - PW HOLDING ENTITIES During the Trust's last two financial years, the PW Holding Entities drilled or participated in the drilling of the following wells: YEAR ENDED YEAR ENDED DECEMBER 31, 2000 DECEMBER 31, 1999 --------------------- ---------------------- Gross Net Gross Net ------- ---------- -------- ---------- Natural Gas 3 1.59 3 2.26 Crude Oil 59 5.53 14 3.80 Dry 2 1.33 4 3.95 ------- ---------- -------- ---------- Total 64 8.45 21 10.01 ======= ========== ======== ========== 18 CAPITAL EXPENDITURES - PW HOLDING ENTITIES The following table sets forth the capital expenditures by the PW Holding Entities for the last two financial years: Year Ended Year Ended December 31, 2000 December 31, 1999 (000's) (000's) -------------------------------------------------------------------------------- Drilling, completion & Facilities $ 23,443 $ 13,750 Property acquisitions, net of dispositions (including corporate acquisitions) 117,801 18,738 Head Office 2,348 422 -------------------------------------- $ 143,592 $ 32,910 ====================================== RECENT DEVELOPMENTS On February 16, 2001, O&G Corp. and Cypress Energy Inc. announced that they had entered into an agreement where O&G Corp. offered to purchase all of the issued and outstanding Class A and B common shares of Cypress. On March 29, 2001, O&G Corp. announced the successful completion of the transaction whereby 97 percent of the outstanding Cypress shares were tendered to the bid. O&G Corp. acquired the remaining shares under the compulsory acquisition provisions of Canadian corporate law. Accordingly, the Trust issued 50.2 million trust units, O&G Corp. issued 5.44 million exchangeable shares and $58.4 million in cash pursuant to the takeover bid offer. ATTRIBUTES OF THE PROPERTIES - PW HOLDING ENTITIES AND THE TRUST The properties of the PW Holding Entities and the Trust include interests in both unitized and non-unitized oil and natural gas production from several major oil and natural gas fields. The following characteristics, as at December 31, 2000, make the properties suitable for a conventional crude oil and natural gas royalty trust structure: (a) LONG LIFE RESERVES: The properties contain long life, low decline rate reserves that have an Established Reserve Life Index of 10.2 years, and a Proved plus Probable Reserve Life Index of 11.6 years; (b) OPERATED PROPERTIES: Approximately 75 percent of the total production from the properties is operated by PrimeWest. In respect of these operated properties, PrimeWest is able to exercise management and operating influence to maximize value for the benefit of the Trust; 19 (c) BALANCED PORTFOLIO: For the year ended December 31, 2000 production from the properties is approximately 50 percent crude oil and natural gas liquids and 50 percent natural gas, on a barrel-of-oil-equivalent basis. As at January 1, 2001, established Reserves for the properties are approximately 44 percent crude oil and natural gas liquids and 56 percent natural gas on a barrel-of-oil-equivalent basis. Crude oil reserves are predominantly light-gravity oil, averaging 32 degree API; (d) CONCENTRATED PORTFOLIO: While the properties are diversified from a geological and geographic perspective, the PW Holding Entities generally have the largest working interest in these properties; and (e) UPSIDE POTENTIAL: Additional opportunities to enhance the value of the properties have been identified by the Manager. These opportunities may not have been included in the valuations provided in the Gilbert Report. OIL AND NATURAL GAS RESERVES - PW HOLDING ENTITIES AND THE TRUST Gilbert has prepared the Gilbert Report evaluating the properties as at January 1, 2001. THE GILBERT REPORT EVALUATES THE CRUDE OIL, NATURAL GAS, NATURAL GAS LIQUIDS AND SULPHUR RESERVES ATTRIBUTABLE TO THE PROPERTIES PRIOR TO PROVISION FOR INCOME TAXES, INTEREST COSTS, GENERAL AND ADMINISTRATIVE EXPENSES AND MANAGEMENT FEES, BUT AFTER PROVIDING FOR ESTIMATED ROYALTIES, OPERATING COSTS, OTHER INCOME, FUTURE CAPITAL EXPENDITURES AND FACILITY SITE RESTORATION, WELL ABANDONMENT AND WELL-SITE RESTORATION COSTS. PROBABLE ADDITIONAL RESERVES AND THE PRESENT WORTH OF THOSE RESERVES AS SET FORTH IN THE TABLES BELOW HAVE BEEN REDUCED BY 50 PERCENT TO REFLECT THE DEGREE OF RISK ASSOCIATED WITH RECOVERY OF THOSE RESERVES. It should not be assumed that the discounted future net cash flows estimated by Gilbert represent the fair market value of these reserves. Other assumptions and qualifications relating to costs, prices for future production and other matters are summarized in the notes following these tables.
PETROLEUM AND NATURAL GAS RESERVES AND PRE-TAX NET CASH FLOWS ESCALATING COST AND PRICE CASE COMPANY INTEREST RESERVES ESTIMATED PRESENT WORTH OF FUTURE PRE-TAX NET CASH FLOWS ($000'S)* ----------------------------------------------------- ------------------------------------------ CRUDE OIL AND NATURAL GAS NATURAL GAS SULPHUR LIQUIDS (MBBLS) (BCF) (MLT) DISCOUNTED AT ----------------- ----------------- ----------------- --------------------------- GROSS NET GROSS NET GROSS NET UNDISCOUNTED 10% 15% 20% -------- ------- ------- -------- -------- -------- -------------- -------- ------- -------- Proved Producing........ 21,878 18,903 162 127 773 637 784,004 484,709 415,511 367,250 Non-Producing.... 3,173 2,533 30 24 8 7 123,675 64,871 51,099 41,702 -------- ------- ------- -------- -------- -------- -------------- -------- ------- -------- Total Proved......... 25,051 21,436 193 151 781 644 907,679 549,580 466,610 408,952 Risked Probable...... 5,740 4,795 40 31 119 100 200,819 73,963 53,702 41,479 -------- ------- ------- -------- -------- -------- -------------- -------- ------- -------- Established.......... 30,790 26,231 233 182 900 744 1,108,498 623,543 520,312 450,431 ======== ======= ======= ======== ======== ======== ============== ======== ======= ========
*Does not include the value of the unproved lands 20
PETROLEUM AND NATURAL GAS RESERVES AND PRE-TAX NET CASH FLOWS CONSTANT COST AND PRICE CASE COMPANY INTEREST RESERVES ESTIMATED PRESENT WORTH OF FUTURE PRE-TAX NET CASH FLOWS ($000'S)* ----------------------------------------------------- ------------------------------------------ CRUDE OIL AND NATURAL GAS NATURAL GAS SULPHUR LIQUIDS (MBBLS) (BCF) (MLT) DISCOUNTED AT ----------------- ----------------- ----------------- --------------------------- GROSS NET GROSS NET GROSS NET UNDISCOUNTED 10% 15% 20% -------- ------- ------- -------- -------- -------- -------------- -------- ------- -------- Proved Producing........ 22,407 19,319 163 127 774 638 1,192,952 685,791 572,168 494,085 Non-Producing.... 3,182 2,520 30 24 7 7 203,096 105,103 82,287 66,769 -------- ------- ------- -------- -------- -------- -------------- -------- ------- -------- Total Proved......... 25,589 21,839 193 152 782 645 1,396,048 790,894 654,455 560,854 Risked Probable...... 5,797 4,818 40 31 121 100 304,421 113,667 82,701 63,853 -------- ------- ------- -------- -------- -------- -------------- -------- ------- -------- Established.......... 31,386 26,657 233 183 903 745 1,700,469 904,561 737,156 624,707 ======== ======= ======= ======== ======== ======== ============== ======== ======= ========
Notes: (1) Columns may not add due to rounding. (2) The following definitions have been used in the Gilbert Report: (a) "Proved Reserves" means those reserves estimated as recoverable with a high degree of certainty under current technology and existing economic conditions, in the case of constant price and cost analyses, and anticipated economic conditions in the case of escalated cost and price analyses, from that portion of a reservoir which can be reasonably evaluated as economically productive on the basis of analysis of drilling, geological, geophysical and engineering data, including the reserves to be obtained by enhanced recovery processes demonstrated to be economic and technically successful in the subject reservoir. (b) "Probable Reserves" means those reserves which analysis of drilling, geological, geophysical and engineering data does not demonstrate to be proved, but where such analysis suggests the likelihood of their existence and future recovery under current technology and existing or anticipated economic conditions. Probable additional reserves to be obtained by the application of enhanced recovery processes will be the increased recovery over and above that estimated in the proved category which can be realistically estimated for the pool on the basis of enhanced recovery processes which can be reasonably expected to be instituted in the future. (c) "Established Reserves" means those reserves estimated as Proved Reserves plus a portion of the Probable additional reserves, reduced to reflect the risks associated with recovery of those reserves. In the Gilbert Report, Established Reserves have been determined as the sum of 50 percent of Probable Reserves and 100 percent of Proved Reserves. (d) "Producing Reserves" means those reserves that are actually on production and could be recovered from existing wells and facilities or, if facilities have not been installed, that would involve a small investment relative to cash flow to install those facilities. In multi-well pools involving a competitive situation, reserves may be subdivided into producing and non-producing reserves in order to reflect allocation of reserves to specific wells and their respective development status. (e) "Non-Producing Reserves" means those reserves that are not classified as producing. (f) "Gross Reserves" means the total remaining recoverable reserves associated with the acreage of interest. (g) "Company Interest Gross Reserves" means the remaining reserves applicable to the properties, before deduction of any royalties. 21 (h) "Company Interest Net Reserves" means the gross remaining reserves applicable to the properties, less all royalties (but not the Royalty to the Trust) and interests owned by others. (3) In the Gilbert Report, the present worth values and quantities of Probable Reserves reported in the Established Reserves category have been reduced by 50 percent to reflect the degree of risk associated with the recovery of those reserves. (4) All natural gas reserve values are reserves remaining after deducting surface losses due to processing shrinkage and raw gas used as lease fuel. (5) The $US/$Cdn exchange rate is assumed in the Gilbert Report to be $0.6587 in 2001, $0.6667 in 2002 and $0.68 in 2003, $0.69 in 2004, and $0.70 in 2005. (6) The Gilbert Report estimates total capital expenditures (net to the PW Holding Entities) to achieve the estimated future pre-tax net cash flows from the Established Reserves based on escalating cost and price assumptions to be $46.9 million ($34.2 million if discounted by 15 percent per annum) with $14.0 million, $12.4 million and $6.1 million of those capital expenditures estimated for the calendar years 2001, 2002 and 2003 respectively. The corresponding capital expenditures to achieve the estimated future pre-tax net cash flows from the Established Reserves based on constant cost and price assumptions are $44.7 million ($31.6 million if discounted by 15 percent per annum) with $14.0 million, $12.2 million and $5.9 million of these capital expenditures estimated for the calendar years 2001, 2002 and 2003 respectively. (7) The Gilbert Report estimates total capital expenditures (net to the PW Holding Entities) to achieve the estimated future pre-tax net cash flows from the Proved Reserves based on escalating cost and price assumptions to be $32.5 million ($22.9 million if discounted by 15 percent per annum) with $11.9 million, $7.1 million and $3.4 million of those capital expenditures estimated for the calendar years 2001, 2002 and 2003, respectively. The corresponding capital expenditures to achieve the estimated future pre-tax net cash flows from the Proved Reserves based on constant cost and price assumptions are $31.1 million ($22.4 million if discounted by 15 percent per annum) with $11.9 million, $7.0 million and $3.3 million of these capital expenditures estimated for the calendar years 2001, 2002 and 2003, respectively. (8) The extent and character of the interests of the PW Holding Entities and the Trust evaluated in the Gilbert Report and all factual data supplied to Gilbert were accepted by Gilbert as represented. The crude oil and natural gas reserve calculations and any projections on which the Gilbert Report is based were determined in accordance with generally accepted petroleum engineering evaluation practices. (9) The constant cost and price evaluation was based on wellhead product prices as set forth below: (CDN.$) ------- Crude Oil..............................................$32.82 per bbl Condensate.............................................$39.83 per bbl Propane................................................$27.03 per bbl Butane.................................................$27.79 per bbl Ethane.................................................$19.71 per bbl Natural Gas.............................................$6.93 per mcf Sulphur................................................$18.73 per lt Operating and capital costs were not escalated in the constant cost and price evaluation. (10) In respect of the escalated cost and price valuation for the Gilbert Report, average yearly general product prices, which are referred to in these reports as the industry consensus as at January 1, 2001 for natural gas, crude oil, natural gas liquids and sulphur, are outlined in the following table. The figures in the following table were calculated as of that date as the arithmetic average 22 of the then current price forecasts of Gilbert, Sproule Associates Limited, and McDaniel & Associates Consultants Ltd.
LIGHT CRUDE OIL NATURAL GAS LIQUIDS OF EDMONTON NATURAL GAS ------------------------ --------------------------------- ------------------------------------ EDMONTON ALBERTA WTI PAR PRICE SPOT CUSHING 40 (DEGREE) PENTANES HENRY HUB AECO-C BC DIRECT OKLAHOMA* API PROPANE BUTANE PLUS $US/ $CDN./ $CDN./ SULPHUR $US/BBL $/BBL $/BBL $/BBL $/BBL MMBTU MMBTU MMBTU $/LT ---------- ----------- -------- -------- --------- ----------- --------- --------- ------- 2001 ..... 26.73 39.67 29.22 30.12 41.87 5.35 7.55 7.42 12.50 2002 ..... 23.80 34.63 24.26 24.88 35.81 4.13 5.62 5.42 14.82 2003 ..... 21.51 30.56 20.37 20.76 31.26 3.57 4.68 4.46 18.10 2004 ..... 21.58 30.20 19.40 19.69 30.54 3.38 4.32 4.11 22.02 2005 ..... 21.90 30.24 18.96 18.97 30.49 3.37 4.18 4.03 25.95 2006 ..... 22.34 30.47 19.10 19.10 30.72 3.41 4.18 4.02 26.81 2007 ..... 22.71 30.67 19.27 19.24 30.92 3.47 4.19 4.03 27.54 2008 ..... 23.07 31.06 19.52 19.47 31.32 3.53 4.24 4.09 28.47 2009 ..... 23.43 31.47 19.82 19.80 31.72 3.59 4.29 4.12 29.94 2010 ..... 23.88 31.99 20.24 20.16 32.25 3.65 4.38 4.22 31.14 2011 ..... 24.25 32.55 20.59 20.59 32.82 3.71 4.45 4.29 32.54 2012 ..... 24.62 33.09 20.89 20.87 33.35 3.77 4.52 4.37 33.67 2013 ..... 24.99 33.65 21.20 21.22 33.92 3.82 4.59 4.42 34.84 2014 ..... 25.36 34.22 21.55 21.54 34.49 3.89 4.66 4.49 36.08 2015 ..... 25.73 34.75 21.89 21.86 35.03 3.95 4.73 4.57 37.36
*40 degrees API, 0.4 percent sulphur (1) Operating and capital costs have been escalated at 1.67 percent annually for 17 years and 1 percent thereafter. 23 ESTIMATED PRE-TAX NET CASH FLOWS ESTABLISHED RESERVES OF THE PROPERTIES ESCALATING COST AND PRICE CASE ($millions except for production)
NET NET REVENUE ALBERTA CASH FLOW COMPANY AFTER ROYALTY NET NET BEFORE ANNUAL INTEREST ROYALTY ROYALTY TAX OPERATING PRODUCTION ABANDONMENT CAPITAL INCOME PRODUCTION REVENUE(1) BURDENS(2) BURDENS CREDIT EXPENSES(3) REVENUE(4) COSTS INVESTMENT TAXES(5)(6) -------------------------------------------------------------------------------------------------------------------- (mboe) ($) ($) ($) ($) ($) ($) ($) ($) ($) 2001...... 6,691 250.5 50.4 200.1 0.5 28.9 171.7 1.5 14.0 156.2 2002...... 6,319 190.4 36.4 153.9 0.5 28.7 125.7 1.4 12.4 111.9 2003...... 5,924 154.5 28.6 125.8 0.5 26.4 99.9 1.7 6.1 92.1 2004...... 5,297 131.3 23.3 107.9 0.5 24.7 83.7 1.9 1.9 79.9 2005...... 4,646 115.4 20.0 95.3 0.5 22.3 73.5 1.4 1.6 70.5 2006...... 4,190 104.7 18.2 86.4 0.5 21.2 65.7 0.9 2.9 61.9 2007...... 3,691 92.9 15.6 77.3 0.5 20.1 57.7 0.6 0.3 56.8 2008...... 3,280 83.8 13.8 70.0 0.5 19.3 51.2 0.5 0.5 50.2 2009...... 2,990 77.3 12.6 64.6 0.4 18.9 46.1 0.8 1.4 43.9 2010...... 2,683 70.9 11.3 59.6 0.4 18.1 41.9 0.5 1.0 40.4 2011...... 2,415 64.9 10.2 54.7 0.4 17.4 37.7 0.5 0.6 36.3 2012...... 2,191 60.0 9.2 50.7 0.4 17.1 34.0 1.0 0.4 32.6 Remainder. 19,263 596.2 83.0 513.2 3.0 218.0 298.2 19.2 3.9 275.1 ---------------------------------------------------------------------------------------------------------------------- TOTAL..... 69,580 1,992.5 332.8 1,659.7 8.6 481.1 1,187.2 32.0 46.9 1,108.5 ======================================================================================================================
Total net cash flow before income taxes discounted at: 10 percent: $623.5 million 15 percent: $520.3 million 20 percent: $450.4 million Notes: (1) Includes working-interest revenue and royalty-interest revenue. (2) Includes royalties net of processing allowances. (3) Includes other expenses, net-profits interest payments, capital and mineral taxes less third party processing and other income. (4) Company-interest revenue less Company interest royalty burdens and operating expenses. (5) Undiscounted. (6) Net cash flow before income taxes is stated prior to interest, general and administrative expenses and management fees. (7) Columns may not add due to roundingEstimated Pre-Tax Net Cash Flows Established Reserves of the Properties Constant Cost and Price Case ($millions except for production) 24
NET NET REVENUE ALBERTA CASH FLOW COMPANY AFTER ROYALTY NET NET BEFORE ANNUAL INTEREST ROYALTY ROYALTY TAX OPERATING PRODUCTION ABANDONMENT CAPITAL INCOME PRODUCTION REVENUE(1) BURDENS(2) BURDENS CREDIT EXPENSES(3) REVENUE(4) COSTS INVESTMENT TAXES(5)(6) -------------------------------------------------------------------------------------------------------------------- (mboe) ($) ($) ($) ($) ($) ($) ($) ($) ($) 2001....... 6,691 250.5 50.4 200.1 0.5 28.9 171.7 1.4 14.0 156.2 2002....... 6,327 238.2 48.0 190.2 0.5 28.7 162.0 1.3 12.2 148.4 2003....... 5,931 223.9 45.1 178.7 0.5 26.2 153.0 1.7 5.9 145.4 2004....... 5,299 200.5 39.6 160.9 0.5 23.8 137.6 1.6 1.8 134.2 2005....... 4,653 176.5 34.3 142.3 0.5 21.3 121.5 1.3 1.5 118.7 2006....... 4,197 160.3 31.3 129.0 0.5 19.6 109.9 0.8 2.6 106.4 2007....... 3,702 141.4 26.8 114.6 0.5 18.3 96.8 0.6 0.2 95.9 2008....... 3,289 125.6 23.3 102.3 0.5 17.3 85.5 0.6 0.5 84.4 2009....... 2,993 114.7 21.2 93.5 0.5 16.5 77.5 0.3 1.2 75.9 2010....... 2,694 103.2 18.6 84.5 0.5 15.6 69.4 0.4 0.9 68.0 2011....... 2,428 92.9 16.5 76.4 0.5 15.1 61.9 0.6 0.5 60.7 2012....... 2,201 84.1 14.7 69.5 0.5 14.4 55.7 0.4 0.3 54.8 Remainder.. 19,932 760.0 119.9 640.1 4.0 175.4 470.2 14.3 3.0 451.3 --------------------------------------------------------------------------------------------------------------------- TOTAL...... 70,337 2,671.7 489.5 2,182.2 10.0 421.4 1,770.5 25.5 44.7 1,700.5 =====================================================================================================================
