U.S. SECURITIES AND EXCHANGE
COMMISSION
WASHINGTON, D.C. 20549
FORM 40-F
[_] REGISTRATION STATEMENT PURSUANT TO SECTION 12 OF THE THE
SECURITIES EXCHANGE ACT OF 1934
[X] ANNUAL REPORT PURSUANT TO SECTION 13(a) OR 15(d) OF THE THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2002
Commission File Number: 333-13238
PRIMEWEST ENERGY TRUST
(Exact name of Registrant as specified in its charter)
CANADA 1311 N/A
(Province or Other (Primary Standard (I.R.S. Employer
Jurisdiction of Industrial Classification Identification No.)
Incorporation or Organization) Code Number)
Suite 4700
150 Sixth Avenue, S.W.
Calgary, Alberta, Canada T2P 3Y7
(403) 234-6600
(Address and Telephone Number of Registrant's Principal Executive Offices)
CT Corporation System
111 Eighth Avenue, New York, New York 10011
(212) 894-8940
(Name, Address Including Zip Code, and Telephone Number
Including Area Codes of Agent for Service)
Securities registered or to be registered pursuant to Section 12(b) of the Act
TITLE OF EACH CLASS NAME OF EACH EXCHANGE ON WHICH REGISTERED
------------------- -----------------------------------------
Trust Units, without nominal or par value New York Stock Exchange
Securities registered or to be registered pursuant to Section 12(g) of the Act
None.
Securities for which there is a reporting obligation pursuant to Section 15(d)
of the Act
None.
For annual reports, indicate by check mark the information filed with this Form:
[X] Annual information form [X] Audited annual financial statements
Indicate the number of outstanding shares of each of the issuer's classes of
capital or common stock as of the close of the period covered by the annual
report:
38,944,386 Trust Units
Indicate by check mark whether the Registrant by filing the information
contained in this Form is also thereby furnishing the information to the
Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934
(the "Exchange Act"). If "Yes" is marked, indicate the filing number assigned to
the Registrant in connection with such Rule.
Yes [_] No [X]
Indicate by check mark whether the Registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Exchange Act during the preceding 12
months (or for such shorter period that the Registrant was required to file such
reports) and (2) has been subject to such filing requirements for the past 90
days.
Yes [X] No [_]
2
DOCUMENTS INCLUDED IN THIS FORM
The following documents are included in the Form:
NO. DOCUMENT
--- --------
1 Annual Information Form of the Registrant for the year ended
December 31, 2002.
2 Consolidated Financial Statements of the Registrant for the
fiscal year ended December 31, 2002 including a reconciliation
to US GAAP.
3 Management's Discussion and Analysis of the Registrant for the
fiscal year ended December 31, 2002
3
CONTROLS AND PROCEDURES
Within the 90-day period prior to the filing of this report, an
evaluation was carried out under the supervision of and with the participation
of the Registrants' management, including the Chief Executive Officer and Chief
Financial Officer, of the effectiveness of the Registrants' disclosure controls
and procedures (as defined in Rule 13a-14(c) under the Exchange Act). Based on
that evaluation, the Chief Executive Officer and Chief Financial Officer
concluded that the design and operation of these disclosure controls and
procedures were effective. No significant changes were made in the Registrants'
internal controls or in other factors that could significantly affect these
controls subsequent to the date of their evaluation, including any corrective
actions with regard to significant deficiencies and material weaknesses.
UNDERTAKING
The Registrant undertakes to make available, in person or by telephone,
representatives to respond to inquiries made by the Commission staff, and to
furnish promptly, when requested to do so by the Commission staff, information
relating to: the securities registered pursuant to Form 40-F; the securities in
relation to which the obligation to file an annual report on Form 40-F arises;
or transactions in said securities.
CONSENT TO SERVICE OF PROCESS
The Registrant has previously filed with the Commission a Form F-X in
connection with the Trust Units.
EXHIBIT INDEX
The following exhibits are filed as part of this report.
EXHIBIT
NUMBER DESCRIPTION
------ -----------
23.1 Consent of PricewaterhouseCoopers LLP
23.2 Consent of Ernst & Young LLP
23.3 Consent of Gilbert Lausten Jung Associates Ltd.
99.1 CEO Certification pursuant to U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.2 CFO Certification pursuant to U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.3 Summary of US federal income tax considerations
4
SIGNATURE
Pursuant to the requirements of the Exchange Act, the Registrant
certifies that it meets all of the requirements for filing on Form 40-F and has
duly caused this Registration Statement on Form 40-F to be signed on its behalf
by the undersigned, thereto duly authorized.