Total net cash flow before income taxes discounted at: 10 percent: $904.6 million 15 percent: $737.2 million 20 percent: $624.7 million Notes: (1) Includes working-interest revenue and royalty-interest revenue. (2) Includes royalties net of processing allowances. (3) Includes other expenses, net-profits interest payments, capital and mineral taxes, less third party processing and other income. (4) Company-interest revenue less Company interest royalty burdens and operating expenses. (5) Undiscounted. (6) Net cash flow before income taxes is stated prior to interest, general and administrative expenses and management fees. (7) Columns may not add due to rounding. 25 PRINCIPAL PROPERTIES - PW HOLDING ENTITIES The following is a description of the significant properties owned by the PW Holding Entities as of January 1, 2001. Remaining Established Reserves, ultimate recovery estimates and working interests contained in the following property descriptions are derived from the Gilbert Report. The term "net" used in the following property descriptions refers to the working interest of the PW Holding Entities and the Trust in the properties. SUNDRE AREA The Sundre Area is comprised of properties located in Westward Ho, Garrington, Caroline and Ricinus. WESTWARD HO The Westward Ho properties are located approximately 50 miles northwest of Calgary, Alberta. The PW Holding Entities have a working interest in 33 (20.5 net) Non-Unit wells in Westward Ho, and a 98.7291 percent working interest in the Westward Ho Unit No. 1. The Gilbert Report assigns remaining Established Reserves of 851 mbbl of oil, 14,281 mmcf of natural gas and 752 mbbl of natural gas liquids (for a total of 3,983 mboe), before deduction of royalties, to the Westward Ho Area properties. The average net production from the properties for the year ended December 31, 2000 was approximately 411 bbls/d of oil and natural gas liquids, and 3,516 mcf/d of natural gas (for a total of 997 boe/d), before royalties. GARRINGTON The Garrington properties are located approximately 55 miles northwest of Calgary, Alberta. The PW Holding Entities have a working interest in 19 producing wells (13.3 net) in the Garrington non-unit area. Production is obtained from depths of 6,850 to 9,200 feet and, in general, consists of gassy, sweet 39-degree API light-gravity crude oil. The Gilbert Report assigns net remaining Established Reserves of 835 mbbl of oil, 2,755 mmcf of natural gas and 153 mbbl of natural gas liquids (for a total of 1,447 mboe), before deduction of royalties, to the Garrington Area properties. The average net production from the Garrington Area properties for the year ended December 31, 2000 was approximately 556 bbls/d of crude oil and natural gas liquids and 3,799 mcf/d of natural gas (for a total of 1,189 boe/d), before royalties. CAROLINE The Caroline properties are located approximately 60 miles northwest of Calgary, Alberta. The PW Holding Entities have a working interest in four separate contiguous properties in the Caroline Area - North Caroline Gas, South Leg, East Caroline, SW Caroline/Northridge and West Caroline. The Gilbert Report assigns remaining Established Reserves of 165 mbbl of oil, 37,155 mmcf of natural gas and 2,145 26 mbbl of natural gas liquids (for a total of 8,503 mboe), before deduction of royalties. The average net production from the Caroline Area properties for the year ended December 31, 2000 was approximately 230 bbls/d of oil and natural gas liquids and 2,511 mcf/d of natural gas (for a total of 649 boe/d), before royalties. RICINUS The Ricinus Cardium Unit #2 is located approximately 85 miles northwest of Calgary. The PW Holding Entities own a 53.5 percent operated working interest in the Unit and a 1.8 percent interest in the Amoco operated Ricinus gas plant. The Gilbert Report assigns net Remaining Established Reserves of 161 mbbls of oil, 6,719 mmcf of natural gas and 260 mbbls of natural gas liquids (for a total of 1,540 mboe), before deduction of royalties. Average net production for the Ricinus property for the year ended December 31, 2000 was 85 bbls/d of oil; 2,183 mcf of natural gas and 115 bbls/d of natural gas liquids (for a total of 564 boe/d), before deduction of royalties. LAPRISE CREEK AREA The Laprise Creek Area is located in northeast British Columbia, approximately 110 miles northwest of Fort St. John, British Columbia. Gas is produced from the Baldonnel Formation at a depth of approximately 4,200 feet. The Laprise Creek Baldonnel "A" Pool is one of British Columbia's largest natural gas pools, having original gas-in-place of 880 bcf. The PW Holding Entities have a 75.6 percent working interest in the Laprise Creek Baldonnel Unit No. 1, which is operated by PrimeWest. The Unit consists of 20 (15.1 net) producing natural gas wells and one (0.76 net) suspended well. In addition, the PW Holding Entities have a 100 percent interest in one producing non-unit gas well. The Gilbert Report assigns net remaining Established Reserves of 45,345 mmcf of natural gas and 1,157 mbbl of natural gas liquids (for a total of 8,714 mboe), before deduction of royalties, to the Laprise Creek Area properties. The average net production from the Laprise Creek Area properties for the year ended December 31, 2000 was approximately 9,268 mcf/d of natural gas and 193 bbls/d of crude oil and natural gas liquids (for a total of 1,738 boe/d), before deduction of royalties. SOUTHEASTERN ALBERTA AREA GRAND FORKS The Grand Forks property is located 45 miles west of Medicine Hat, Alberta. Crude oil reserves are found in the Sawtooth formation at an average depth of 3,100 feet. The PW Holding Entities have an average 71 percent working interest in 180 (127 net) producing oil wells and a 41.5 percent working interest in 11 (4.57 net) non-producing natural gas wells. 27 The Gilbert Report assigns net remaining Established Reserves of 7,303 mbbl of oil and natural gas liquids and 884 mmcf of natural gas (for a total of 7,786 net mboe), before deduction of royalties to the Grand Forks property. The average net production from the Grand Forks property for the year ended December 31, 2000 was approximately 2,963 bbls/d of crude oil and natural gas liquids and 431 mcf/d of natural gas (for a total of 3,035 boe/d), before deduction of royalties. MEDICINE HAT The Medicine Hat property covers a 25 mile radius around Medicine Hat, Alberta. The Gilbert Report assigns net remaining Established Reserves of 345 mbbl of oil and 18,456 mmcf of natural gas (for a total of 3,421 net mboe), before deduction of royalties to the Medicine Hat properties. The average net production from the Medicine Hat properties for the year ended December 31, 2000 was approximately 118 bbls/d of crude oil and natural gas liquids and 3,221 mcf/d of natural gas (for a total of 655 boe/d), before deduction of royalties. PrimeWest operates and the PW Holding Entities have a 96.7 percent average working interest in 17 oil wells (16 net) in the Medicine Hat Glauconitic C Pool. The PW Holding Entities have a 49.44 percent working interest in the PrimeWest operated Medicine Hat Consolidated Unit #2 which is located 25 miles northeast of Medicine Hat. PrimeWest operates and the PW Holding Entities have a 100 percent interest in the Etzikom gas field. Gas is produced from the Medicine Hat "A", "C", "D", Lower Colorado and Milk River zones. DINOSAUR/PATRICIA The Dinosaur/Patricia area is located approximately 110 miles east of Calgary. The PW Holding Entities own a 51 percent operated interest in both the Patricia Gas Unit #1 and the Dinosaur Gas Unit #1. There are currently 69 producing gross (35.2 net) wells in the Patricia Unit and 25 producing gross (12.75 net) wells in the Dinosaur Unit. The Gilbert Report assigns net Remaining Established Reserves of 12,920 mmcf of gas, before deduction of royalties. The average net production from the Dinosaur/Patricia property for the year ended December 31, 2000 was approximately 2,650 mcf/d of gas, before deduction of royalties. CROSSFIELD/LONE PINE CREEK AREA The Crossfield/Lone Pine Creek Area is located approximately 20 miles north of Calgary, Alberta, and was discovered in 1960. Production of natural gas and natural gas liquids occurs from the Elkton, Wabamun (Crossfield), Leduc and Nisku Formations. Oil production occurs from the Cardium, Basal Quartz, Elkton and Nisku Formations. The Gilbert Report assigns net remaining Established Reserves of 314 mbbl of oil, 49,406 mmcf of natural gas and 584 mbbl of natural gas liquids (for a total of 9,132 mboe), before deduction of royalties, and 673 mlt of sulphur to the East Crossfield/Lone Pine Creek Area properties. The aggregate average net daily sales volumes from this area for the year ended December 31, 2000 was approximately 28 12,123 mcf/d of natural gas and 323 bbls/d of oil and natural gas liquids (for a total of 2,343 boe/d), in each case before royalties. PrimeWest operates and the PW Holding Entities have a net working interest in the following: 54.6 percent in the East Crossfield Unit - Crossfield Formation, 68.4 percent in the Lone Pine Creek Gas Unit No. 1, 75 percent in the Lone Pine Creek Gas Unit No. 3, 76.6 percent in the Lone Pine Creek Gas Unit No. 5, 65.9 percent in the Lone Pine Creek D-3 Gas Unit No. 1, 100 percent in the East Crossfield Elkton "F" Pool, five (4.3 net) non-unit gas wells and a 100 percent working interest in one non-unit oil well. In addition, the PW Holding Entities have varying working interests averaging 25 percent in two non-operated oil wells, and a 100 percent working interest in two PrimeWest-operated, producing natural gas wells. All operated natural gas production is processed at the East Crossfield Sour Gas Processing Facility. Originally, PrimeWest had a 20 percent interest in the facility. Effective January 5, 2000, PrimeWest acquired Amoco's 34.6 percent interest and became operator of the facility. In May 2000, PrimeWest sold a 25.8 percent interest to a third party for cash and a dedication of the third party gas reserves to the plant for life. After this sale, PrimeWest's ownership in the facility is 28.8 percent. All of the PW Holding Entities' natural gas produced from this area is processed on a plant operating-cost basis. During 2000, plant utilization was approximately 75 percent. Other major facilities owned by PrimeWest in respect of this property include the Lone Pine Creek Central Gathering and Compression Facility (42.8 percent interest), the Lone Pine Creek Waukesha Compressors (50.1 percent interest), the Lone Pine Creek D-1 Unit Booster Compressor (68.4 percent interest) and the Lone Pine Creek to East Crossfield Amalgamation Pipeline (40.2 percent interest). PrimeWest has made arrangements with a number of companies to bring third party natural gas to the East Crossfield plant, bringing the 2000 throughput to approximately 71 mmcf/d. Discussions are continuing with a number of parties to attract additional volumes. BOUNDARY LAKE AREA The Boundary Lake Area is located approximately 25 miles east of Fort St. John, British Columbia on the British Columbia/Alberta border. The Boundary Lake Field was discovered in 1955. The productive horizon is the Boundary Lake member of the Triassic Charlie Lake Formation at a depth of approximately 4,200 feet, which produces a 35-degree API light-gravity crude oil and solution gas. PrimeWest operates and the PW Holding Entities have a 100 percent working interest in both Boundary Lake Project No. 1, and Boundary Lake Project No. 2, (both projects are located in British Columbia), varying working interests averaging 4.2 percent in three producing oil wells operated by Imperial Oil Limited in the British Columbia portion of the field and a 25 percent working interest in a producing oil well operated by PrimeWest in the Alberta portion of the field. The PW Holding Entities also have a 2.1 percent working interest in the 29 Boundary Lake Unit No. 1. The Gilbert Report assigns remaining Established Reserves of 5,151 mbbl of oil, 544 mmcf of natural gas and 45 mbbl of natural gas liquids (for a total of 5,286 mboe), before deduction of royalties, to the Boundary Lake Area properties. The average net production from the Boundary Lake Area properties for the year ended December 31, 2000 was approximately 819 bbls/d of oil and natural gas liquids and 1 mcf/d of natural gas (for a total of 820 boe/d), in each case before royalties. KAYBOB SOUTH AREA The Kaybob South Area is located approximately 150 miles northwest of Edmonton, Alberta and consists of oil and solution gas production from the Kaybob South Triassic "A" Pool at a depth of approximately 7,000 feet. The PW Holding Entities have a 42.5 percent working interest in the Kaybob South Triassic Unit No. 1 and a 20.1 percent working interest in the Kaybob South Triassic Unit No. 2, both of which are operated by PrimeWest. The Gilbert Report assigns net remaining Established Reserves of 1,624 mbbl of oil, 1,178 mmcf of natural gas and 125 mbbl of natural gas liquids (for a total of 1,945 mboe), before deduction of royalties, to the Kaybob South Area properties. The average net production from the Kaybob South Area properties for the year ended December 31, 2000 was 676 bbls/d of oil and natural gas liquids and 258 mcf/d (for a total of 719 boe/d), before deduction of royalties. OTHER PROPERTIES The following is a description of the balance of the PW Holding Entities' and the Trust's properties. These properties represent approximately 23.2 percent of the total reserves of all of the properties and consist of small working interests in unitized properties and Gross Overriding Royalty interests in larger fields. JUMPING POUND WEST The PW Holding Entities have a 14.6 percent interest in the Jumping Pound West Unit No. 2 operated by Shell Canada Limited and located 30 miles west of Calgary. The unitized zone is the Rundle Formation. Production from the unit commenced in 1972 and is currently coming from 12 natural gas wells. Production is processed at the adjacent Jumping Pound Unit No. 1 plant facilities on a custom-processing-fee basis. The production is slightly sour and liquid rich, yielding 40 bbls of liquids per mmcf of natural gas. The Gilbert Report assigns net remaining Established Reserves of 12,031 mmcf of natural gas and 502 mbbls of natural gas liquids (for a total of 2,507 net mboe), before deduction of royalties, to the Jumping Pound West property. Average net production for the year ended December 31, 2000 was 2,630 mcf/d of natural gas and 83 bbls/d of natural gas liquids (for a total of 522 boe/d), before deduction of royalties. 30 EAGLE LAKE VIKING VOLUNTARY UNIT The PW Holding Entities have a 9.4 percent working interest in the Eagle Lake Viking Voluntary Unit operated by Viking Holdings Management Ltd. The Unit was formed in 1966, and is located approximately 90 miles southwest of Saskatoon, Saskatchewan. The unitized zone consists of the Viking Formation, and 38 degree API light-gravity crude oil is recovered by waterflood, which was implemented in 1967. The Gilbert Report assigns net remaining Established Reserves of 770 mboe, before deduction of royalties, to the Eagle Lake Viking Voluntary Unit. Net oil production for the unit for the year ended December 31, 2000 averaged 125 boe/d before royalties. MIDALE UNIT The PW Holding Entities have a 3.9 percent interest in the Apache-operated Midale Unit located in southeast Saskatchewan. The Unit was formed in 1962 when a waterflood project was implemented. Since that time, the operator has undertaken an infill drilling program, first vertical and then horizontal, commencing in 1989. Recent activity in the Unit consists of multiple-leg horizontal drilling projects. In addition, enhanced recovery from C02 miscible flood was started in 1992, but suspended in March 1999. The Gilbert Report assigns net remaining Established Reserves of 2,002 mbbls of oil and 170 mmcf of natural gas (for a total of 2,030 mboe) to the Midale Unit property, before deduction of royalties. Average net production from the property for the year ended December 31, 2000 was 271 boe/d. An aggressive infill-drilling program was initiated in 2000, resulting in 20 - 30 new wells annually for several years. WILLESDEN GREEN The Willesden Green properties are located approximately 10 miles northeast of Rocky Mountain House, Alberta. The PW Holding Entities have a 13.4 percent working interest and a 0.29 percent royalty interest in the Petro-Canada operated Willesden Green Cardium Unit No. 6, as well as varying minor royalty interests in units 1, 2, 4, 7 and 8. The Unit produces a 40-degree API light-gravity crude oil from the Willesden Green Cardium "A" Pool at a depth of approximately 6,230 feet. The Pool was discovered in 1959 and Unit No. 6 was formed in 1966 when a field wide waterflood scheme was implemented. The Gilbert Report assigns net remaining Established Reserves of 1,166 mboe, before deduction of royalties, to the Willesden Green properties. Average net production for the Willesden Green area for the year ended December 31, 2000, was 185 bbls/d of oil and natural gas liquids and 172 mcf/d of natural gas, before royalties (for a total of 214 boe/d). Drilling and completion of three infill wells was in progress by year end. BONNIE GLEN The PW Holding Entities have a 0.77 percent interest in the Bonnie Glen D-3A Gas Cap Unit and the Bonnie Glen Cycling Plant as well as a 55 percent interest in the 31 12-8-47-27W4 Proration Battery and two producing oil wells. The property is operated by Imperial Oil Resources. The Gilbert Report assigns net remaining Established Reserves of 102 mbbls of oil and natural gas liquids and 906 mmcf of gas (for a total of 253 mboe) to the Bonnie Glen property, before deduction of royalties. Average net production from the property for the year ended December 31, 2000 was 132 bbls/d of oil and natural gas liquids and 1,682 mcf/d of gas (for a total of 412 boe/d). GROSS OVERRIDING ROYALTY INTERESTS In July 2000, Royalty Corp. acquired Reserve Royalty Corp., a company owning mainly Gross Overriding Royalty Interests (GORRs). Following this acquisition, the GORRs were conveyed directly to the Trust. These interests entitle the holder a gross sales price on production from the property generally without deduction for royalties and operating expenses. The Gilbert Report assigns net remaining Established Reserves of 2,837 mmbls of oil and natural gas liquids and 15,294 mmcf of gas to the GORR interests acquired from Reserve Royalty. The production from these GORR interests for the period from July 27, 2000 to December 31, 2000 was 1,574 boepd (1,030 bbls/d of crude oil and natural gas liquids and 3.2 mmcf/d of gas). UNPROVED LANDS - PW HOLDING ENTITIES The PW Holding Entities have an interest in approximately 530,430 (448,163 net) acres of unproved lands at December 31, 2000. PrimeWest is currently reviewing available seismic and other data, and will develop an exploitation plan for these properties. Capital expenditures, farmouts and/or dispositions may result in future revenues from these undeveloped lands. The geographical area and value of the unproved lands is as follows: UNPROVED LANDS AREA ACRES NET VALUE ----------------------------------- --------------------------- ------------- GROSS NET ($) Sundre Caroline 71,237 56,841 3,279,350 Garrington 23,638 12,329 206,100 Westward Ho 9,230 8,448 193,100 Kobes Creek 7,160 2,864 253,100 Southeastern Alberta 53,648 30,397 981,642 Crossfield/Lone Pine Creek 55,060 42,181 4,659,092 Boundary Lake 4,820 4,620 9,900 Gross Overriding Royalty Interests 243,797 243,797 3,678,909 Others 61,840 46,686 3,976,909 --------------------------- ------------- TOTAL 530,430 448,163 17,238,102 =========================== ============= 32 RESERVE CONTINUITY - CYPRESS Gilbert Laustsen Jung Associates Ltd., independent petroleum consultants, ("Gilbert"), has prepared a reserves report ("Gilbert Report") evaluating the crude oil, natural gas, natural gas liquids and sulphur reserves attributable to properties owned by Cypress Energy Inc. as at January 1, 2001. The following table sets forth the reconciliation of the Established Reserves of Cypress Energy Inc. for the year ended December 31, 2000.
RECONCILIATION OF NET COMPANY INTEREST RESERVES OIL & NATURAL ----------------------------------------------- GAS LIQUIDS NATURAL GAS TOTAL(1)(2) (MMBBLS) (BCF) (MMBOE) ----------------- -------------- ------------------ As at January 1, 2000 11.40 195.95 44.06 Capital Development Program and Revisions 4.50 68.16 15.88 Acquisitions, net of dispositions 3.10 2.70 3.55 Production (1.90) (24.77) (6.02) ----------------- -------------- ------------------ As at January 1, 2001 17.10 242.04 57.44 ================= ============== ================== Net Increase in Reserves 5.70 46.09 13.38 Percent Increase 50% 24% 30% ================= ============== ==================
(1) may not add due to rounding (2) gas reserves converted to mmboe on the basis of 6:1 DRILLING ACTIVITY - CYPRESS During the last two financial years, Cypress Energy Inc. drilled or participated in the drilling of the following wells: YEAR ENDED YEAR ENDED DECEMBER 31, 2000 DECEMBER 31, 1999 ------------------- -------------------- Gross Net Gross Net --------- -------- --------- ---------- Natural Gas.... 98 68.3 41 30.0 Crude Oil...... 20 8.1 9 7.5 Dry 31 25 21 16.5 --------- -------- --------- ---------- Total 149 101.4 71 54.0 ========= ======== ========= ========== 33 CAPITAL EXPENDITURES - CYPRESS The following table sets forth the capital expenditures by Cypress Energy Inc. for the last two financial years: Year Ended Year Ended December 31, 2000 December 31, 1999 (000's) (000's) ------------------------------------ ----------------- ------------------ Drilling, completion & Facilities 91,688 45,446 Property acquisitions, net of dispositions (includes corporate acquisitions) 43,082 117,664 Head Office 326 298 ----------------- ------------------ 135,096 163,408 ================= ================== RECENT DEVELOPMENTS - CYPRESS On March 23, 2001, Cypress completed the acquisition of Ranchero Energy Inc. whereby approximately 97 percent of the Ranchero shares were tendered to Cypress offer dated February 28, 2001. The remaining shares were acquired pursuant to the compulsory acquisition provision of Canadian corporate law. Under the terms of the offer Cypress paid $26.5 million in cash and issued 1.077 million common shares to Ranchero shareholders. The following tables summarize Ranchero Energy Inc. Petroleum and Natural Gas Reserves and Estimated Pre-Tax Net Cash Flows.
PETROLEUM AND NATURAL GAS RESERVES AND PRE-TAX NET CASH FLOWS ESCALATING COST AND PRICE CASE CRUDE OIL AND NATURAL GAS NATURAL GAS SULPHUR LIQUIDS (MBBLS) (BCF) (MLT) DISCOUNTED AT ----------------- ----------------- ----------------- --------------------------- GROSS NET GROSS NET GROSS NET UNDISCOUNTED 10% 15% 20% -------- ------- ------- -------- -------- -------- -------------- -------- ------- -------- Proved 311.0 254.0 8.6 6.4 0.0 0.0 23,726 20,415 19,117 17,992 Producing Non-Producing.... 0.0 0.0 0.0 0.0 0.0 0.0 0 0 0 0 -------- ------- ------- -------- -------- -------- -------------- -------- ------- -------- Total Proved......... 311.0 254.0 8.6 6.4 0.0 0.0 23,726 20,415 19,117 17,992 Risked Probable...... 79.0 68.5 0.0 0.0 0.0 0.0 1,033 777.5 711.5 656.5 -------- ------- ------- -------- -------- -------- -------------- -------- ------- -------- Established.......... 390.0 322.5 8.6 6.4 0.0 0.0 24,759 21,193 19,828 18,649 ======== ======= ======= ======== ======== ======== ============== ======== ======= ========
34 ESTIMATED PRE-TAX NET CASH FLOWS ESTABLISHED RESERVES OF THE PROPERTIES ESCALATING COST AND PRICE CASE ($ MILLIONS EXCEPT FOR PRODUCTION)
NET NET REVENUE ALBERTA CASH FLOW COMPANY AFTER ROYALTY NET NET BEFORE ANNUAL INTEREST ROYALTY ROYALTY TAX OPERATING PRODUCTION ABANDONMENT CAPITAL INCOME PRODUCTION REVENUE(1) BURDENS(2) BURDENS CREDIT EXPENSES(3) REVENUE(4) COSTS INVESTMENT TAXES(5)(6) -------------------------------------------------------------------------------------------------------------------- (mboe) ($) ($) ($) ($) ($) ($) ($) ($) ($) 2001...... 441 18.3 5.3 13.0 0 2.9 10.1 0.0 0.1 10.0 2002...... 421 13.5 3.8 9.7 0 3.0 6.7 0.0 0.1 6.6 2003...... 294 8.0 2.0 6.0 0 2.4 3.6 0.0 0.0 3.5 2004...... 204 5.2 1.3 3.9 0 1.9 2.0 0.0 0.2 1.8 2005...... 140 3.4 0.8 2.6 0 1.5 1.1 0.0 0.2 1.0 2006...... 115 2.5 0.6 1.9 0 1.1 0.8 0.0 0.2 0.6 2007...... 69 1.7 0.4 1.3 0 0.8 0.5 0.0 0.2 0.3 2008...... 46 1.2 0.2 1.0 0 0.5 0.5 0.0 0.1 0.3 2009...... 32 0.8 0.2 0.6 0 0.4 0.2 0.0 0.1 0.2 2010...... 21 0.5 0.1 0.4 0 0.3 0.1 0.0 0.1 0.2 2011...... 16 0.4 0.1 0.3 0 0.2 0.1 0.0 0.0 0.1 2012...... 13 0.4 0.1 0.3 0 0.2 0.1 0.0 0.0 0.1 Remainder. 24 0.4 0.0 0.6 0 0.4 0.7 0.0 0.1 0.1 ------------------------------------------------------------------------------------------------------------------------- TOTAL..... 1,836 56.3 14.7 41.6 0 15.5 26.2 0.0 1.4 24.7 =========================================================================================================================
Total net cash flow before income taxes discounted at: 10 percent: $21.2 million 15 percent: $19.8 million 20 percent: $18.7 million Notes: (1) Includes working-interest revenue and royalty-interest revenue. (2) Includes royalties net of processing allowances. (3) Includes other expenses, net-profits interest payments, capital and mineral taxes less third party processing and other income. (4) Company-interest revenue less Company interest royalty burdens and operating expenses. (5) Undiscounted. (6) Net cash flow before income taxes is stated prior to interest, general and administrative expenses and management fees. (7) Columns may not add due to rounding. ATTRIBUTES OF THE PROPERTIES - CYPRESS The properties of Cypress Energy Inc. include interests in both unitized and non-unitized oil and natural gas production from several major oil and natural gas fields. The following characteristics, as at December 31, 2000, make the properties suitable for a conventional crude oil and natural gas royalty trust structure: (a) OPERATED PROPERTIES: Approximately 90 percent of the total production from the properties is operated by Cypress. In respect of these operated properties, Cypress is able to exercise management and operating influence to maximize value of the properties; 35 (b) GAS WEIGHTED PORTFOLIO: Production from the properties is approximately 30 percent crude oil and natural gas liquids and 70 percent natural gas, on a barrel-of-oil-equivalent basis. Established Reserves for the properties is approximately 30 percent crude oil and natural gas liquids and 70 percent natural gas on a barrel-of-oil-equivalent basis; (c) CONCENTRATED PORTFOLIO: While the properties are diversified from a geological and geographic perspective, Cypress Energy Inc. generally have the largest working interest in these properties; and (d) UPSIDE POTENTIAL: Additional opportunities to enhance the value of the properties have been identified by PrimeWest. These opportunities may not have been included in the valuations provided in the Gilbert Report. OIL AND NATURAL GAS RESERVES - CYPRESS Gilbert has prepared the Gilbert Report evaluating the properties as at January 1, 2001. THE GILBERT REPORT EVALUATES THE CRUDE OIL, NATURAL GAS, NATURAL GAS LIQUIDS AND SULPHUR RESERVES ATTRIBUTABLE TO THE PROPERTIES PRIOR TO PROVISION FOR INCOME TAXES, INTEREST COSTS, GENERAL AND ADMINISTRATIVE EXPENSES AND MANAGEMENT FEES, BUT AFTER PROVIDING FOR ESTIMATED ROYALTIES, OPERATING COSTS, OTHER INCOME, FUTURE CAPITAL EXPENDITURES AND FACILITY SITE RESTORATION, WELL ABANDONMENT AND WELL-SITE RESTORATION COSTS. PROBABLE ADDITIONAL RESERVES AND THE PRESENT WORTH OF THOSE RESERVES AS SET FORTH IN THE TABLES BELOW HAVE BEEN REDUCED BY 50 PERCENT TO REFLECT THE DEGREE OF RISK ASSOCIATED WITH RECOVERY OF THOSE RESERVES. It should not be assumed that the discounted future net cash flows estimated by Gilbert represent the fair market value of these reserves. Other assumptions and qualifications relating to costs, prices for future production and other matters are summarized in the notes following these tables. 36
PETROLEUM AND NATURAL GAS RESERVES AND PRE-TAX NET CASH FLOWS ESCALATING COST AND PRICE CASE COMPANY INTEREST RESERVES ESTIMATED PRESENT WORTH OF FUTURE PRE-TAX NET CASH FLOWS ($000'S)* ----------------------------------------------------- ------------------------------------------ CRUDE OIL AND NATURAL GAS NATURAL GAS SULPHUR LIQUIDS (MBBLS) (BCF) (MLT) DISCOUNTED AT ----------------- ----------------- ----------------- --------------------------- GROSS NET GROSS NET GROSS NET UNDISCOUNTED 10% 15% 20% -------- ------- ------- -------- -------- -------- -------------- -------- -------- -------- Proved Producing........ 11,730 9,327 149 116 - - 638,499 423,791 374,668 339,220 Non-Producing.... 2,842 2,180 59 44 26 21 188,425 113,087 94,873 81,810 -------- ------- ------- -------- -------- -------- -------------- -------- -------- -------- Total Proved......... 14,572 11,507 208 160 26 21 826,924 536,878 469,541 421,030 Risked Probable...... 2,581 2,004 34 28 5 4 127,068 56,099 43,189 34,859 -------- ------- ------- -------- -------- -------- -------------- -------- -------- -------- Established.......... 17,153 13,511 242 188 31 25 953,992 592,977 512,730 455,889 ======== ======= ======= ======== ======== ======== ============== ======== ======== ======== PETROLEUM AND NATURAL GAS RESERVES AND PRE-TAX NET CASH FLOWS CONSTANT COST AND PRICE CASE COMPANY INTEREST RESERVES ESTIMATED PRESENT WORTH OF FUTURE PRE-TAX NET CASH FLOWS ($000'S)* COMPANY INTEREST RESERVES ESTIMATED PRESENT WORTH OF FUTURE PRE-TAX NET CASH FLOWS ($000'S)* ----------------------------------------------------- ------------------------------------------ CRUDE OIL AND NATURAL GAS NATURAL GAS SULPHUR LIQUIDS (MBBLS) (BCF) (MLT) DISCOUNTED AT ----------------- ----------------- ----------------- --------------------------- GROSS NET GROSS NET GROSS NET UNDISCOUNTED 10% 15% 20% -------- ------- ------- -------- -------- -------- -------------- -------- -------- -------- Proved 12,040 9,541 149 116 0 0 984,558 605,811 520,315 459,643 Producing........ Non-Producing.... 2,822 2,136 59 44 26 21 323,904 187,601 154,737 131,373 -------- ------- ------- -------- -------- -------- -------------- -------- -------- -------- Total Proved......... 14,862 11,677 208 160 26 21 1,308,462 793,412 675,052 591,016 Risked Probable...... 2,642 2,025 34 28 5 4 216,423 93,525 71,041 56,593 -------- ------- ------- -------- -------- -------- -------------- -------- -------- -------- Established.......... 17,504 13,702 242 188 31 25 1,524,885 886,937 746,093 647,609 ======== ======= ======= ======== ======== ======== ============== ======== ======== ========
*Does not include the value of the unproved lands Notes: (1) Columns may not add due to rounding. (2) The following definitions have been used in the Gilbert Report: (a) "Proved Reserves" means those reserves estimated as recoverable with a high degree of certainty under current technology and existing economic conditions, in the case of constant price and cost analyses, and anticipated economic conditions in the case of escalated cost and price analyses, from that portion of a reservoir which can be reasonably evaluated as economically productive on the basis of analysis of drilling, geological, geophysical and engineering data, including the reserves to be obtained by enhanced recovery processes demonstrated to be economic and technically successful in the subject reservoir. (b) "Probable Reserves" means those reserves which analysis of drilling, geological, geophysical and engineering data does not demonstrate to be proved, but where such analysis suggests the likelihood of their existence and future recovery under current technology and existing or anticipated economic conditions. Probable additional reserves to be obtained by the application of enhanced recovery processes will be the increased recovery over and above that estimated in the proved category which can be realistically estimated for the pool on the basis of enhanced recovery processes which can be reasonably expected to be instituted in the future. 37 (c) "Established Reserves" means those reserves estimated as Proved Reserves plus a portion of the Probable additional reserves, reduced to reflect the risks associated with recovery of those reserves. In the Gilbert Report, Established Reserves have been determined as the sum of 50 percent of Probable Reserves and 100 percent of Proved Reserves. (d) "Producing Reserves" means those reserves that are actually on production and could be recovered from existing wells and facilities or, if facilities have not been installed, that would involve a small investment relative to cash flow to install those facilities. In multi-well pools involving a competitive situation, reserves may be subdivided into producing and non-producing reserves in order to reflect allocation of reserves to specific wells and their respective development status. (e) "Non-Producing Reserves" means those reserves that are not classified as producing. (f) "Gross Reserves" means the total remaining recoverable reserves associated with the acreage of interest. (g) "Company Interest Gross Reserves" means the remaining reserves applicable to the properties, before deduction of any royalties. (h) "Company Interest Net Reserves" means the gross remaining reserves applicable to the properties, less all royalties (but not the Royalty) and interests owned by others. (3) In the Gilbert Report, the present worth values and quantities of Probable Reserves reported in the Established Reserves category have been reduced by 50 percent to reflect the degree of risk associated with the recovery of those reserves. (4) All natural gas reserve values are reserves remaining after deducting surface losses due to processing shrinkage and raw gas used as lease fuel. (5) The $US/$Cdn exchange rate is assumed in the Gilbert Report to be $0.6587 in 2001, $0.6667 in 2002 and $0.68 in 2003, $0.69 in 2004, and $0.70 in 2005. (6) The Gilbert Report estimates total capital expenditures (net to Cypress Energy Inc.) to achieve the estimated future pre-tax net cash flows from the Established Reserves based on escalating cost and price assumptions to be $31.6 million ($25.8 million if discounted by 15 percent per annum) with $19 million, $5.7 million and $2.5 million of those capital expenditures estimated for the calendar years 2001, 2002 and 2003 respectively. The corresponding capital expenditures to achieve the estimated future pre-tax net cash flows from the Established Reserves based on constant cost and price assumptions are $32.1 million ($25.7 million if discounted by 15 percent per annum) with $19 million, $5.7 million and $2.5 million of these capital expenditures estimated for the calendar years 2001, 2002 and 2003 respectively. (7) The Gilbert Report estimates total capital expenditures (net to Cypress Energy Inc.) to achieve the estimated future pre-tax net cash flows from the Proved Reserves based on escalating cost and price assumptions to be $27.1 million ($22.3 million if discounted by 15 percent per annum) with $16.9 million, $4.7 million and $1.7 million of those capital expenditures estimated for the calendar years 2001, 2002 and 2003, respectively. The corresponding capital expenditures to achieve the estimated future pre-tax net cash flows from the Proved Reserves based on constant cost and price assumptions are $27 million ($22.5 million if discounted by 15 percent per annum) with $16.9 million, $4.7 million and $1.6 million of these capital expenditures estimated for the calendar years 2001, 2002 and 2003, respectively. (8) The extent and character of the interests of Cypress Energy Inc. evaluated in the Gilbert Report and all factual data supplied to Gilbert were accepted by Gilbert as represented. The crude oil and natural gas reserve calculations and any projections on which the Gilbert Report is based were determined in accordance with generally accepted petroleum engineering evaluation practices. 38 (9) The constant cost and price evaluation was based on wellhead product prices as set forth below: (CDN.$) ------- Crude Oil................................................$32.82 per bbl Condensate...............................................$39.83 per bbl Propane..................................................$27.03 per bbl Butane...................................................$27.79 per bbl Ethane...................................................$19.71 per bbl Natural Gas...............................................$6.93 per mcf Sulphur..................................................$18.73 per lt Operating and capital costs were not escalated in the constant cost and price evaluation. (10) In respect of the escalated cost and price valuation for the Gilbert Report, average yearly general product prices, which are referred to in these reports as the industry consensus as at January 1, 2001 for natural gas, crude oil, natural gas liquids and sulphur, are outlined in the following table. The figures in the following table were calculated as of that date as the arithmetic average of the then current price forecasts of Gilbert, Sproule Associates Limited, and McDaniel & Associates Consultants Ltd.