Dated: March 26, 2003
PRIMEWEST ENERGY TRUST
By: /s/ Dennis G. Feuchuk
---------------------------------------
Name: Dennis G. Feuchuk
Title: Vice President, Finance and
Chief Financial Officer
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CEO CERTIFICATION
I, Donald A. Garner, certify that:
1. I have reviewed this annual report on Form 40-F of PrimeWest Energy Trust;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have;
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities,
particularly during the period in which this annual report is being
prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing of this annual
report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness
of the disclosure controls and procedures based on our evaluation as of the
Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (and persons performing the
equivalent function);
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to record,
process, summarize and report financial data and have identified for the
registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6
c) the Registrant's other certifying officers and I have indicated in this
annual report whether there were significant changes in internal controls
or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any
corrective actions with regard to significant deficiencies and material
weaknesses.
Date: March 26, 2003
/s/ Donald A. Garner
- -----------------------------
Name: Donald A. Garner
Title: President and Chief Executive Officer
7
CFO CERTIFICATION
I, Dennis G. Feuchuk, certify that:
1. I have reviewed this annual report on Form 40-F of PrimeWest Energy Trust;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have;
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities,
particularly during the period in which this annual report is being
prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing of this annual
report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness
of the disclosure controls and procedures based on our evaluation as of the
Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (and persons performing the
equivalent function);
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to record,
process, summarize and report financial data and have identified for the
registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
8
c) the Registrant's other certifying officers and I have indicated in this
annual report whether there were significant changes in internal controls
or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any
corrective actions with regard to significant deficiencies and material
weaknesses.
Date: March 26, 2003
/s/ Dennis G. Feuchuk
- -----------------------------
Name: Dennis G. Feuchuk
Title: Vice President, Finance and Chief Financial Officer
9
EXHIBIT INDEX
EXHIBIT
NUMBER DESCRIPTION
------ -----------
23.1 Consent of PricewaterhouseCoopers LLP
23.2 Consent of Ernst & Young LLP
23.3 Consent of Gilbert Lausten Jung Associates Ltd.
99.1 CEO Certification pursuant to U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.2 CFO Certification pursuant to U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.3 Summary of US federal income tax considerations
DOCUMENT 1
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PRIMEWEST ENERGY TRUST
RENEWAL ANNUAL INFORMATION FORM
FOR THE YEAR ENDED DECEMBER 31, 2002
MARCH 14, 2003
TABLE OF CONTENTS
ITEM 1: ORGANIZATION..........................................................1
Trust Structure...........................................................2
The Declaration of Trust..................................................2
Unitholder Rights Plan....................................................6
Internalization of Management.............................................7
Decision Making...........................................................8
ITEM 2: GENERAL DEVELOPMENT OF THE BUSINESS...................................8
Developments Since Year-End..............................................10
ITEM 3: NARRATIVE DESCRIPTION OF BUSINESS....................................10
The Business of the Trust.....................................................10
General..................................................................10
Operatorship.............................................................11
Acquisitions.............................................................11
Risk Management & Marketing..............................................11
Reserve Continuity.......................................................14
Drilling Activity........................................................14
Capital Expenditures.....................................................15
Exploration and Development..............................................15
Attributes of the Properties.............................................16
Oil and Natural Gas Reserves.............................................16
Principal Properties..........................................................21
Unproved Lands................................................................29
Industry Conditions...........................................................30
Risks Related to Our Business.................................................32
Risks Related to the Trust Structure and the Ownership of Trust Units.........40
ITEM 4: SELECTED CONSOLIDATED FINANCIAL INFORMATION..........................44
Selected Annual Information...................................................44
Selected Quarterly Information................................................44
Selected Financial and Operational Information................................45
ITEM 5: MANAGEMENT'S DISCUSSION AND ANALYSIS.................................46
ITEM 6: MARKET FOR SECURITIES................................................46
ITEM 7: DIRECTORS AND OFFICERS...............................................47
Directors................................................................47
Officers.................................................................48
Employees................................................................49
ITEM 8: ADDITIONAL INFORMATION...............................................49
GLOSSARY OF ABBREVIATIONS & TERMS.............................................50
Abbreviations............................................................50
Definitions..............................................................51
SCHEDULE A FINANCIAL STATEMENTS OF CYPRESS ENERGY INC.