LIGHT CRUDE OIL NATURAL GAS LIQUIDS OF EDMONTON NATURAL GAS ------------------------ --------------------------------- ------------------------------------ EDMONTON ALBERTA WTI PAR PRICE SPOT CUSHING 40 (DEGREE) PENTANES HENRY HUB AECO-C BC DIRECT OKLAHOMA* API PROPANE BUTANE PLUS $US/ $CDN./ $CDN./ SULPHUR $US/BBL $/BBL $/BBL $/BBL $/BBL MMBTU MMBTU MMBTU $/LT ---------- ----------- -------- -------- --------- ----------- --------- --------- ------- 2001...... 26.73 39.67 29.22 30.12 41.87 5.35 7.55 7.42 12.50 2002...... 23.80 34.63 24.26 24.88 35.81 4.13 5.62 5.42 14.82 2003...... 21.51 30.56 20.37 20.76 31.26 3.57 4.68 4.46 18.10 2004...... 21.58 30.20 19.40 19.69 30.54 3.38 4.32 4.11 22.02 2005...... 21.90 30.24 18.96 18.97 30.49 3.37 4.18 4.03 25.95 2006...... 22.34 30.47 19.10 19.10 30.72 3.41 4.18 4.02 26.81 2007...... 22.71 30.67 19.27 19.24 30.92 3.47 4.19 4.03 27.54 2008...... 23.07 31.06 19.52 19.47 31.32 3.53 4.24 4.09 28.47 2009...... 23.43 31.47 19.82 19.80 31.72 3.59 4.29 4.12 29.94 2010...... 23.88 31.99 20.24 20.16 32.25 3.65 4.38 4.22 31.14 2011...... 24.25 32.55 20.59 20.59 32.82 3.71 4.45 4.29 32.54 2012...... 24.62 33.09 20.89 20.87 33.35 3.77 4.52 4.37 33.67 2013...... 24.99 33.65 21.20 21.22 33.92 3.82 4.59 4.42 34.84 2014...... 25.36 34.22 21.55 21.54 34.49 3.89 4.66 4.49 36.08 2015...... 25.73 34.75 21.89 21.86 35.03 3.95 4.73 4.57 37.36
*40 degrees API, 0.4 percent sulphur (1) Operating and capital costs have been escalated at 1.67 percent annually for 17 years and 1 percent thereafter. 39 ESTIMATED PRE-TAX NET CASH FLOWS ESTABLISHED RESERVES OF THE PROPERTIES ESCALATING COST AND PRICE CASE ($millions except for production)
NET NET REVENUE ALBERTA CASH FLOW COMPANY AFTER ROYALTY NET NET BEFORE ANNUAL INTEREST ROYALTY ROYALTY TAX OPERATING PRODUCTION ABANDONMENT CAPITAL INCOME PRODUCTION REVENUE(1) BURDENS(2) BURDENS CREDIT EXPENSES(3) REVENUE(4) COSTS INVESTMENT TAXES(5)(6) -------------------------------------------------------------------------------------------------------------------- (mboe) ($) ($) ($) ($) ($) ($) ($) ($) ($) 2001...... 7,293 301.0 75.3 225.6 0.1 28.1 197.6 0.7 19.0 177.9 2002...... 7,054 224.1 54.8 169.2 0.1 27.9 141.4 1.0 5.7 134.7 2003...... 6,032 162.6 37.9 124.7 0.1 25.5 99.3 0.9 2.5 95.9 2004...... 5,028 127.6 28.2 99.4 0 23.3 76.1 1.1 0.2 75.0 2005...... 4,169 104.5 21.8 82.7 0 21.1 61.6 0.8 1.6 59.3 2006...... 3,505 88.1 17.5 70.6 0 19.0 51.6 0.6 1.1 49.9 2007...... 2,969 75.2 14.3 60.9 0 17.5 43.4 0.7 0.1 42.5 2008...... 2,508 64.5 11.9 52.6 0 16.1 36.5 0.7 0.1 35.9 2009...... 2,138 55.6 9.9 45.7 0 14.7 31.0 0.7 0.1 30.3 2010...... 1,852 49.3 8.5 40.7 0 13.3 27.4 0.7 0.2 26.5 2011...... 1,617 43.7 7.5 36.3 0 12.2 24.1 0.7 0.2 23.3 2012...... 1,400 38.8 6.5 32.3 0 11.2 21.1 1.0 0.1 19.9 Remainder. 11,922 378.1 65.7 312.4 0.1 120.5 191.9 8.1 0.7 183.2 --------------------------------------------------------------------------------------------------------------------------------- TOTAL..... 57,494 1,713.0 359.8 1,353.2 0.4 350.4 1,003.1 17.6 31.6 953.9 =======================================================================================================================
Total net cash flow before income taxes discounted at: 10 percent: $593.0 million 15 percent: $512.7 million 20 percent: $455.9 million Notes: (1) Includes working-interest revenue and royalty-interest revenue. (2) Includes royalties net of processing allowances. (3) Includes other expenses, net-profits interest payments, capital and mineral taxes less third party processing and other income. (4) Company-interest revenue less Company interest royalty burdens and operating expenses. (5) Undiscounted. (6) Net cash flow before income taxes is stated prior to interest, general and administrative expenses and management fees. (7) Columns may not add due to rounding. 40 ESTIMATED PRE-TAX NET CASH FLOWS ESTABLISHED RESERVES OF THE PROPERTIES CONSTANT COST AND PRICE CASE ($millions except for production)
NET NET REVENUE ALBERTA CASH FLOW COMPANY AFTER ROYALTY NET NET BEFORE ANNUAL INTEREST ROYALTY ROYALTY TAX OPERATING PRODUCTION ABANDONMENT CAPITAL INCOME PRODUCTION REVENUE(1) BURDENS(2) BURDENS CREDIT EXPENSES(3) REVENUE(4) COSTS INVESTMENT TAXES(5)(6) -------------------------------------------------------------------------------------------------------------------- (mboe) ($) ($) ($) ($) ($) ($) ($) ($) ($) 2001....... 7,293 301.0 75.3 225.6 0 28.1 197.6 0.5 19.0 178.0 2002....... 7,056 292.3 73.6 218.6 0 28.2 190.4 0.9 5.6 184.0 2003....... 6,036 250.6 61.4 189.2 0 25.8 163.4 0.8 2.4 160.3 2004....... 5,029 209.0 48.9 160.1 0.1 23.3 136.9 1.0 0.2 135.8 2005....... 4,170 173.4 38.4 135.0 0.1 20.8 114.3 0.7 1.5 112.0 2006....... 3,515 146.4 30.9 115.5 0.1 18.7 96.9 0.7 1.0 95.1 2007....... 2,976 124.0 25.1 98.9 0 16.9 82.0 0.6 0.1 81.3 2008....... 2,525 105.2 20.6 84.6 0 15.3 69.3 0.5 0.1 68.7 2009....... 2,158 90.0 17.0 73.0 0 13.9 59.1 0.6 0.1 58.5 2010....... 1,869 78.1 14.4 63.7 0 12.5 51.2 0.6 0.2 50.4 2011....... 1,633 68.2 12.4 55.9 0 11.2 44.7 0.7 0.2 43.9 2012....... 1,419 59.3 10.5 48.7 0 10.2 38.5 0.8 0.1 37.7 Remainder.. 12,210 517.1 92.8 424.3 0.2 97.3 327.2 6.2 1.7 319.4 ---------------------------------------------------------------------------------------------------------------------- TOTAL...... 57,888 2,414.5 521.3 1,893.2 0.7 322.3 1,571.6 14.5 32.1 1,524.9 ======================================================================================================================
Total net cash flow before income taxes discounted at: 10 percent: $886.9 million 15 percent: $746.1 million 20 percent: $647.6 million Notes: (1) Includes working-interest revenue and royalty-interest revenue. (2) Includes royalties net of processing allowances. (3) Includes other expenses, net-profits interest payments, capital and mineral taxes, less third party processing and other income. (4) Company-interest revenue less Company interest royalty burdens and operating expenses. (5) Undiscounted. (6) Net cash flow before income taxes is stated prior to interest, general and administrative expenses and management fees. (7) Columns may not add due to rounding. 41 PRINCIPAL PROPERTIES The following is a description of the significant properties owned by Cypress Energy Inc. as of January 1, 2001. Remaining Established Reserves, ultimate recovery estimates and working interests contained in the following property descriptions are derived from the Gilbert Report. The term "net" used in the following property descriptions refers to the working interest of Cypress Energy Inc. and the Trust in the properties. CYPRESS PROPERTIES Cypress' exploration efforts are concentrated in Alberta and Saskatchewan in areas which are prospective for oil or readily marketable natural gas. The following is a description of the principal producing properties of Cypress. Any references in this section to reserves are based on Cypress' working interest therein before deduction of royalties, unless otherwise noted, as estimated in the report (the "GLJ Report") of Gilbert Laustsen Jung Associates Ltd. ("GLJ") dated January 1, 2001. Net acreage and production values refer to Cypress' working interest in the specific property or well, while gross values refer to a 100 percent working interest in those respective properties or wells. NORTHWEST ALBERTA The Northwest Alberta area is characterized by prolific, high deliverability oil and natural gas reservoirs located in multiple, shallow to medium depth horizons. The area produces oil and natural gas from the Gilwood formation, as well as natural gas from the Bluesky, Gething, Debolt, Shunda and Slave Point formations. Cypress' current focus in this area is on the exploration and development of reserves of natural gas in the shallow Cretaceous and Mississippian formations as well as oil and gas from the deeper Devonian formations. Cypress' production from this area for the year ended December 31, 2000 averaged 2,503 boe/d, 76 percent natural gas and 24 percent oil and liquids. Virtually all of Cypress' activities in the area are operated by Cypress. Reserves at January 1, 2001 consisted of 5,460 mmboe (net remaining established), 69 percent of the reserves were natural gas, 31 percent oil and liquids. Cypress operates a gas processing plant in the area that has 22 mmcf/d of capacity. For the year ended December 31, 2000, Cypress drilled 35 gross (31 net) wells in the area. 42 DAWSON The Dawson area is characterised by prolific, high deliverability natural gas reservoirs located in multiple shallow depth horizons. Cypress operates all of its activities in this area. Reserves at January 1, 2001 consisted of 4,256 mmboe (net remaining established reserves), 70 percent of the reserves were natural gas and 30 percent of the reserves were oil. Cypress operates two gas processing plants built or acquired since year end 1999 which have up to 17 mmcf/d of capacity. In 2000, Cypress drilled 27 gross (16 net) wells. THORSBY The Thorsby area is characterised by liquids and rich, sweet natural gas located in multiple, shallow to medium depth horizons. The area produces natural gas, oil and associated natural gas liquids primarily from the Glauconite and Basal Quartz zones with additional production from the Belly River and Banff zones. Cypress' production in this area for the year ended December 31, 2000 averaged 5,335 boed, 80 percent natural gas and 20 percent oil and liquids. Virtually all of Cypress' activities in the area are operated by Cypress and accounted for 32 percent of Cypress' average 2000 production, and 39 percent of Cypress' total reserves at January 1, 2001. Reserves at January 1, 2001 consisted of 22,235 mmboe (net remaining established reserves), 80 percent of which are natural gas. Cypress operates three of the five gas processing facilities in the area that have a capacity of over 50 mmcf/d. For the year ended December 31, 2000 Cypress drilled 32 gross (28.1 net) wells targeting 3 primary zones. In addition Cypress shot approximately 25 sections of 3D seismic, followed in early 2000 with a further two 3D seismic programs for a total of almost 40 sections of new 3D coverage. BRANT/FARROW The Brant/Farrow area is characterised by shallow to medium depth natural gas and oil reservoirs. The area produces oil and natural gas from the Mississippian, Basal Quartz, Glauconite, and Belly River formations. Cypress' production in this area for the year ended December 31, 2000 averaged 2,223 boed, 83 percent natural gas and 17 percent oil and liquids. All of Cypress' activities in the area are operated by Cypress and accounted for 13 percent of Cypress' average 2000 production and 7 percent of Cypress' total reserves at January 1, 2001. Reserves at January 1, 2001 consisted of 3,946 mmboe (net remaining established reserves); 93 43 percent of the reserves were natural gas, 7 percent oil and liquids, and 81 percent of the reserves were classified as proven. Cypress operates two gas processing plants in the area which have 15 mmcf/d of capacity For the year ended December 31, 2000 Cypress drilled 22 gross (12.4 net) wells in the area. In addition Cypress purchased a partner's interest in land, production and one of the gas plants to increase ownership to over 75 percent, as well as expanding the other gas plant and building an oil battery. SOUTHWEST SASKATCHEWAN Cypress' southwest Saskatchewan properties produce primarily oil from the Shaunavon and Roseray formations. Cypress production on these properties for the year ended December 31, 2000 averaged 1,029 boed, 93 percent oil and 7 percent natural gas. The properties are operated by Cypress and collectively accounted for 6 percent of Cypress' average 2000 production, and 4 percent of Cypress' total reserves at January 1, 2001. Reserves at year end 2000 consisted of 2,111 mmboe (net remaining established reserves) of which 70 percent of the reserves were oil. The majority of the assets in Southwest Saskatchewan were acquired pursuant to Cypress' acquisition of Canadian Conquest. In 2000 Cypress drilled 2 gross (2 net) wells in the area and purchased a gas plant which allowed new gas production to come on stream. UNPROVED LANDS - CYPRESS ENERGY INC. Cypress Energy Inc. has an interest in approximately 756,100 (539,800 net) acres of unproved lands at December 31, 2000. PrimeWest is currently reviewing available seismic and other data, and will develop an exploitation plan for these properties. Capital expenditures, farmouts and/or dispositions may result in future revenues from these undeveloped lands. The geographical area and value of the unproved lands is as follows: UNPROVED LANDS AREA ACRES ('000) ------------------------------ ------------------------------------ GROSS NET Alberta 732.7 532.6 Saskatchewan 9.0 5.8 British Columbia 2.4 0.9 Non-core Areas 12.0 0.5 ----------------- --------------- TOTAL 756.1 539.8 ================= =============== 44 The total estimated value of Cypress undeveloped land holdings at December 31, 2000 was approximately $50 million. INDUSTRY CONDITIONS The oil and natural gas industry is subject to extensive controls and regulations imposed by various levels of government. It is not expected that any of these controls or regulations will affect the operations of PrimeWest or the Trust in a manner materially different than they would affect other oil and gas companies and trusts of similar size. All current legislation is a matter of public record, and the Manager is unable to predict what additional legislation or amendments may be enacted. PRICING AND MARKETING - OIL In Canada, producers of oil negotiate sales contracts directly with oil purchasers. Oil prices are primarily based on worldwide supply and demand. The specific price paid depends in part on oil quality, prices of competing fuels, distance to market, the value of refined products and the supply/demand balance. Oil exports may be made pursuant to export contracts with terms not exceeding one year in the case of light crude, and not exceeding two years in the case of heavy crude, provided that an order approving any such export has been obtained from the National Energy Board ("NEB"). Any oil export to be made pursuant to a contract of longer duration (to a maximum of 25 years) requires an exporter to obtain an export licence from the NEB and the issue of such a licence requires the approval of the Governor in Council. PRICING AND MARKETING - NATURAL GAS In Canada, the price of natural gas sold intraprovincially, interprovincially or to the United States is determined by negotiation between buyers and sellers. Natural gas exported from Canada is subject to regulation by the NEB and the Government of Canada. Exporters are free to negotiate prices and other terms with purchasers, provided that the export contracts continue to meet certain criteria prescribed by the NEB and the government of Canada. Natural gas exports for a term of less than two years requires a general short term export license while terms greater than two years require a specific license for the particular gas sold (in quantities of not more than 30,000 cubic metres per day). Any natural gas export to be made pursuant to a contract of longer duration (to a maximum of 25 years) or a larger quantity requires an exporter to obtain an export licence from the NEB and the issue of such a licence requires the approval of the Governor in Council. The governments of Alberta, British Columbia and Saskatchewan also regulate the volume of natural gas which may be removed from those provinces for consumption elsewhere based on such factors as reserve availability, transportation arrangements and market considerations. 45 THE NORTH AMERICAN FREE TRADE AGREEMENT On January 1, 1994, the North American Free Trade Agreement ("NAFTA") among the governments of Canada, the U.S. and Mexico became effective. The NAFTA carries forward most of the material energy terms contained in the Canada-U.S. Free Trade Agreement. In the context of energy resources, Canada continues to remain free to determine whether exports to the U.S. or Mexico will be allowed provided that any export restrictions do not: (i) reduce the proportion of energy resource exported relative to domestic use (based upon the proportion prevailing in the most recent 36-month period), (ii) impose an export price higher than the domestic price; and (iii) disrupt normal channels of supply. All three countries are prohibited from imposing minimum export- or import-price requirements. The NAFTA contemplates the reduction of Mexican restrictive trade practices in the energy sector and prohibits discriminatory border restrictions and export taxes. The agreement also contemplates clearer disciplines on regulators to ensure fair implementation of any regulatory changes, and to minimize disruption of contractual arrangements, which is important for Canadian natural gas exports. ROYALTIES AND INCENTIVES In addition to federal regulation, each province has legislation and regulations which govern land tenure, royalties, production rates, environmental protection and other matters. In all Canadian jurisdictions, producers of oil and natural gas are required to pay annual rental payments in respect of Crown leases and royalties and freehold production taxes in respect of oil and natural gas produced from Crown and freehold lands, respectively. The royalty regime is a significant factor in the profitability of oil and natural gas production. Royalties payable on production from lands other than Crown lands are determined by negotiations between the mineral owner and the lessee. Crown royalties are determined by governmental regulation and are generally calculated as a percentage of the value of the gross production, and the rate of royalties payable generally depends in part on prescribed reference prices, well productivity, geographical location, field discovery date and the type or quality of the petroleum product produced. From time to time the governments of Canada, Alberta, British Columbia and Saskatchewan have established incentive programs which have included royalty-rate reductions, royalty holidays and tax credits for the purpose of encouraging oil and natural gas exploration or enhanced planning projects. These programs reduce the amount of Crown royalties otherwise payable. ENVIRONMENTAL REGULATION The oil and natural gas industry is subject to environmental regulation pursuant to local, provincial and federal legislation. Environmental legislation provides for 46 restrictions and prohibitions on releases or emissions of various substances produced in association with certain oil and natural gas industry operations, and can affect the location of wells and facilities and the extent to which exploration and development is permitted. In addition, legislation requires that well and facilities sites be abandoned and reclaimed to the satisfaction of provincial authorities. A breach of that legislation may result in the imposition of fines or issuance of clean-up orders. PrimeWest as the primary operating entity for all of the PW Holding Entities and the Trust is committed to meeting its responsibilities to protect the environment wherever it operates, and anticipates making increased expenditures of both a capital and expense nature as a result of the increasingly stringent laws relating to the protection of the environment. PrimeWest's internal procedures are designed to ensure that the environmental aspects of new developments are taken into account prior to proceeding. The Manager believes that PrimeWest is in material compliance with applicable environmental laws and regulations properties. RISK FACTORS VOLATILITY OF OIL AND NATURAL GAS PRICES The results of operations and financial condition of each of the PW Holding Entities, and therefore the amounts paid to the Trust, will be dependent on the prices received oil and natural gas production. Crude oil and natural gas prices have fluctuated widely during recent years and are determined by supply and demand factors, including weather and general economic conditions, as well as conditions in other oil producing regions, which are beyond the control of PrimeWest or the Trust. Any decline in crude oil or natural gas prices could have a material adverse effect on the operations, financial condition, proved reserves and the level of expenditures for the development of the oil and natural gas reserves of the PW Holding Entities. The Manager may manage the risk associated with changes in commodity prices and foreign exchange rates by causing one or more of the PW Holding Entities to, from time to time, enter into crude oil, natural gas and foreign currency risk management contracts and forward foreign-exchange contracts. RESERVES REPLACEMENT (SUSTAINABILITY) The Trust has certain unique attributes which differentiate it from other oil and natural gas industry participants. Distributions of Distributable Income in respect of properties, absent commodity price increases or cost-effective acquisition and development activities, will decline over time in a manner consistent with declining production from typical oil, natural gas and natural gas liquids reserves. The PW Holding Entities will not be reinvesting cash flow in the same manner as other oil and natural gas exploration and production company industry participants. Their future oil and natural gas reserves and production, and therefore their cash flows, will be highly dependent on the Manager's success in exploiting existing reserve bases and acquiring 47 additional reserves. Without reserve additions through acquisition and/or development activities, the reserves and production of the PW Holding Entities and the Trust will decline over time as reserves are produced. Trust Units will have no value when reserves from the properties or additional properties can no longer be economically marketed and, as a result, subscribers for Trust Units will have to obtain the return of capital invested out of cash flow derived from their investment in Trust Units during the period when reserves can be economically recovered. To the extent that external sources of capital, including the issuance of additional Trust Units, become limited or unavailable, the ability of the PW Holding Entities and the Trust to make the necessary capital investments to maintain or expand their oil and natural gas reserves will be impaired. To the extent that the PW Holding Entities are required to use cash flow to finance capital expenditures or property acquisitions, the level of Distributable Income will be reduced. There is strong competition relating to all aspects of the oil and natural gas industry. The Manager actively competes for reserve acquisitions and skilled industry personnel with a substantial number of other oil and natural gas companies, many of which have significantly greater financial resources than the Manager. There can be no assurance that the PW Holding Entities will be successful in developing additional reserves or acquiring additional reserves on terms that meet the acquisition guidelines. CHANGES IN LEGISLATION There can be no assurance that income tax laws or government incentive programs relating to the oil and natural gas industry, such as the status of mutual fund trusts and the resource allowance, will not be changed in a manner which adversely affects Unitholders. INVESTMENT ELIGIBILITY If the Trust ceases to qualify as a mutual fund trust, the Trust Units will cease to be qualified investments for RRSPs, RRIFs and DPSPs and RESPs that acquired the Trust Units after October 27, 1998 ("Exempt Plans"). Where at the end of any month an Exempt Plan holds Trust Units that are not qualified investments, the Exempt Plan must, in respect of that month, pay a tax under Part XI.1 of the Tax Act equal to 1 percent of the fair market value of the Trust Units at the time those Trust Units were acquired by the Exempt Plan. In addition, where a trust governed by an RRSP holds Trust Units that are not qualified investments, the trust will become taxable on its income attributable to the Trust Units while they are not qualified investments. 48 OPERATIONAL MATTERS The operation of oil and natural gas wells involves a number of operating and natural hazards which may result in blowouts, environmental damage and other unexpected or dangerous conditions, resulting in damage to the property of the PW Holding Entities and possible liability to third parties. PrimeWest, on behalf of itself, the other PW Holding Entities and the Trust, maintains liability insurance, where available, in amounts consistent with industry standards. Business interruption insurance may also be purchased for selected facilities, to the extent that kind of insurance is available. The PW Holding Entities may become liable for damages arising from those events against which it cannot insure or against which it may elect not to insure because of high premium costs or other reasons. In particular, insurance against environmental risks is not generally available to PrimeWest or to other companies in the oil and natural gas industry. Costs incurred to repair that damage or pay those liabilities will reduce amounts paid to the Trust. Continuing production from a property, and to some extent the marketing of production therefrom, are largely dependent upon the capability of the operator of the property. To the extent the operator fails to perform these functions properly, revenue may be reduced. Payments from production generally flow through the operator, and there is a risk of delay and additional expense in receiving those revenues if the operator becomes insolvent. Although satisfactory title reviews of the properties will be conducted in accordance with industry standards, those title reviews do not guarantee or certify that a defect in the chain of title may not arise to defeat the claim of the PW Holding Entities to a property. A reduction of amounts paid to the Trust could result in those circumstances. ENVIRONMENTAL CONCERNS The oil and natural gas industry is subject to environmental regulation pursuant to municipal, provincial and federal legislation. A breach of that legislation may result in the imposition of fines or the issuance of clean up orders. That legislation may be changed to impose higher standards and potentially more costly obligations on PrimeWest. See "Industry Conditions - Environmental Regulation". Although PrimeWest has established a reclamation fund for the purpose of funding its currently estimated future environmental and reclamation obligations of the PW Holding Entities and the Trust based on its current knowledge, there can be no assurance that PrimeWest will be able to satisfy their actual future environmental and reclamation obligations. Ongoing environmental obligations will be funded out of cash flow and will therefore reduce Distributable Income payable to Unitholders. Should PrimeWest be unable to fully fund the cost of remedying an environmental problem, PrimeWest might be required to suspend operations or enter into interim compliance measures pending completion of the required remedy. 49 DEBT SERVICE Amounts paid in respect of interest and principal, and other costs, expenses and disbursements ("Debt Service Charges") relating to debt incurred in respect of the properties will reduce amounts paid to the Trust. Variations in interest rates and other credit charges and scheduled principal repayments could result in significant changes in the amount required to be applied to Debt Service Charges before payment of amounts paid to the Trust and Distributable Income. Certain covenants of the agreements with the bank providing the Credit Facility may also limit distributions to and by the Trust. Although the Manager and PrimeWest believe the Credit Facility will be sufficient for all immediate requirements, there can be no assurance that the amount will be adequate for the future financial obligations of the PW Holding Entities and the Trust or that additional funds will be able to be obtained. The bank providing the Credit Facility will be provided with security over substantially all of the assets of each of the PW Holding Entities and the Trust. If any of the PW Holding Entities become unable to pay its Debt Service Charges in respect of the Credit Facility, or otherwise commits an event of default such as bankruptcy, that bank may foreclose on or sell the properties free from the rights of the Trust to the revenue therefrom. DELAY IN CASH DISTRIBUTIONS In addition to the usual delays in payment by purchasers of Petroleum Substances produced from the properties to the operator of the properties, from the operator to the PW Holding Entities (where PrimeWest is not the operator), from the PW Holding Entities to the Trust and from the Trust to Unitholders, payments between any of those parties may also be affected or delayed by restrictions imposed by lenders, accounting delays, delays in the sale or delivery of products, delays in the connection of wells to a gathering system, blowouts or other accidents, adjustments for prior periods, recovery by the operator of expenses incurred in the operation of properties, or the establishment by the operator of reserves for those expenses. RELIANCE ON THE MANAGER Unitholders will be dependent on the management of the Manager in respect of the administration and management of all matters relating to the properties, the PW Holding Entities, the Trust and Trust Units. Investors who are not willing to rely on the management of the Manager should not invest in the Trust Units. POTENTIAL CONFLICTS OF INTEREST There may be circumstances in which the interests of the Manager will conflict with those of Unitholders. 50 The Manager will use all reasonable efforts to resolve such conflicts of interest in a manner that will treat the Trust and the PW Holding Entities, as the case may be, and the other interested party fairly, taking into account all of the circumstances of the Trust and the PW Holding Entities, as the case may be, and such interested party, and to act honestly and in good faith in resolving those matters. Circumstances may arise where members of the board of directors of PrimeWest are directors or officers of corporations which are in competition to the interests of the PW Holding Entities and the Trust. No assurances can be given that opportunities identified by those board members will be provided to the PW Holding Entities and the Trust. NATURE OF TRUST UNITS The Trust Units do not represent a traditional investment in the oil and natural gas sector and should not be viewed by investors as shares in any of the PW Holding Entities. The Trust Units represent a fractional interest in the Trust. As holders of Trust Units, Unitholders will not have the statutory rights normally associated with ownership of shares of a corporation including, for example, the right to bring oppression or derivative actions. The Trust's sole assets will be permitted short-term investments, direct and indirect interests in petroleum and natural gas properties and related contractual rights and shares in the PW Holding Entities. The market price of the Trust Units will be a function of anticipated Distributable Income, the value of the properties owned by the PW Holding Entities and the Trust, and the Manager's ability to effect long-term growth in the value of the Trust. The market price of the Trust Units will be sensitive to a variety of market conditions including, but not limited to, interest rates and the ability of the Trust to acquire suitable oil and natural gas properties. Changes in market conditions may adversely affect the trading price of the Trust Units. UNITHOLDER LIMITED LIABILITY The Declaration of Trust provides that no Unitholder will be subject to any liability in connection with the Trust or its obligations and affairs and, in the event that a court determines Unitholders are subject to any of those liabilities, those liabilities will be enforceable only against, and will be satisfied only out of the Trust's assets. Pursuant to the Declaration of Trust, the Trust will indemnify and hold harmless each Unitholder from any costs, damages, liabilities, expenses, charges and losses suffered by a Unitholder resulting from or arising out of that Unitholder not having that limited liability. The Declaration of Trust provides that all written instruments signed by or on behalf of the Trust must contain a provision to the effect that the obligations in those instruments will not be binding on Unitholders personally. Where however the Trust holds direct interests in oil and gas properties, such as in the case of third party gross overriding royalties, the terms of contracts assigned to the Trust may not contain such 51 provisions. In such cases the assignments to the Trust of such interests specifically reserve out the assumption by the Trust of any liability to the Unitholders personally. Personal liability may also arise in respect of claims against the Trust that do not arise under contracts, including claims in tort, claims for taxes, and possibly certain other statutory liabilities. The possibility of any personal liability of this nature arising is considered unlikely. The operations of the Trust will be conducted, on the advice of counsel, in such a way and in such jurisdictions as to avoid as far as possible any material risk of liability on the Unitholders for claims against the Trust. ITEM 4: SELECTED CONSOLIDATED FINANCIAL INFORMATION Reference is made to the consolidated financial statements of the Trust contained in the Annual Report, which financial statements are hereby incorporated into this Annual Information Form by reference. SELECTED ANNUAL INFORMATION
FOR THE PERIOD FROM AUGUST 2, 1996 TO ($000's except per Unit) FOR THE YEAR ENDED DECEMBER 31 DECEMBER 31, 1996 2000 1999 1998 1997 ------------------------------------------------------------------------ EARNINGS INFORMATION Total Revenue, net of royalties..................... 156,561 83,063 66,057 59,593 18,043 Expenses, including D, D & A and taxes.............. 100,949 77,078 79,604 56,423 16,030 Net Income (Loss) .................................. 55,612 5,985 (13,547) 3,170 2,013 Net Income (Loss) per Trust Unit ($) Basic........................................... 1.25 0.18 (0.43) 0.13 0.08 Fully Diluted................................... 1.21 0.18 (0.43) 0.13 0.08 DISTRIBUTABLE INCOME INFORMATION Cash Available for Distribution..................... 79,832 37,728 26,030 33,746 11,067 Cash Available for Distribution to Trust Unitholders ........................................ 79,033 37,351 25,769 33,409 10,956 Cash Available for Distribution per Trust Unit ($) 1.77 1.10 0.82 1.34 0.44 BALANCE SHEET INFORMATION Total Assets ....................................... 434,238 320,210 316,140 285,765 254,480 Long Term Debt, including current portion .......... 79,047 92,286 73,112 66,829 14,228 Average Trust Units Outstanding..................... 44,652 33,965 31,426 24,931 24,900 SELECTED QUARTERLY INFORMATION FOR THE QUARTERS ENDED - 2000 ------------------------------------------------------------------- MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31 ---------------- -------------- --------------- -------------- Total Revenue, net of royalties .............. 27,829 34,641 41,091 53,000 Expenses including D, D & A................... 19,748 24,609 26,431 30,161 Net Income ................................... 8,081 10,032 14,660 22,839 Net Income per Unit Basic................................. 0.23 0.26 0.31 0.45 Fully diluted......................... 0.23 0.25 0.30 0.43
52
------------------------------------------------------------------- ($000's except per Trust Unit) FOR THE QUARTERS ENDED - 1999 ------------------------------------------------------------------- MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31 ---------------- -------------- --------------- -------------- Total Revenue, net of royalties .............. 17,675 19,304 22,180 23,904 Expenses including D, D & A .................. 19,732 18,473 18,994 19,879 Net Income (Loss) ............................ (2,057) 831 3,186 4,025 Net Income (Loss) per Trust Unit Basic.................................. (0.06) 0.03 0.10 0.11 Fully diluted.......................... (0.06) 0.03 0.10 0.11
In addition, applicable securities laws require the Trust to provide certain historical financial statements of Cypress Energy Inc. and Reserve Royalty Corporation in connection with any offering of Trust Units. Those financial statements are attached to this Annual Information Form as Schedules A and B. ITEM 5: MANAGEMENT'S DISCUSSION AND ANALYSIS Reference is made to the information under the heading "Management's Discussion and Analysis" in the Annual Report, which information is hereby incorporated into this Annual Information Form by reference. ITEM 6: MARKET FOR SECURITIES The outstanding Trust Units of PrimeWest Energy Trust are listed for trading on The Toronto Stock Exchange under the symbol PWI.UN. ITEM 7: DIRECTORS AND OFFICERS The Trust has no directors or officers. The following information pertains to the board of directors of PrimeWest and the officers of PrimeWest and the Manager. DIRECTORS The Trust has the right to nominate and cause the Manager to elect a majority of the board of directors of PrimeWest. The names of the nominees for election as directors, their municipalities of residence, principal occupations, year in which each became a director of PrimeWest and numbers of Trust Units beneficially owned or over which control or direction is exercised by such persons, as at April 5, 2001, are as follows:
TRUST UNITS BENEFICIALLY OWNED OR DIRECTOR OF OVER WHICH CONTROL OR DISCRETION IS NAME AND PRESENT PRINCIPAL PRIMEWEST MUNICIPALITY OF EXERCISED AS OCCUPATION OR EMPLOYMENT SINCE RESIDENCE AT APRIL 5, 2001 --------------------------- ----------- --------------- ------------------------------------ HAROLD P. MILAVSKY 1996 Calgary, Alberta 41,435 Chairman Quantico Capital Corp.
53
TRUST UNITS BENEFICIALLY OWNED OR DIRECTOR OF OVER WHICH CONTROL OR DISCRETION IS NAME AND PRESENT PRINCIPAL PRIMEWEST MUNICIPALITY OF EXERCISED AS OCCUPATION OR EMPLOYMENT SINCE RESIDENCE AT APRIL 5, 2001 --------------------------- ----------- --------------- ------------------------------------ BARRY E. EMES 1996 Calgary, Alberta 9,000 Partner Stikeman Elliott HAROLD N. KVISLE 1996 Calgary, Alberta 10,000 President TransCanada Pipelines Limited MICHAEL W. O'BRIEN 2000 Calgary, Alberta 5,000 Executive Vice President, Corporate Development and Chief Financial Officer Suncor Energy Inc. KENT J. MACINTYRE 1996 Calgary, Alberta 207,309 Chief Executive Officer PrimeWest Energy Inc.
Each of the foregoing persons has been engaged in the occupation set forth above or similar occupations with the same employer for the last five years, other than Mr. Kvisle who prior to May, 2001 was Senior Vice President, Energy Operations of TransCanada Pipelines Limited (October 1999 to May 2001) and prior to October, 1999 was President of Fletcher Challenge Energy Canada Inc. Prior to December, 1999, Mr. O'Brien was Executive Vice-President of Sunoco Inc., a wholly-owned subsidiary of Suncor Energy Inc. Prior to July, 1996 Mr. MacIntyre's principal occupation was Chief Executive Officer of Triad Energy Inc. (March, 1994 - July, 1996). PrimeWest does not have an executive committee, but is required to, and does have, an audit committee. The audit committee consists of those directors of PrimeWest who are nominees of the Trust. Barry E. Emes, Harold N. Kvisle, Michael W. O'Brien and Harold P. Milavsky, who are Independent Directors, are members of the Audit and Reserves Committee. The Independent Directors also act as the Corporate Governance and Compensation Committees of PrimeWest. The Trust Company of Bank of Montreal is currently the Trustee of the Trust. 54 OFFICERS Each person who is an officer of the Manager also holds the same office with each of the PW Holding Entities. The name, municipality of residence, position held and principal occupation of each officer of each of the PW Holding Entities and the Manager on the date hereof are set out below:
NAME AND MUNICIPALITY POSITION WITH THE MANAGER PRINCIPAL OCCUPATION --------------------- ------------------------- -------------------- Kent J. MacIntyre Director, Vice-Chairman and Chief Vice-Chairman and Chief Executive Calgary, Alberta Executive Officer Officer of the Manager and PrimeWest Since October 1996 Timothy S. Granger Vice-President, Vice-President, Production of the Calgary, Alberta Production Manager and PrimeWest Since June 1999 Susan M. Duncan Vice-President, Vice-President, Finance of the Calgary, Alberta Finance Manager and PrimeWest Since October 1996 Ronald J. Ambrozy Vice-President, Business Development Vice-President, Business Development Calgary, Alberta Since September 1997 of the Manager and PrimeWest Ann C. Laniel Land Manager Land Manager of the Manager and Calgary, Alberta Since October 1996 PrimeWest James T. Bruvall Secretary Partner, Stikeman Elliott Calgary, Alberta Since October 1996
None of the above officers have been employed in their current positions for more than five years. Prior to October, 1996 Mr. MacIntyre was Chief Executive Officer of Triad Energy Inc. (March, 1994 - October, 1996). For the five years prior to June, 1999, Mr. Granger held various managerial positions at Pogo Canada Ltd., Petro-Canada and prior to that at Amerada-Hess. Prior to October, 1996 Ms. Duncan was Treasurer of Triad Energy Inc. (June, 1995 - October, 1996). Prior to September, 1997, Mr. Ambrozy held several positions of progressive responsibility at Gulf Canada Resources Limited over the previous 22 years. Prior to October, 1996 Ms. Laniel was Landman of Triad Energy Inc. (March, 1994 - October, 1996). Mr. Bruvall is currently a partner at Stikeman Elliott, barristers and solicitors (February, 1996 - present). 55 MANAGEMENT OF THE MANAGER KENT J. MACINTYRE, DIRECTOR, VICE-CHAIRMAN AND CHIEF EXECUTIVE OFFICER Mr. MacIntyre has overall responsibility for leading and overseeing the business direction of the Manager. He has over 20 years of experience in the oil and natural gas industry, the last ten years as principal in the start-up and management of several energy ventures including Olympia Energy Ventures Ltd. (1989-1993) and Triad Energy Inc. (1994-1996). Through these ventures, Mr. MacIntyre has been directly involved in and responsible for the acquisition of various petroleum and natural gas properties and the enhancement of the value of those properties through selective operating, marketing, development and exploration strategies. In each of those acquisitions Mr. MacIntyre's companies became the operator of the acquired properties and developed a record of acquiring properties at costs substantially below industry averages. Prior to 1994, Mr. MacIntyre held executive or engineering operating positions with Sabre Energy Ltd., Vikor Resources Ltd., and Hudson's Bay Oil and Gas Company Ltd. Mr. MacIntyre has a B.Sc. (Eng.) from the University of Manitoba and an MBA from the University of Calgary. TIMOTHY S. GRANGER, VICE PRESIDENT, PRODUCTION Mr. Granger joined the Manager in June 1999 and is responsible for field operations and the capital development program. Mr. Granger has more than 20 years of extensive experience in exploitation, production operations and asset management. From 1996 to 1999, Mr. Granger held various managerial positions at Pogo Canada Ltd., Petro-Canada including production engineering and upstream and corporate information technology. Prior to 1996, Mr. Granger held various management positions at Amerada Hess. From 1980 to 1991, Mr. Granger held various engineering positions at Dynex Petroleum, Canterra Energy and Dome Petroleum. Mr. Granger holds a P.Eng. (Mechanical) from Carlton University. SUSAN M. DUNCAN, VICE-PRESIDENT, FINANCE Ms. Duncan is responsible for the general financial operations of the Manager and for providing advice to the Manager on tax and accounting matters. Ms. Duncan has over 16 years of experience in finance, accounting, audit and income tax in the oil and natural gas industry and in public accounting. She was Treasurer of Triad Energy Inc. from June, 1995 to October, 1996. Prior to 1995, Ms. Duncan was a Principal at Coopers & Lybrand in Calgary. Ms. Duncan has a B.Comm. from the University of Lethbridge and received her C.A. designation in 1988. 56 RONALD J. AMBROZY, VICE-PRESIDENT, BUSINESS DEVELOPMENT Mr. Ambrozy has over 24 years of experience in the petroleum and natural gas industry. Prior to joining the Manager in 1997, Mr. Ambrozy held progressively more senior positions at Gulf Canada Resources Limited, as well as manager of Gulf's asset management group. Mr. Ambrozy has a Bachelor of Science in Engineering from the University of Manitoba. ANN C. LANIEL, LAND MANAGER Ms. Laniel is responsible for all of the Manager's land functions. Ms. Laniel has over 14 years of experience in the oil and natural gas industry, the last ten years of which were directly related to land negotiation, land contracts and mineral and surface administration with Triad Energy Inc. and Olympia Energy Ventures Ltd. EMPLOYEES As of December 31, 2000, the Trust had no employees. The activities of the PW Holding Entities and the Trust are carried out by the Manager pursuant to the terms of the Management Agreement. The Manager had 99 employees (including field staff) as of December 31, 2000, all of which devoted substantially all of their working time to the business of the Trust and the PW Holding Entities. ITEM 8: ADDITIONAL INFORMATION Additional information, including directors' and officers' remuneration and indebtedness, principal holders of the Trust's securities, interests of insiders in material transactions and the compensation of the Manager, where applicable, is contained in the Circular. Additional financial information is provided in the Trust's consolidated comparative financial statements for the year ended December 31, 2000, contained in the Annual Report. Upon request to the Secretary of PrimeWest, the Trust will provide one copy of this Annual Information Form, together with one copy of any document incorporated herein by reference, one copy of the Annual Report (including the consolidated comparative financial statements of the Trust for the year ended December 31, 2000 and accompanying report of the auditors), one copy of any interim financial statements subsequent to the consolidated financial statements for the year ended December 31, 2000 and a copy of the Circular dated April 10, 2001. When securities of the Trust are in the course of a distribution pursuant to a short-form prospectus, or a preliminary short form prospectus has been filed in respect of a distribution of the Trust's securities, copies of the foregoing documents and any other documents that are incorporated by reference into the short form prospectus or 57 preliminary short-form prospectus may also be obtained from the Secretary of PrimeWest. GLOSSARY OF ABBREVIATIONS & TERMS ABBREVIATIONS In this Annual Information Form measurements are given in standard Imperial or metric units only. The following table sets forth certain standard conversions: BBLS Barrels MCF/D 1,000 cubic feet per day MBBLS 1,000 barrels BCF 1,000,000,000 cubic feet MMBBLS 1,000,000 barrels M3 1000 cubic metres BBLS/D Barrels per day BOE barrels of oil equivalent MCF 1,000 cubic feet MBOE 1,000 barrels of oil equivalent MMCF 1,000,000 cubic feet BOE/D barrels of oil equivalent per day MLT 1,000 long tons MMBOE millions of barrels of oil equivalent
For purposes of this document, 6 mcf of natural gas and 1 bbl of NGLs each equal 1 bbl of oil. This conversion rate is not based on price or energy content. DEFINITIONS In this Annual Information Form, the capitalized terms set forth below have the following meanings: AMOCO means, collectively, Amoco Canada Petroleum Company Ltd. and its affiliates. ANNUAL REPORT means the 2000 Annual Report of PrimeWest Energy Trust filed on SEDAR at www.sedar.com. CASH DISTRIBUTION DATE means the date Distributable Income is paid to Unitholders, currently being the 15th day following any Record Date. CIRCULAR means the Management Proxy Circular of PrimeWest Energy Trust, dated April 10, 2001. DECLARATION OF TRUST means declaration of trust dated August 2, 1996 among the Trustee, PrimeWest and the Initial Unitholder (as therein defined), as amended from time to time. DISTRIBUTABLE INCOME means 99 percent of the Royalty Income together with any income earned by the Trust from permitted short term investments plus any ARTC, less Crown royalties and other Crown charges that are not deductible by PrimeWest for 58 income tax purposes and that are reimbursed by the Trust to PrimeWest less general and administrative expenses of the Trust. ESTABLISHED RESERVES, PROVED RESERVES and PROBABLE RESERVES have the meanings given to those terms in this Annual Information Form under the heading "Oil and Natural Gas Reserves". GENERAL AND ADMINISTRATIVE COSTS means the amount in aggregate representing all expenditures and costs incurred under the Management Agreement in respect of PrimeWest, the Trust or the Royalty or in the management and administration of PrimeWest, the Trust or the Royalty, other than Management Fees. MANAGEMENT AGREEMENT means the agreement dated October 16, 1996 among the Manager, PrimeWest and the Trustee for and on behalf of the Trust, as amended from time to time, pursuant to which the Manager provides management services to PrimeWest and the Trust. MANAGEMENT FEES means the fees payable to the Manager pursuant to the Management Agreement. MANAGER means PrimeWest Management Inc. NET PRODUCTION REVENUE in respect of any period for which Net Production Revenue is calculated means the aggregate of: (a) the amount received or receivable by PrimeWest in respect of the sale of its interest in all Petroleum Substances produced from the properties; (b) Crown royalties and other Crown charges which are not deductible for income tax purposes to the extent those royalties are not included in the amounts described in paragraph (a); (c) PrimeWest's share of all other revenues which accrue in respect of the properties including, without limitation, (i) fees and similar payments made by third parties for the processing, transportation, gathering or treatment of their Petroleum Substances in facilities that are part of the properties, (ii) proceeds from the sale or licensing of seismic and similar data, (iii) incentives, rebates and credits in respect of production costs or in respect of capital expenditures, (iv) overhead and other cost recoveries, (v) royalties and similar income; and 59 (d) ARTC applicable to the properties; less (e) the amount of non-capital operating costs paid or payable by or on behalf of PrimeWest in respect of operating the properties including, without limitation, the costs of gathering, compressing, processing, transporting and marketing all Petroleum Substances produced therefrom and all other amounts paid to third parties which are calculated with reference to production from the properties including, without limitation, gross overriding royalties and lessors' royalties, but excluding Crown royalties and other Crown charges and any site reclamation and abandonment costs. O&G CORP. means PrimeWest Oil and Gas Corp. a majority owned subsidiary of the Trust. All of the shares of O&G Corp. not owned by the Trust are owned by PrimeWest. PERSON means an individual, a body corporate, a partnership (limited or general), a joint venture, a trust, a pension fund, a union, a government and a governmental agency. PETROLEUM SUBSTANCES means petroleum, natural gas and related hydrocarbons (except coal) including, without limitation, all liquid hydrocarbons, and all other substances, including sulphur, whether gaseous, liquid or solid and whether hydrocarbon or not, produced in association with those petroleum, natural gas or related hydrocarbons. PRIMEWEST means PrimeWest Energy Inc., a wholly-owned subsidiary of PrimeWest Management Inc. PW HOLDING ENTITIES means collectively, PrimeWest, Resources, Royalty Corp. and O&G Corp. RECORD DATE means the last day in each month. RESERVE LIFE INDEX means the amount obtained by dividing the quantity of reserves by the production of Petroleum Substances from those reserves for the year ending December 31, 2000. RESOURCES means PrimeWest Resources Ltd., a wholly-owned subsidiary of the Trust. ROYALTY means the royalty payable by PrimeWest to the Trust pursuant to the Royalty Agreement, which royalty equals 99 percent of Royalty Income. ROYALTY AGREEMENT means the agreement dated October 16, 1996 between PrimeWest and the Trustee as trustee for and on behalf of the Trust, as amended from time to time, regarding the creation and sale of the Royalty. 60 ROYALTY CORP. means PrimeWest Royalty Corp., a wholly-owned subsidiary of the Trust. ROYALTY INCOME in respect of any period for which Royalty Income is calculated means Net Production Revenue less the aggregate of: (a) the Debt Service Charges, Management Fees, General and Administrative Costs and taxes (other than Crown royalties but including any capital taxes) payable by PrimeWest or the Trust; (b) capital expenditures intended to improve or maintain production from the properties or to acquire additional properties, in excess of amounts borrowed or designated as a deferred purchase price obligation pursuant to the Royalty Agreement, provided that the amount of capital expenditures that can be deducted will not be in excess of 10 percent of the annual net cash flow from the properties in the year before the year in which the determination is made; (c) net contributions to PrimeWest's reclamation fund; and (d) ARTC applicable to the properties. Any income derived from properties which are not working, royalty or other interests in Canadian resource properties or which do not relate to production from working, royalty or other interests in Canadian resource properties, will not be included as Royalty Income and will be used to defray other expenses, capital expenditures of PrimeWest and Debt Service Charges. TRUST means PrimeWest Energy Trust. TRUST UNITS means the units of the Trust, each unit representing an equal undivided beneficial interest in the Trust. TRUSTEE means The Trust Company of Bank of Montreal, or its successor as trustee of the Trust. UNITHOLDERS means the holders from time to time of one or more Trust Units. 61 SCHEDULE A US GAAP RECONCILIATION 1. RECONCILIATION TO ACCOUNTING PRINCIPLES GENERALLY ACCEPTED IN THE UNITED STATES 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.). The following are those policies that result in significant differences. PROPERTY, PLANT AND EQUIPMENT PrimeWest follows the full cost accounting guideline as established by the Canadian Institute of Chartered Accountants. Under this guideline, the net carrying value of the company's oil and gas properties is limited to an estimated recoverable amount calculated as aggregate undiscounted future net revenues, after deducting future general and administrative costs, financing costs, and income taxes. In accordance with the full cost method of accounting as set out by the U.S. Securities and Exchange Commission, the net carrying value is limited to a standardized measure of discounted future cash flows, before financing and general administrative costs. Where the amount of a ceiling test write down under Canadian GAAP differs from the amount of a write down under U.S. GAAP, the charge for depreciation and depletion under U.S. and Canadian GAAP will differ in subsequent years. INCOME TAXES Effective January 1, 2000, the company adopted, retroactively without restating prior years, the liability method of accounting for income taxes as recommended by the Canadian Institute of Chartered Accountants. In prior years, the company computed deferred income taxes using the deferral method. The new Canadian accounting standard is similar to the United States Statement of Financial Accounting Standards No. 109 (FAS 109), "Accounting for Income Taxes", which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been recognized in the company's financial statements or tax returns. In estimating future tax consequences, both the new Canadian standard and FAS 109 generally consider all expected events, including enacted changes in laws or rates. RECENTLY ISSUED ACCOUNTING STANDARDS DERIVATIVE FINANCIAL INSTRUMENTS Effective January 1, 2001, the company will adopt United States Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities ("FAS 133"), as amended by FAS 138, which establishes accounting and reporting standards for derivative instruments, including certain derivative instruments A-1 embedded in other contracts and for hedging activities. All derivatives, whether designated in hedging relationships or not, and excluding normal purchase and sales are required to be recorded on the balance sheet at fair value. If the derivative is designated as a fair value hedge, the changes in the fair value of the derivative and of the hedged item attributable to the hedged risk are recognized in earnings. If the derivative is designated as a cash flow hedge, the effective portions of the changes in fair value of the derivative are recorded in other comprehensive income (OCI) and are recognized in the income statement when the hedged item is realized. Ineffective portions of changes in the fair value and the cash flow hedges are recognized in earnings, immediately. The adoption of FAS 133 is expected to result in a charge to Other Comprehensive Income of $970,000. Liabilities are expected to increase by $970,000 as a result of recording derivative instruments on the consolidated balance sheet at fair value. The decrease in U.S. GAAP comprehensive earnings is attributable to the mark to market derivative losses at the balance sheet date. Implementation of this accounting standard will not affect the company's cash flow or liquidity. The following tables set out the significant differences in the consolidated financial statements using U.S. GAAP. Certain comparative figures have been reclassified to conform with the 2000 presentation. (a) CONSOLIDATED NET INCOME 2000 1999 $000'S $000'S Net income as reported 55,612 5,985 Adjustments Depletion and depreciation 6,523 6,217 Future income tax expense (780) (740) ----------------------- Adjusted net and comprehensive income 61,355 ======================= Net income per trust unit Canadian GAAP 1.25 0.18 U.S. GAAP 1.37 0.34 A-2 (b) CONSOLIDATED BALANCE SHEETS
2000 1999 ----------------------------- ---------------------------- CDN GAAP U.S. GAAP CDN GAAP U.S. GAAP $ $ $ $ Capital assets - net 395,376 336,529 289,209 223,839 Future income taxes (16,596) (11,255) - (4,099) Accumulated income (loss) 43,014 (10,492) (2,379) (71,848)
(c) CONSOLIDATED CASH FLOWS The consolidated statements of cash flows prepared in accordance with Canadian GAAP conform in all material respects with U.S. GAAP except that Canadian GAAP allows for the presentation of operating cash flow before changes in non-cash working capital items in the consolidated statement of cash flows. This total cannot be presented under U.S. GAAP. A-3 SCHEDULE B FINANCIAL STATEMENTS OF CYPRESS ENERGY INC. AUDITORS' REPORT TO: The Shareholders of Cypress Energy Inc. We have audited the consolidated balance sheets of Cypress Energy Inc. as at December 31, 2000, 1999 and 1998 and the consolidated statements of income and retained earnings and cash flows for the years then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in Canada. Those standards require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of the Company as at December 31, 2000, 1999 and 1998 and the results of its operations and its cash flows for the years then ended in accordance with accounting principles generally accepted in Canada. Calgary, Canada /s/ Ernst & Young LLP April 16, 2001 Chartered Accountants B-1 CYPRESS ENERGY INC. CONSOLIDATED BALANCE SHEETS AS AT DECEMBER 31 (IN THOUSANDS OF DOLLARS)
--------------------------------------------------------------------------------------------------- 2000 1999 1998 --------------------------------------------------------------------------------------------------- Assets Current assets (note 6 Accounts receivable $ 31,813 $ 17,112 $ 9,531 Deposits, prepaids and other 2,531 2,452 542 Assets held for resale (note 3) -- 5,395 -- --------------------------------------------------------------------------------------------------- 34,344 24,949 10,073 Property and equipment (note 4) 368,479 270,572 136,489 --------------------------------------------------------------------------------------------------- $402,823 $295,531 $146,562 =================================================================================================== Liabilities and Shareholders' Equity Current Liabilities Accounts payable and accrued liabilities $ 47,870 $ 25,511 $ 10,392 --------------------------------------------------------------------------------------------------- Long-term debt (note 6) 113,889 92,760 34,559 Deferred rental obligation 532 772 -- Future income taxes (note 8) 61,743 8,017 518 Provision for future site restoration 3,972 2,043 618 --------------------------------------------------------------------------------------------------- 180,136 103,592 35,695 Shareholders' Equity Share capital (note 7) 149,747 155,478 96,921 Retained earnings 25,070 10,950 3,554 --------------------------------------------------------------------------------------------------- 174,817 166,428 100,475 --------------------------------------------------------------------------------------------------- $402,823 $295,531 $146,562 ===================================================================================================
Commitments and contingencies (notes 6 and 10) See accompanying notes B-2 CYPRESS ENERGY INC. CONSOLIDATED STATEMENTS OF INCOME AND RETAINED EARNINGS YEARS ENDED DECEMBER 31 (IN THOUSANDS OF DOLLARS EXCEPT PER SHARE AMOUNTS)
-------------------------------------------------------------------------------------------------------------- 2000 1999 1998 -------------------------------------------------------------------------------------------------------------- Revenue Petroleum and natural gas sales $ 186,763 $ 78,168 $ 34,124 Royalties, net of ARTC (45,180) 17,270) 7,098) -------------------------------------------------------------------------------------------------------------- 141,583 60,898 27,026 -------------------------------------------------------------------------------------------------------------- Expenses Production 18,394 11,983 6,235 General and administrative 4,453 3,508 1,894 Interest 7,785 3,758 1,281 Depletion, depreciation and site restoration 41,912 26,417 14,332 -------------------------------------------------------------------------------------------------------------- 72,544 45,666 23,742 -------------------------------------------------------------------------------------------------------------- Income before income taxes 69,039 15,232 3,284 ============================================================================================================== Income taxes Capital taxes 1,178 746 165 Future income taxes (note 8) 29,363 7,049 1,527 -------------------------------------------------------------------------------------------------------------- 30,541 7,795 1,692 -------------------------------------------------------------------------------------------------------------- Net income for the year 38,498 7,437 1,592 Retained earnings, beginning of year 10,950 3,554 1,962 Adjustment to reflect adoption of new income tax accounting policy (note 11) (20,195) -- -- Acquisition of shares in excess of carrying value (4,183) (41) -- -------------------------------------------------------------------------------------------------------------- Retained earnings, end of year $ 25,070 $ 10,950 $ 3,554 ============================================================================================================== Earnings per common share (note 9) -------------------------------------------------------------------------------------------------------------- Basic Class A and Class B shares $ 0.90 $ 0.20 $ 0.06 -------------------------------------------------------------------------------------------------------------- Fully diluted $ 0.84 $ 0.20 $ 0.06 ==============================================================================================================
See accompanying notes B-3 CYPRESS ENERGY INC. CONSOLIDATED STATEMENTS OF CASH FLOWS YEARS ENDED DECEMBER 31 (IN THOUSANDS OF DOLLARS EXCEPT PER SHARE AMOUNTS)
------------------------------------------------------------------------------------------------------------------ 2000 1999 1998 ------------------------------------------------------------------------------------------------------------------ Cash provided by (used in): Operating Activities Net income for the year $ 38,498 $ 7,437 $ 1,592 Non-cash items Depletion, depreciation and site restoration 41,912 26,417 14,332 Future income taxes 29,363 7,049 1,527 ------------------------------------------------------------------------------------------------------------------ Cash flow from operations 109,773 40,903 17,451 Net change in non-cash working capital items 12,734 1,561 2,525 ------------------------------------------------------------------------------------------------------------------ 122,507 42,464 19,976 ------------------------------------------------------------------------------------------------------------------ Funding Activities Increase in long-term debt 21,129 31,373 7,043 Issue of Class A flow-through shares -- 3,731 1,995 Issue of Special Warrants -- -- 20,600 Issue of Class A shares on exercise of stock options 1,378 991 688 Repurchase of Class A shares (9,577) (129) (3) Share issue and repurchase costs (note 7) (47) (1,724) (1,157) ------------------------------------------------------------------------------------------------------------------ 12,883 34,242 29,166 ------------------------------------------------------------------------------------------------------------------ Investing Activities Additions to property and equipment (135,096) (79,732) (48,917) Cash expenditures on acquisitions (note 5) -- (3,682) -- Cash acquired on acquisition (note 5) -- 6,905 -- Site restoration and abandonment expenditures (294) (197) (225) ------------------------------------------------------------------------------------------------------------------ (135,390) (76,706) (49,142) ------------------------------------------------------------------------------------------------------------------ Change in cash and cash, beginning and end of year -- -- -- ------------------------------------------------------------------------------------------------------------------ Cash flow from operations per common share (note 9) Basic Class A and Class B shares $ 2.56 $ 1.09 $ 0.68 Fully diluted $ 2.39 $ 1.04 $ 0.60 ==================================================================================================================
See accompanying notes B-4 CYPRESS ENERGY INC NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 2000, 1999 AND 1998 (THOUSANDS OF DOLLARS EXCEPT PER SHARE AMOUNTS) 1. DESCRIPTION OF THE BUSINESS Cypress Energy Inc. ("Cypress" or the "Company") was incorporated under the laws of the Province of Alberta on November 16, 1995. The Company's business is related to the acquisition of petroleum and natural gas rights and the exploration for, and the development, exploitation and production of, petroleum and natural gas in Canada. 2. SIGNIFICANT ACCOUNTING POLICIES BASIS OF PRESENTATION The consolidated financial statements have been prepared in accordance with Canadian generally accepted accounting principles which, in management's opinion, have been properly prepared within reasonable limits of materiality and within the framework of the accounting polices summarized below. PROPERTY AND EQUIPMENT Capitalized Costs The Company follows the full cost method of accounting in accordance with the guidelines issued by the Canadian Institute of Chartered Accountants whereby all costs associated with the exploration for and development of petroleum and natural gas reserves, whether productive or unproductive, are capitalized and charged to income as set out below. Such costs include lease acquisition, drilling, geological and geophysical, equipment costs, staff costs and certain overhead expenses directly related to exploration and development activities. Costs of acquiring and evaluating unproved properties are excluded from depletion calculations until it is determined whether or not proved reserves are attributable to the properties or when impairment occurs. Gains or losses are not recognized upon disposition of petroleum and natural gas properties unless crediting the proceeds against accumulated costs would result in a change in the rate of depletion of 20 percent or more. Depletion and Depreciation Depletion of petroleum and natural gas properties and depreciation of production equipment is provided on accumulated costs using the unit of production method based on estimated proven petroleum and natural gas reserves, before royalties, as determined by independent engineers. For purposes of the depletion calculation natural B-5 CYPRESS ENERGY INC NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 2000, 1999 AND 1998 gas reserves and production are converted to equivalent barrels of oil using the relative energy content of six thousand cubic feet of natural gas to one barrel of oil. Depreciation of gas plants and related equipment is provided for on a straight-line basis over fifteen years. The depletion and depreciation cost base includes total capitalized costs, less costs of unproved properties, plus a provision for future development costs of proven undeveloped reserves. CEILING TEST The Company applies a ceiling test to capitalized costs to ensure that such costs do not exceed the aggregate of estimated future net revenues from production of proven reserves and the costs of unproved properties, net of impairment allowances, less estimated future production costs, general and administrative costs, financing costs, site restoration and abandonment costs, and income taxes. Future net revenues are estimated using year-end prices and costs without escalation or discounting. and the income tax and Alberta Royalty Tax Credit legislation in effect at the year end. OFFICE FURNITURE AND EQUIPMENT Office furniture and equipment are carried at cost and are depreciated on a straight line basis over the estimated useful lives of the assets at rates varying between 15 percent and 20 percent. FUTURE SITE RESTORATION AND ABANDONMENT COSTS The estimated cost of future site restoration and abandonment is based on the current cost and the anticipated method and extent of site restoration and abandonment in accordance with existing legislation and industry practice. The annual charge, provided for on a unit of production basis, is accounted for as part of depletion, depreciation and site restoration expense. Site restoration expenditures are charged to the accumulated provision account as incurred. MEASUREMENT UNCERTAINTY The amounts recorded for depletion and depreciation of property and equipment and the provision for future site restoration and abandonment costs are based on estimates. The ceiling test calculation is based on estimates of proven reserves, production rates, oil and natural gas prices, future costs and other relevant assumptions. By their nature, these estimates are subject to measurement uncertainty and the effect on the consolidated financial statements of changes in such estimates in future years could be significant. B-6 CYPRESS ENERGY INC NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 2000, 1999 AND 1998 JOINT OPERATIONS Substantially all of the Company's exploration and development activities are conducted jointly with others, and accordingly the consolidated financial statements reflect only the Company's proportionate interest in such activities. FUTURE INCOME TAXES The Company follows the liability method in accounting for income taxes. Under this method future tax assets and liabilities are determined based on differences between financial reporting and income tax bases of assets and liabilities, and are measured using enacted tax rates and laws that will be in effect when the differences are expected to reverse. The effect on future tax assets and liabilities of a change in tax rates is recognized in net income in the period in which the change occurs. FLOW-THROUGH SHARES A portion of the Company's exploration and development activities is financed through proceeds received from the issue of flow-through shares. Under the terms of the flow-through share issues, the tax attributes of the related expenditures are renounced to the share subscribers. To recognize the foregone tax benefits to Cypress, the flow-through shares issued are recorded net of the tax benefits renounced as the expenditures are incurred and renounced with a corresponding future tax liability recorded. FINANCIAL INSTRUMENTS Financial instruments of the Company consist mainly of accounts receivable, accounts payable and accrued liabilities and long-term debt. As at December 31, 2000, 1999 and 1998 there are no significant differences between the carrying amounts reported on the balance sheet and the estimated fair values of the financial instruments. The Company also from time to time employs financial instruments to manage exposures related to interest rates, Canada/U.S. exchange rates and commodity prices. These instruments are not used for speculative trading purposes. Gains and losses on exchange rate and commodity price hedges are included in revenues upon the sale of the related production provided there is reasonable assurance that the hedge is and will continue to be effective. Amounts received or paid under interest rate swaps are recognized in interest expense on an accrual basis. B-7 CYPRESS ENERGY INC NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 2000, 1999 AND 1998 STOCK BASED COMPENSATION PLAN The Company follows the intrinsic value method of accounting for stock-based compensation plans. Consideration paid by employees, consultants or directors on the exercise of stock options is credited to share capital. Options are issued at current market value, consequently no compensation expense is recorded. 3. ASSETS HELD FOR RESALE On November 1, 1999 the Company acquired assets in the Thorsby area for $5.5 million. The Company has granted a third party an irrevocable option, exercisable through May 14, 2000, to purchase these assets for a purchase price equal to the original acquisition cost of $5.5 million subject to adjustments relating to operations from November 1, 1999 to the option exercise date. Assets held for resale has been shown net of revenue attributable to the property during the option period to date of $0.1 million. On March 3, 2000 the option was exercised and the properties were sold to the option holder. 4. PROPERTY AND EQUIPMENT
--------------------------------------------------------------------------------------------- 2000 1999 1998 --------------------------------------------------------------------------------------------- Petroleum and natural gas properties $ 449,895 $ 312,624 $ 153,392 Office furniture and equipment 1,170 845 497 451,065 313,469 153,889 Accumulated depletion and depreciation (82,586) (42,897) (17,400) Net property and equipment $ 368,479 $ 270,572 $ 136,489
At December 31, 2000 the Company estimates its liability for future site restoration and abandonment to be $12.6 million (net of the year-end accumulated provision) (1999 - $7.8 million; 1998 - $3.3 million). At December 31, 2000 $34.5 million (1999 - $31.4 million; 1998 - $9.5 million) of costs associated with unproved properties have been excluded from costs subject to depletion. 5. ACQUISITIONS (a) ACQUISITION OF CANADIAN CONQUEST EXPLORATION INC. In May, 1999, the Company acquired all of the common shares of Canadian Conquest Exploration Inc. ("Canadian Conquest"). Canadian Conquest was amalgamated with Cypress effective September 1, 1999. The acquisition was accounted for by the purchase method and the purchase price was allocated as follows: B-8 CYPRESS ENERGY INC NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 2000, 1999 AND 1998 Net working capital $ 1,140 Property and equipment 75,396 Long-term debt (26,828) Rent obligation (1,207) Provision for deferred taxes (1,215) Provision for future site restoration (702) -------------------------------------------------------------------------------- Total Consideration $ 46,584 ================================================================================ Consideration was comprised of Cash $ 3,619 Issue of 10,479,200 Class A shares at $4.10 per share 42,965 -------------------------------------------------------------------------------- Total Consideration $ 46,584 ================================================================================ (b) ACQUISITION OF GARDINER EXPLORATION LIMITED In July, 1999, the Company acquired all of the common shares of Gardiner Exploration Limited ("Gardiner"). Gardiner was amalgamated with Cypress effective September 1, 1999. The acquisition was accounted for by the purchase method and the purchase price was allocated as follows: Cash $ 6,905 Net non-cash working capital 623 Property and equipment 8,280 -------------------------------------------------------------------------------- Total Consideration $ 15,808 ================================================================================ Consideration was comprised of Cash $ 63 Issue of 2,581,200 Class A shares at $6.10 per share 15,745 -------------------------------------------------------------------------------- Total Consideration $ 15,808 ================================================================================ 6. LONG- TERM DEBT At December 31, 2000, the Company had a $180.0 million syndicated revolving term credit facility, which was subsequently increased to $200.0 million. The loan facility provides that advances may be made by way of direct advances, bankers acceptances or U.S. dollar LIBOR advances which bear interest at the applicable bankers' acceptances or LIBOR rates plus an applicable bank fee per annum or the bank's prime lending rate depending on the nature of the advance. The authorized limit is subject to an annual review and redetermination of the Company's borrowing base by the bank. The effective interest rate on the amounts outstanding under the facility at December 31, 2000 was 6.8 percent (1999 - 5.7 percent; 1998 - 5.9 percent). B-9 CYPRESS ENERGY INC NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 2000, 1999 AND 1998 Cash interest paid for the years ended December 31, 2000, 1999 and 1998 approximated interest expense. Collateral pledged for the facility consists of a fixed and floating charge demand debenture in the principal amount of $300.0 million conveying a floating charge on all of the property and assets of the Company. While the credit facility is demand in nature, the bank has stated that it is not its intention to call for repayment before December 31, 2001 provided that there is no adverse change in the Company's financial position. Accordingly, the loan advances are classified as long-term. At December 31, 2000, the Company was party to a contract to fix the interest rate on $9.0 million of its loan advances at approximately 6.8 percent until March 11, 2002. In addition, the counterparty to the contract has an option to extend the contract at its expiry to March 11, 2004 at the same rate and for the same notional amount. If the Company were required to settle this contract at December 31, 2000, a cash payment of approximately $0.2 million would be required. B-10 CYPRESS ENERGY INC NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 2000, 1999 AND 1998 7. SHARE CAPITAL AUTHORIZED: Unlimited number of Class A and Class B common voting shares ISSUED:
2000 1999 1998 ----------------------------------------------------------------------------------------------------------------------------- NUMBER OF NUMBER OF NUMBER OF SHARES SHARES SHARES (000S) AMOUNT (000s) Amount (000s) AMOUNT ----------------------------------------------------------------------------------------------------------------------------- Class A Shares Outstanding, beginning of year 42,521 $ 161,211 28,256 $ 97,867 23,408 $ 74,587 On acquisition of Canadian Conquest (see note 5) - -- 10,479 42,965 -- -- On acquisition of Gardiner (see Note 5) -- -- 2,581 15,745 -- -- Private Placement (a) -- -- 746 3,731 547 1,995 Adjustment to reflect adoption of new income tax accounting policy (see note 11) -- (1,668) -- -- -- -- Special Warrants financings (b) -- -- -- -- 4,000 20,600 Repurchase of Class A Shares (1,438) (5,394) (24) (88) (1) (3) Exercised stock options 410 1,378 483 991 302 688 Class A Shares Outstanding, end of year 41,493 155,527 42,521 161,211 28,256 97,867 Class B Shares (c) Outstanding, beginning and end of year 558 5,580 558 5,580 558 5,580 161,107 166,791 103,447 Share issue costs (d) (4,179) (4,132) ( 3,173) Tax benefits renounced (a) (7,181) (7,181) (3,353) Total Share Capital $ 149,747 $ 155,478 $ 96,921
(a) On December 31, 1999 Cypress issued 746,263 (1998 - 546,574) flow-through shares at $5.00 (1998 - $3.65) per share resulting in gross proceeds of $3.7 million (1998 - $2.0 million). B-11 CYPRESS ENERGY INC NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 2000, 1999 AND 1998 During 2000, in accordance with the terms of the flow-through share offering and pursuant to certain provisions of the Income Tax Act (Canada), Cypress incurred aggregate exploration expenditures of $3.7 million and renounced the tax benefits to the purchasers of its flow-through shares. (b) On March 30, 1998, Cypress completed a Special Warrants financing consisting of 4,000,000 Special Warrants at $5.15 per Special Warrant for gross proceeds of $20.5 million. The Special Warrants were converted in April, 1998 into 4,000,000 Class A shares for no additional consideration. (c) The Class B shares are convertible at the option of Cypress into Class A shares at any time after March 1, 2000 and before March 1, 2002. After March 1, 2002 the Class B shares are convertible at the option of the shareholder until June 30, 2002 when all remaining Class B shares will be deemed to be converted. The number of Class A shares to be issued on conversion of each Class B share will be equal to $10.00 divided by the greater of $1.00 or the current market price of the Class A shares at the conversion date. (d) The total share issue costs incurred related to the 2000, 1999 and 1998 share issues were $0.05 million, $1.7 million and $1.2 million respectively. A charge to share capital of $0.05 million (1999 - $1.0 million; 1998 - $0.6 million) was recorded to reflect these costs, with no associated estimated future tax benefit in 2000 (1999 - estimated deferred tax benefit of $0.7 million; 1998 - $0.6 million). STOCK OPTIONS The Company has established a stock option plan whereby options may be granted to its directors, officers and employees. The exercise price of each option equals the market price of the Company's stock on the date of the grant and an option's maximum term is five years. The stock options are exercisable over a five-year period from the date of grant. The options are exercisable on a cumulative basis of 20 percent immediately and 20 percent per year for each of the first four years of the plan. No compensation expense is recognized for the plan when stock options are issued or exercised. The following is a continuity of stock options outstanding for which shares have been reserved: B-12 CYPRESS ENERGY INC NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 2000, 1999 AND 1998
2000 1999 1998 ------------------------------------------------------------------------------------------------------------------------------- WEIGHTED WEIGHTED WEIGHTED AVERAGE AVERAGE AVERAGE EXERCISE EXERCISE EXERCISE SHARES PRICE SHARES PRICE SHARES PRICE (000S) ($) (000S) ($) (000S) ($) ------------------------------------------------------------------------------------------------------------------------------- Balance, beginning of year 3,582 $ 3.96 2,181 $ 3.06 1,456 $ 2.51 Granted 1,009 $ 6.82 1,925 $ 4.48 1,119 $ 3.55 Exercised (410) $ 3.39 (483) $ 2.05 (302) $ 2.05 Cancelled (43) $ 3.53 (41) $ 3.37 (92) $ 2.99 ------------------------------------------------------------------------------------------------------------------------------- Balance, end of year 4,138 $ 4.71 3,582 $ 3.96 2,181 $ 3.06 ===============================================================================================================================
The following summarizes information about stock options outstanding at December 31, 2000:
---------------------------------------------------------------------------------------------------------------------------- WEIGHTED AVERAGE NUMBER REMAINING WEIGHTED NUMBER WEIGHTED RANGE OF OUTSTANDING CONTRACTUAL AVERAGE EXERCISABLE AVERAGE EXERCISE AT 12/31/00 LIFE EXERCISE AT 12/31/00 EXERCISE PRICES (000S) (YEARS) PRICE (000S) PRICE ---------------------------------------------------------------------------------------------------------------------------- $ 1.78 to $ 2.75 212 1.1 $ 2.21 181 $ 2.12 $ 3.15 to $ 3.75 1,065 2.6 $ 3.48 492 $ 3.52 $ 4.10 to $ 4.95 1,805 3.5 $ 4.53 709 $ 4.52 $ 5.45 to $ 6.00 397 4.3 $ 5.94 81 $ 5.96 $ 6.85 to $ 7.30 659 4.9 $ 7.29 132 $ 7.29 ---------------------------------------------------------------------------------------------------------------------------- 4,138 3.4 $ 4.71 1,595 $ 4.24 ============================================================================================================================
8. FUTURE INCOME TAXES The liability for future income taxes is primarily due to the excess carrying value of property plant and equipment over the associated tax basis. B-13 CYPRESS ENERGY INC NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 2000, 1999 AND 1998 The effective tax rate used in the financial statements differs from the statutory income tax rate due to the following:
2000 1999 1998 ------------------------------------------------------------------------------------------------ Statutory tax rate 44.7% 45.0% 45.0% ------------------------------------------------------------------------------------------------ Calculated income tax expense $ 30,840 $ 6,796 $ 1,478 Increase (decrease) in income tax resulting from: Non-deductible Crown payments (net of ARTC) 15,007 4,757 1,174 Resource allowance (16,103) (6,321) (2,445) Other (381) 1,817 1,320 ------------------------------------------------------------------------------------------------ Total future income tax 29,363 7,049 1,527 Large corporation and capital tax 1,178 746 165 ------------------------------------------------------------------------------------------------ Income tax provision $ 30,541 $ 7,795 $ 1,692 ================================================================================================
As at December 31, 2000, the Company has exploration and development costs. undepreciated capital costs and unamortized share issue costs and loss carryforwards available for deduction against future taxable income in aggregate of approximately $209.2 million (1999 - $185.5 million; 1998 - $106.5 million). Cash tax paid for the years ended December 31, 2000, 1999 and 1998 approximated the amounts reported above for large corporation and capital taxes for each of the years. 9. PER SHARE AMOUNTS The calculations of "earnings per common share-basic" and "cash flow from operations per common share - basic" are based on the weighted average number of Class A shares outstanding during the year ended December 31, 2000 of 42.9 million (1999 - 36.5 million; 1998 - $24.3 million). The "fully diluted" weighted average number of shares outstanding during the year ended December 31, 2000 is 46.5 million (1999 - 39.9 million; 1998 - $29.7 million). The number of shares for the calculation of "Class A and Class B" and "fully diluted" assumes that the Class B shares were deemed to be converted into Class A shares based on the conversion formula described in note 7(c) using the trading price of the Class A shares as at December 31, 2000 which was $9.75 (1999 - $6.10; 1998 - $3.85). The fully diluted number of shares also includes the effects of exercising outstanding stock options. Cash flow from operations per share is based on cash flow from operations before changes in non-cash working capital items. B-14 CYPRESS ENERGY INC NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 2000, 1999 AND 1998 10. COMMODITY MARKETING ARRANGEMENTS As at December 31, 2000, physical delivery contracts were in effect to deliver a total of 5,201 gigajoules ("GJ") per day at prices as set out in the following table: SALES VOLUME CONTRACT EXPIRY (GJ/DAY) TERMS DATES ---------- -------------------------------------- --------------------- 2,740 AECO Daily Spot less $0.075/GJ October 31, 2002 2,461 AECO Monthly plus variable premium, September 30, 2003 less 3% marketing fee The balance of 2000 gas sales was split between aggregator sales (approximately 13.5 mmcf/d) and spot gas sales. All liquids are sold on a spot basis. At December 31, 2000, the Company had no financial natural gas contracts or swaps outstanding. 11. CHANGE IN ACCOUNTING POLICY - FUTURE INCOME TAX Effective January 1, 2000, Cypress adopted the Canadian Institute of Chartered Accountants' new accounting recommendations with respect to income taxes. The new recommendations were applied retroactively without restatement of prior year financial statements. The application of the new liability method for income taxes resulted in a change against retained earnings of $20.2 million (largely as a result of prior years' corporate acquisitions). There was a corresponding increase to the Company's liability for future income taxes of $24.4 million, an increase to property plant and equipment of $2.5 million and a reduction to share capital of $1.7 million. Prior to the adoption of the new recommendation, the Company followed the deferral method of accounting for income taxes. Under this method, the Company provided for deferred income taxes to the extent that income taxes otherwise payable were reduced by exploration and development costs and capital cost allowances in excess of the depletion and depreciation provisions recorded in the accounts. 12. SUBSEQUENT EVENTS On February 28, 2001 the Company announced that it had mailed to the registered shareholders of Ranchero Energy Inc. ("Ranchero") its Offer to Purchase ("Offer") all of the outstanding Class A shares of Ranchero ("Ranchero shares") on the basis of, for each Ranchero share, $1.68 in cash or 0.1723 of a Class A share of Cypress, subject to an aggregate maximum of 1,076,900 Class A shares of Cypress and subject to pro-ration. On March 23, 2001 the Company announced that all of the conditions to the Offer were satisfied. B-15 CYPRESS ENERGY INC NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 2000, 1999 AND 1998 On February 16, 2001 PrimeWest Energy Trust ("PrimeWest") and Cypress jointly announced that they had entered into an agreement whereby PrimeWest offered to purchase all of the issued and outstanding common shares of Cypress. The offer consisted of cash of $14.00 per Cypress share up to a maximum of $60.0 million, or, at the option of the Cypress shareholder, 1.45 PrimeWest trust units or 1.45 exchangeable shares of a subsidiary of PrimeWest (subject to a maximum of 5.44 million exchangeable shares). On March 29, 2001, PrimeWest announced that all of the conditions to the Offer were satisfied. B-16 SCHEDULE C FINANCIAL STATEMENTS OF RESERVE ROYALTY CORPORATION AUDITORS' REPORT TO: The Shareholders of Reserve Royalty Corporation We have audited the consolidated balance sheets of Reserve Royalty Corporation as at December 31, 1999 and 1998, and the consolidated statements of operations and deficit and cash flows for the years then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements, based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards. Those standards require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of the Company as at December 31, 1999 and 1998, and the results of its operations and its cash flows for the years then ended, in accordance with generally accepted accounting principles. /s/ KPMG LLP Chartered Accountants Calgary, Alberta April 14, 2000 C-1 RESERVE ROYALTY CORPORATION CONSOLIDATED BALANCE SHEETS
At December 31 ------------------------------------------------------------------------------------------------------- (THOUSANDS) 1999 1998 ------------------------------------------------------------------------------------------------------- ASSETS Current Cash $ 275 $ 200 Marketable securities (market $17; 1998 - $1,831) 14 1,831 Accounts receivable 4,247 11,940 Inventory, prepaid expenses and deposits 550 1,444 Notes receivable -- 700 ------------------------------------------------------------------------------------------------------- 5,086 16,115 Petroleum and natural gas properties Note 2 115,979 212,693 ------------------------------------------------------------------------------------------------------- $ 121,065 $ 228,808 ======================================================================================================= LIABILITIES AND SHAREHOLDERS' EQUITY Current Accounts payable and accrued liabilities $ 6,394 $ 10,155 Current portion of long-term debt Note 3 -- 38,866 ------------------------------------------------------------------------------------------------------- 6,394 49,021 Long-term debt Note 3 35,055 61,314 Hedging contracts assumed on acquisition Note 6 -- 1,710 Future site restoration provision 382 3,090 ------------------------------------------------------------------------------------------------------- 41,831 115,135 ------------------------------------------------------------------------------------------------------- Shareholders' equity Share capital Note 4 212,558 212,558 Deficit (133,324) (98,885) ------------------------------------------------------------------------------------------------------- 79,234 113,673 ------------------------------------------------------------------------------------------------------- $ 121,065 $ 228,808 =======================================================================================================
See accompanying notes to Consolidated Financial Statements. C-2 RESERVE ROYALTY CORPORATION CONSOLIDATED STATEMENTS OF OPERATIONS AND DEFICIT
For the Years Ended December 31 --------------------------------------------------------------------------------------------------------- (thousands, except per share amounts) 1999 1998 --------------------------------------------------------------------------------------------------------- Resource revenue $ 21,605 $ 39,478 Other income (loss) Gain (loss) from marketable securities 2,887 (89) Gas marketing gain (loss) Note 7 (4,640) 1,066 Interest and other income 76 538 Commodity and exchange hedging losses (490) (649) --------------------------------------------------------------------------------------------------------- 19,438 40,344 Expenses Administration (4,308) (4,172) Interest and financing (4,625) (6,843) Production (2,719) (8,758) Royalties (327) (3,039) Writedown of marketable securities -- (1,909) Writedown of inventory and accounts receivable -- (819) Depletion, depreciation and amortization (11,998) (21,727) Writedown of petroleum and natural gas properties (30,000) (118,591) --------------------------------------------------------------------------------------------------------- (53,977) (165,858) --------------------------------------------------------------------------------------------------------- Loss before income taxes (34,539) (125,514) --------------------------------------------------------------------------------------------------------- Provision for income taxes Current recovery (expense) 100 (664) Deferred reduction -- 18,591 --------------------------------------------------------------------------------------------------------- 100 17,927 --------------------------------------------------------------------------------------------------------- Loss for the year (34,439) (107,587) Retained earnings (deficit), beginning of period (98,885) 8,702 --------------------------------------------------------------------------------------------------------- Deficit, end of period $ (133,324) $ (98,885) --------------------------------------------------------------------------------------------------------- Loss per common share $ (0.34) $ (1.10) Weighted average number of common shares outstanding 102,252 97,533 =========================================================================================================
See accompanying notes to Consolidated Financial Statements. C-3 RESERVE ROYALTY CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31 ----------------------------------------------------------------------------------------------------------- (thousands, except per share amounts) 1999 1998 ----------------------------------------------------------------------------------------------------------- Net inflow (outflow) of cash related to the following activities: OPERATIONS Loss for the year $ (34,439) $ (107,587) Items not affecting cash: Writedown of marketable securities -- 1,909 Writedown of inventory and accounts receivable -- 819 Depletion, depreciation and amortization 11,998 21,727 Writedown of petroleum and natural gas properties 30,000 118,591 Deferred income taxes -- (18,591) ----------------------------------------------------------------------------------------------------------- Funds from operations 7,559 16,868 Net change in non-cash working capital items 7,343 (11,030) ----------------------------------------------------------------------------------------------------------- Cash provided by operating activities 14,902 5,838 ----------------------------------------------------------------------------------------------------------- FINANCING Long-term debt repayments (65,125) (13,120) Payment on hedging contracts assumed on acquisition (1,710) (617) Issue of common shares, net of issue costs -- 146 Share purchase loans -- (340) ----------------------------------------------------------------------------------------------------------- Cash provided by financing activities (66,835) (13,931) ----------------------------------------------------------------------------------------------------------- INVESTMENTS Petroleum and natural gas properties (4,600) (20,037) Proceeds on disposal of petroleum & natural gas properties 56,608 28,318 ----------------------------------------------------------------------------------------------------------- Cash provided by investing activities 52,008 8,281 ----------------------------------------------------------------------------------------------------------- Increase in cash during the year 75 188 Cash, beginning of year 200 12 ----------------------------------------------------------------------------------------------------------- Cash, end of year $ 275 $ 200 ----------------------------------------------------------------------------------------------------------- Funds from operations per common share: Basic $ 0.07 $ 0.17 Fully diluted $ 0.07 $ 0.16 -----------------------------------------------------------------------------------------------------------
See accompanying notes to Consolidated Financial Statements. C-4 RESERVE ROYALTY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS YEARS ENDED DECEMBER 31, 1999 AND 1998 GENERAL The Company's principal activities are the ownership of royalty interests and the production of crude oil and natural gas. 1. SIGNIFICANT ACCOUNTING POLICIES (a) Principles of consolidation The consolidated financial statements of the Company include the accounts of all subsidiary companies. A portion of activities is conducted jointly with others and these financial statements include only the Company's proportionate interest in such activities. (b) Capital assets The Company follows the full cost method of accounting for its investment in crude oil and natural gas interests whereby all costs related to the acquisition, exploration and development for production of crude oil and natural gas are capitalized. These costs include those related to the acquisition and retention of royalties, reserves, and mineral rights, geological and geophysical activities, the drilling of productive and non-productive wells, and overhead directly related to exploration, development and acquisition activities. The costs are accumulated on a country by country basis with substantially all of the Company's activities and costs centered in Canada. Capitalized costs, plus an estimate for future costs associated with proven non-producing interests, are depleted and depreciated using the unit-of-production method based upon production volumes as a proportion of proven reserves after royalties, as estimated by internal and independent engineers. For purposes of depletion and depreciation, proven reserves and production volumes are converted to a common unit of measure on the basis of relative energy content. The carrying value of undeveloped interests is excluded from the depletion and depreciation calculation. Proceeds on the disposition of interests reduce the accumulated capitalized costs. Gains and losses on the disposition of interests are only recognized where crediting of the proceeds results in a change in the unit depletion and depreciation rate which exceeds 20 percent. Estimated future abandonment and site restoration costs for petroleum and natural gas interests are provided for over the life of the proven C-5 RESERVE ROYALTY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS YEARS ENDED DECEMBER 31, 1999 AND 1998 reserves on a unit-of-production basis. Actual restoration costs are charged to the site restoration provision as incurred. The net book value of interests is subject to a cost recovery test whereby the net book value, including an estimate for future costs associated with proven non-producing interests, is compared to the estimated future net revenue from proven reserves less a provision for future abandonment and site restoration costs, administration, financing costs, and income taxes. Additional depletion and depreciation is provided where the carrying value exceeds the future recoverable net revenue from the proven reserves. The amounts recorded for depletion, depreciation and amortization of capital assets and the provision for future site restoration, if any, are based on estimates of proved reserves and future costs. The recoverable value of the capital asset is based on a number of factors including estimated proven reserves, crude oil and natural gas prices and future costs. By their nature, these estimates are subject to measurement uncertainty and the impact on these financial statements and future periods can be material. (c) Income taxes The Company follows the deferral method of accounting for income taxes which relates the provision for income taxes to the accounting income for the period. Under the deferral method, the amount by which the tax provision differs from the amount of tax currently payable is considered to represent the deferring to future periods of benefits obtained or expenditures incurred in the current period, and accordingly is computed at current tax rates. The accumulated tax allocation debit or credit is not adjusted to reflect subsequent changes in tax rates. (d) Stock option plan The Company has a stock option plan described in note 4c. The Company does not record a compensation expense at the time of granting. Proceeds received on the exercise of stock options are credited to share capital when received. (e) Per share information Per share amounts are based on the weighted average number of common shares outstanding. Fully diluted amounts are based on the weighted average number of common shares outstanding adjusted for the inclusion of stock options and warrants which would be dilutive. The calculation of fully diluted amounts include imputed interest on the proceeds that would have been received. C-6 RESERVE ROYALTY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS YEARS ENDED DECEMBER 31, 1999 AND 1998 (f) Comparative figures Certain comparative amounts have been restated to conform with current year presentation. 2. PETROLEUM AND NATURAL GAS PROPERTIES
------------------------------------------------------------------------------------- (thousands) 1999 1998 ------------------------------------------------------------------------------------- Petroleum and natural gas properties, at cost $ 315,333 $ 370,115 Other equipment 1,360 1,294 Accumulated depletion, depreciation (200,714) (158,716) ------------------------------------------------------------------------------------- $ 115,979 $ 212,693 -------------------------------------------------------------------------------------
For the year ended December 31, 1999, $1,639,000 (1998 - $1,701,000) of administrative expenses directly related to exploration, development, acquisition and divestiture activities were capitalized. At December 31, 1999 undeveloped properties with a carrying value of $17,057,000 (1998 - $76,609,000) have been excluded from costs subject to depletion and depreciation. At December 31, 1999, $60 million of costs associated with unproven properties at December 31, 1998 have been moved into the full cost pool and included in the ceiling test evaluation. In conducting the December 31, 1999 ceiling test evaluation, the Company determined that the capitalized costs in respect of oil and gas properties exceeded the estimated future net revenues from proven reserves by $30 million and a writedown for the same amount has been recorded. At December 31, 1999, the evaluation was performed using the December 1999 prices for the Company of $34.52 Cdn per barrel for oil and natural gas liquids (based on an average 1999 WTI price of $26.09 US per barrel), and $2.35 Cdn per thousand cubic feet for natural gas. In conducting the December 31, 1998 ceiling test evaluation, the Company determined that the capitalized costs in respect of oil and gas properties exceeded the estimated future net revenues from proven reserves by $100 million (net of recovery of $18.6 million of deferred taxes) and a writedown for the same amount has been recorded. At December 31, 1998, the evaluation was performed using average 1998 prices for the Company of $19.33 Cdn per barrel for oil and natural gas liquids (based on an average 1998 WTI price of $14.43 US per barrel), and $1.96 Cdn per thousand cubic feet for natural gas. The ceiling test is a cost recovery test and is not intended to result in an estimate of fair value. C-7 RESERVE ROYALTY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS YEARS ENDED DECEMBER 31, 1999 AND 1998 3. LONG TERM DEBT At December 31, 1999 the Company had a revolving term credit facility of $39,000,000 with a Canadian chartered bank in accordance with a Credit Agreement dated November 18, 1999. At December 31, 1999, $35,055,000 had been drawn under this credit facility. The credit facility revolves until May 31, 2000, at which time the revolving period may be extended based on an annual review. The Company has requested a new revolving period extending beyond December 31, 2000. The bank has advised the Company that, subject to possible changes in the Borrowing Base and to the Company satisfying the general conditions and general borrowing reporting conditions of the Credit Agreement, the bank will not require either, that any principal repayments will be required under the credit limit prior to January 1, 2001, or that any demand will be made by the bank for repayments of the credit limit prior to January 1, 2001. Security for the indebtedness is provided by a general assignment of accounts receivable, a demand debenture conveying a first floating charge overall assets, and a registered assignment over oil and gas properties. Interest, at bank prime rate plus 1/8 of one percent, in the amount of $47,986 was paid under this credit facility during 1999. Subsequent to December 31, 1999, the Company received proceeds of $6.9 million on the disposal of oil and gas properties. These proceeds were applied to the outstanding bank debt and the authorized credit facility was reduced to $36,000,000. At December 31, 1998, the Company had combined credit facilities of $101,707,212 with two Canadian chartered banks against which $100,180,000 had been drawn. A portion of the long term debt at December 31, 1998, was a revolving credit facility of $19,000,000 against which $18,080,000 had been drawn. Under conditions at the time, the Company did not expect that principal repayment would be required within the next year. Security for this indebtedness was provided by a general assignment of accounts receivable, a demand debenture conveying a first floating charge over all assets, and a registered assignment over oil and gas properties for the Company and a wholly owned subsidiary. Interest, at bank prime rate plus 1/8 of one percent, in the amount of $1,118,688 was paid under this credit facility during 1998. The Company had a non-revolving term loan at December 31, 1998 of $82,707,212 against which $82,100,000 had been drawn. The credit facility was repayable with minimum repayments of $5,067,996 by December 31, 1998, $2,905,394 by January 8, 1999, $12,019,818 by February 28, 1999, and $7,980,182 quarterly from May 31, 1999. Security for this indebtedness was provided by a general assignment of accounts receivable, a demand debenture conveying a first floating charge over all assets, and a registered assignment over oil and gas properties of a wholly owned subsidiary. C-8 RESERVE ROYALTY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS YEARS ENDED DECEMBER 31, 1999 AND 1998 Interest, at bank prime rate plus 1 percent, in the amount of $3,229,748 was paid under these credit facilities during 1998. 4. SHARE CAPITAL (a) Authorized: Unlimited number of common shares Unlimited number of first preferred shares, non-voting, cumulative dividend of 10 percent of redemption value, redeemable on or after January 1, 1995 at $1.00 each plus any unpaid dividends thereon, convertible into common shares at the rate of 1 common share for each $15.00 of redemption value. Unlimited number of second and third preferred shares with attributes to be determined by the board of directors. (b) Issued:
---------------------------------------------------------------------------------------------------------- Common shares 1999 1998 Number of Number of (all amounts in thousands) Shares Amount Shares Amount ---------------------------------------------------------------------------------------------------------- Balance, beginning of year 102,252 $ 212,558 57,124 $ 46,302 Conversion of special warrants(i) -- 45,000 166,426 Share issue costs, net of deferred tax -- (30) Exercise of stock options(ii) -- 128 200 Share purchase loans(iii) -- (340) ---------------------------------------------------------------------------------------------------------- 102,252 $ 212,558 102,252 $ 212,558 ----------------------------------------------------------------------------------------------------------
i. On November 5, 1997, the Company issued 45,000,000 special warrants at a price of $3.80 per special warrant for gross proceeds of $171,000,000. These warrants were converted into 45,000,000 common shares between February 3rd and 11th, 1998 pursuant to a prospectus dated January 30, 1998. ii. A total of 127,834 common shares were issued in 1998 on the exercise of share purchase options which had exercise prices of between $0.90 and $2.40. iii. Share purchase loans of $340,000 secured by common shares of the Company were recorded as a reduction in share capital in 1998. These loans to officers of the Company are secured by 99,500 common shares of the Company. (c) Options Under the Stock Option Plan of the Company, the Board of Directors of the Company or a committee thereof, may allocate non-transferable options to purchase common shares to such directors, officers or employees of the Company, or any other person or company engaged in C-9 RESERVE ROYALTY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS YEARS ENDED DECEMBER 31, 1999 AND 1998 providing ongoing management or consulting services for the Company, as the Board of Directors may determine from time to time. Options issued pursuant to the Plan will have an exercise price equal to the average price of common shares in respect of all board lot trades on the TSE on the day such option is granted. The options granted are exercisable one third at time of granting, one third a year after granting, and one third two years after granting. The options expire five years after the date they are granted. A summary of the status of the Company's stock option plan as of December 31, 1999 and changes during the year is presented below: Fixed Options 1999 Weighted Avg. Shares Exercise Price -------------------------------------------------------------- Outstanding, beginning of year 3,491,500 $ 1.93 Granted 2,643,000 $ 0.41 Exercised - Forfeited (568,000) $ 1.86 ------------ Outstanding, end of year 5,566,500 $ 0.97 ============ Including the re-pricing of 428,500 employee options from $1.35 per share to $0.41 per share in 1999. Options exercisable at December 31, 1999 3,444,167 The following table summarizes information about the fixed stock options outstanding at December 31, 1999: C-10 RESERVE ROYALTY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS YEARS ENDED DECEMBER 31, 1999 AND 1998
Options Outstanding Options Exercisable --------------------------------------------------------------------------------------- Weighted Avg. Weighted Avg. Remaining Contract Remaining Contract Exercise Price Dec 31-99 Life Dec 31-99 Life --------------------------------------------------------------------------------------- $ 0.41 2,769,000 4.6 965,000 4.6 $ 0.90 850,000 0.9 850,000 0.9 $ 1.12 250,000 1.4 250,000 1.4 $ 1.35 862,500 3.7 589,167 3.7 $ 2.40 200,000 2.4 200,000 2.4 $ 4.25 635,000 3.0 590,000 3.0 --------------------------------------------------------------------------------------- $ 0.97 5,566,500 3.5 3,444,167 2.9 =======================================================================================
(d) Warrants On January 8, 1999, the Company issued 200,000 warrants associated with a financing arrangement. The warrants are exercisable into 200,000 common shares of the Company at $0.60 per share expiring January 8, 2000. The Warrants expired unexercised on January 8, 2000. C-11 RESERVE ROYALTY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS YEARS ENDED DECEMBER 31, 1999 AND 1998 5. INCOME TAX The provision for income taxes varies from that calculated by applying the combined statutory Canadian federal and provincial income tax rate to income before tax as follows:
--------------------------------------------------------------------------------------- (dollar amounts in thousands) 1999 1998 --------------------------------------------------------------------------------------- Earnings before income taxes $ (34,539) $ (125,514) Statutory income tax rate 45% 45% --------------------------------------------------------------------------------------- Expected income tax provision $ (15,543) $ (56,482) Effect on taxes of: Non-deductible Crown charges, net of ARTC 130 575 Federal resource allowance (212) (596) Non-deductible depletion & ceiling test writedown 13,951 37,740 Non-taxable portion of capital loss (gain) (504) 172 Unrecognized benefit of losses 2,178 -- Other (250) -- Large corporations tax & provincial surtaxes 150 664 ---------------------------------------------------------- ------------- -------------- $ (100) $ (17,927) ---------------------------------------------------------- ------------- --------------
Oil and gas properties with a net book value of $20 million (1998 - $51 million) have no cost basis for income tax purposes arising from the purchase of oil and gas properties through corporate transactions. 6. FINANCIAL INSTRUMENTS The Company is exposed to fluctuations in commodity prices, interest rates, and exchange rates. In order to mitigate the exposure to cash flow risk associated with product prices, foreign currency transactions, and interest rates, the Company may be party to certain financial instruments such as commodity futures and swap arrangements, forward exchange contracts and interest rate swap contracts. Except as noted below, these instruments are not reflected in the financial statements at inception, rather payments and receipts from these contracts are recognized as revenues in the same period as the production revenue to which they relate. Payment and receipts under the interest rate swap contracts are reflected as adjustments to interest expense. Financial instruments C-12 RESERVE ROYALTY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS YEARS ENDED DECEMBER 31, 1999 AND 1998 are subject to fluctuations in price and rates, but by nature of being hedges of an actual or anticipated transaction, any gains or losses are offset by gains or losses on the hedged transaction. The Company is exposed to losses in the event of non-performance by counter- parties to the financial instruments. The Company deals with major institutions and does not anticipate non-performance by counterparties. At December 31, 1999, the Company had a hedging contract associated with interest rates which was acquired in a 1997 corporate acquisition and restructured during 1998, and a hedging contract associated with oil prices pursuant to an agreement dated September 22, 1999. At December 31, 1999, a net payment by the Company of $466,806 would have been required to terminate the open position of the financial instrument relating to interest rates and a net payment by the Company of $213,857 would have been required to terminate the open position of the financial instrument relating to oil price. At December 31, 1998, the Company had hedging contracts associated with exchange rates and interest rates which were acquired in the 1997 corporate acquisition and restructured during 1998. At December 31, 1998, it was estimated that a net payment by the Company of $5.2 million would have been required to terminate the open position of financial instruments relating to exchange rates, and $2.0 million to terminate the open position of financial instruments relating to interest rates. Hedging contracts which are acquired as part of the purchase of a subsidiary are valued at the date of the acquisition, and the resulting asset or liability is reduced over the period of the hedging contract. As at December 19, 1997, with the acquisition of Jordan, and at December 31, 1997, it was estimated that net payment by the Company of $2.3 million would have been required to terminate the open positions of financial instruments relating to natural gas prices, exchange rates, and interest rates. The estimated net market value of hedging contracts assumed on acquisition at December 19, 1997 was recorded as a liability on the balance sheet. The liability set up December 19, 1997 was settled with payments by the Company of $617,057 in 1998, and $1,710,300 in 1999. (a) Foreign currency risk management At December 31, 1999 the Company had no outstanding hedging commitments associated with exchange rates. At December 31, 1998 the Company had a forward exchange swap transaction for a period ending December 31, 1999, with an option for the C-13 RESERVE ROYALTY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS YEARS ENDED DECEMBER 31, 1999 AND 1998 counterparty to extend to December 31, 2001, whereby $1,000,000 US per month has been sold forward at a rate of 1.3952. (b) Interest rates risk management At December 31, 1998 and 1999 the Company had an interest rate swap for a period ending May 22, 2002, with an option for the counterparty to extend to May 25, 2004, whereby the interest rate on $25 million has been fixed at 6.48 percent. (c) Oil price risk management At December 31, 1999 the Company had an oil price swap for a period ending September 30, 2000, whereby 350 barrels per day of oil is sold forward at a price of $30.60 per barrel. (d) Credit risk management Accounts receivable include amounts receivable from oil and gas sales. These sales are generally made to large, credit worthy purchasers. The Company views the credit risks on these items as low. Amounts receivable from royalty payers and joint venture partners are secured by production or debentures and, accordingly, the Company views credit risks as minimal. (e) Fair values of financial instruments Accounts receivable, accounts payable, and accrued liabilities have carrying values that approximate fair value due to the near term maturity of these financial instruments. Portfolio investments are carried at cost, and their quoted market value at year-end is disclosed. Long-term debt, all of which is subject to floating interest rates, has a carrying value that approximates fair value. 7. GAS DELIVERY CONTRACTS At December 31, 1999 subsidiaries of the Company have contracts to deliver natural gas in excess of current natural gas production of approximately 9,500 GJ's per day. These contracts have expiry dates from October 2000 to October 2007. With respect to the delivery of natural gas, the Company contracted in December 1999 to buy 4,000 GJ's per day from January to October 2000 for the filling of a fixed price contract which expires October 31, 2000. The difference between the fixed sales price and the contracted supply price has been recorded as a current liability at December 31, 1999 of $1,573,800. This liability will be settled monthly from January to October 2000. The remaining 5,500 GJ's per day of contracted volume in excess of current natural gas production relates to a contract to deliver natural gas into the Northeastern U.S. At C-14 RESERVE ROYALTY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS YEARS ENDED DECEMBER 31, 1999 AND 1998 December 31, 1999 it was estimated that $419,354 would have been received by the Company to terminate the natural gas delivery contract. At December 31, 1998 subsidiaries of the Company had contracts to deliver natural gas in excess of current natural gas production of approximately 22,800 GJ's per day. These contracts have expiry dates from October 2000 to October 2007. At December 31, 1998 it was estimated that a net payment by the Company of $10.5 million would have been required to terminate excess natural gas delivery contracts. The expected settlement amount for these contracts had been recognized in the ceiling test evaluation of petroleum and natural gas properties as a reduction. The excess gas delivery contracts are principally related to the delivery of natural gas into the Northeastern U.S. and are priced based on those markets on a month to month basis. The natural gas required to fill these excess delivery contracts is purchased based on the Alberta market. The net differential in pricing between the Northeastern U.S. markets and the Alberta market generates a gas marketing gain or loss. The Company reported a loss of $4,639,914 for 1999, including the loss relating to the gas supply contract for the fixed price sales contract which expires at the end of October 2000, and a gain of $890,889 for 1998 related to this activity. C-15 RESERVE ROYALTY CORPORATION CONSOLIDATED BALANCE SHEET (UNAUDITED) ------------------------------------------------------------------------------ (THOUSANDS) JUNE 30, 2000 ------------------------------------------------------------------------------ ASSETS Current Marketable securities $ 3 Accounts receivable 4,194 Inventory, prepaid expenses and deposits 527 ------------------------------------------------------------------------------ 4,724 Petroleum and natural gas properties 103,680 ------------------------------------------------------------------------------ $ 108,404 ------------------------------------------------------------------------------ LIABILITIES AND SHAREHOLDERS' EQUITY Current Bank indebtedness $ 195 Accounts payable and accrued liabilities 3,100 ------------------------------------------------------------------------------ 3,295 Long-term debt 27,030 Future site restoration provision 399 Future income taxes 12,360 ------------------------------------------------------------------------------ 43,084 Shareholders' equity Share capital (102,459,000 shares outstanding) 212,656 Deficit (147,336) ------------------------------------------------------------------------------ 65,320 ------------------------------------------------------------------------------ $ 108,404 ============================================================================== See accompanying notes to Consolidated Financial Statements. C-16 RESERVE ROYALTY CORPORATION CONSOLIDATED STATEMENTS OF OPERATIONS AND DEFICIT (UNAUDITED) For the Six Months Ended June 30 -------------------------------------------------------------------------------- (thousands, except per share amounts) 2000 1999 -------------------------------------------------------------------------------- Resource revenue $ 9,786 $ 12,133 Other income (loss) Gas marketing gain (loss) (533) (1,554) Interest and other income 52 13 Commodity and exchange hedging losses (731) (281) -------------------------------------------------------------------------------- 8,574 10,311 Expenses Administration (2,545) (1,910) Interest and financing (1,255) (2,713) Production (636) (1,793) Royalties (189) (223) Depletion, depreciation and amortization (5,563) (6,820) -------------------------------------------------------------------------------- (10,188) (13,459) -------------------------------------------------------------------------------- Loss before income taxes (1,614) (3,148) Provision for income taxes Current expense (38) (186) Future recovery (Note 1) 556 -------------------------------------------------------------------------------- 518 (186) -------------------------------------------------------------------------------- Loss for the period (1,096) (3,334) Change in accounting policy (Note 1) (12,916) Deficit, beginning of period (133,324) (98,885) -------------------------------------------------------------------------------- Deficit, end of period $ (147,336) $ (102,219) -------------------------------------------------------------------------------- Loss per common share $ (0.01) $ (0.03) -------------------------------------------------------------------------------- Weighted average number of common shares outstanding 102,379 102,252 -------------------------------------------------------------------------------- See accompanying notes to Consolidated Financial Statements. C-17 RESERVE ROYALTY CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
For the Six Months Ended June 30 ------------------------------------------------------------------------------------------------ (thousands, except per share amounts) 2000 1999 ------------------------------------------------------------------------------------------------ Net inflow (outflow) of cash related to the following activities: OPERATIONS Loss for the period $ (1,096) $ (3,334) Items not affecting cash: Depletion, depreciation and amortization 5,563 6,820 Future income taxes (556) ------------------------------------------------------------------------------------------------ Funds from operations 3,911 3,486 Net change in non-cash working capital items (3,208) 3,547 ------------------------------------------------------------------------------------------------ Cash provided by operating activities 703 7,033 ------------------------------------------------------------------------------------------------ FINANCING Long-term debt (8,025) (54,969) Issuance of share capital 98 Payment on hedging contracts assumed on acquisition (1,710) ------------------------------------------------------------------------------------------------ Cash provided by financing activities (7,927) (56,679) ------------------------------------------------------------------------------------------------ INVESTMENTS Petroleum and natural gas properties (680) (2,196) Proceeds on disposal of petroleum & natural gas properties 7,434 51,849 ------------------------------------------------------------------------------------------------ Cash used in investing activities 6,754 49,653 ------------------------------------------------------------------------------------------------ Increase (decrease) in cash during the period (470) 7 Cash, beginning of period 275 200 ------------------------------------------------------------------------------------------------ Cash (bank indebtedness), end of period $ (195) $ 207 ------------------------------------------------------------------------------------------------ Funds from operations per common share: Basic $ 0.04 $ 0.03 Fully diluted $ 0.04 $ 0.03 ------------------------------------------------------------------------------------------------
See accompanying notes to Consolidated Financial Statements. C-18 RESERVE ROYALTY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS SIX MONTHS ENDED JUNE 30, 2000 AND 1999 (UNAUDITED) 1. CHANGE IN ACCOUNTING POLICY In the first quarter of 2000, the Company changed its policy on accounting for income taxes. Effective January 1, 2000, the liability method was adopted; prior thereto, the Company followed the deferral method. The new method was applied retroactively without restatement of prior period financial statements. At January 1, 2000, a future income tax liability was recorded for $12,916,000 and retained earnings was decreased by $12,916,000. These adjustments were a result of the future tax cost recognition where the tax base of acquired companies was less than the acquisition cost. The effect of adopting the policy on the six month period ended June 30, 2000 was to increase net income by $416,400 to recognize the decrease in income tax rates during the period and the recovery of future income taxes from the utilization of current period losses. 2. SUBSEQUENT EVENT On July 27, 2000, the Company was amalgamated with its subsidiary companies and continued under the name Reserve Royalty Corporation. Immediately following this amalgamation, approximately 97 percent of the outstanding common shares of the Company were acquired by PrimeWest Royalty Corp. by way of a takeover bid circular. The remaining shares of the Company were acquired by way of a compulsory acquisition pursuant to the BUSINESS CORPORATIONS ACT (Alberta). Subsequent to this transaction, the Company was amalgamated with PrimeWest Royalty Corp. and continued under the name PrimeWest Royalty Corp. C-19