NOTE TO READER
--------------
The Trust Units were consolidated on a one for four basis on
August 16, 2002. Except where otherwise indicated, all
amounts relating to the Trust Units contained in this Annual
Information Form have been adjusted to give effect to that
consolidation.
ITEM 1: ORGANIZATION
PrimeWest Energy Trust (the "TRUST") is an open-end investment trust
created under the laws of Alberta pursuant to the Declaration of Trust. 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. Computershare Trust Company of Canada is the Trustee of the
Trust. The head office and principal place of business of the Trust is 4700, 150
- - 6th Avenue S.W., Calgary, Alberta, T2P 3Y7.
PrimeWest Energy Inc. ("PRIMEWEST" or the "OPERATING COMPANY") was
incorporated under the BUSINESS CORPORATIONS ACT (Alberta) on March 4, 1996 and
was amalgamated with PrimeWest Oil and Gas Corp., PrimeWest Royalty Corp. and
PrimeWest Resources Ltd. on January 1, 2002 and continued as PrimeWest Energy
Inc. PrimeWest was amalgamated with PrimeWest Management Inc. (the "MANAGER")
and Delgrae Energy Corporation on November 6, 2002 and continued as PrimeWest
Energy Inc. The latter amalgamation was completed as part of the
"internalization" of the Manager referred to under "Internalization of
Management" below.
PrimeWest is wholly owned by the Trust. PrimeWest's business is the
acquisition, development, exploitation, production and marketing of petroleum
and natural gas properties and granting the Royalty to the 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 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 balance of
such net cash flow may be retained by PrimeWest to fund its working capital and
other business and operating requirements, or may be passed on to the Trust to
support distributions to Unitholders. The Distributable Income resulting from
the Royalty and other amounts received by the Trust is then distributed monthly
to Unitholders.
The head, principal and registered office of PrimeWest is 4700, 150 -
6th Avenue S.W., Calgary, Alberta T2P 3Y7.
TRUST STRUCTURE
The following diagram represents the current structure of the Trust and
shows the flow of funds from the petroleum and natural gas properties owned by
PrimeWest and the gross overriding royalties owned directly by the Trust, as
well as the flow of funds to PrimeWest, and from the Trust to Unitholders:
[GRAPHIC OMITTED]
[CHART]
---------------------------------
Unitholders
---------------------------------
Monthly distributions
---------------------------------
PrimeWest Energy Trust
---------------------------------
Royalty
Debt Service
Dividends
---------------------------------
PrimeWest Energy Inc.
and its subsidiaries
(oil & gas properties actively
managed to maximize cash flow and
reserve value)
---------------------------------
NOTE:
1. The Trust also directly owns certain gross overriding royalty
interests.
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.
2
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, 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.
CLASS A EXCHANGEABLE SHARES OF PRIMEWEST
An unlimited number of Class A Exchangeable Shares may be issued by the
Operating Company, each of which entitles the holder to exchange the Class A
Exchangeable Share at any time into a number of Trust Units based on an exchange
ratio then in effect. The exchange ratio is determined by reference to the
distributions paid on Trust Units in a given month and the current market price
of the trust units. On December 31, 2002, each Class A Exchangeable Share was
exchangeable for 0.37454 Trust Units.
PrimeWest issued Class A Exchangeable Shares in connection with the
acquisitions of the Manager in November 2002, Cypress Energy Inc. in March 2001
and Venator Petroleum Company Ltd. in April 2000. Shareholders of the Manager,
Cypress and Venator who received Class A Exchangeable Shares could in certain
circumstances defer the tax consequences of that exchange. PrimeWest may issue
additional Class A Exchangeable Shares in connection with future acquisitions.
The Class A Exchangeable Shares provide holders with economic terms and
voting rights which are, as nearly as practicable, equivalent to those of Trust
Units. The Class A Exchangeable Shares are maintained economically equivalent to
the Trust Units by the progressive increase in the exchange ratio, incorporating
and reflecting the distributions provided to Unitholders in the right to acquire
an ever-increasing number of Trust Units per Class A Exchangeable Share. The
Class A Exchangeable Shares are provided equivalent voting rights as Unitholders
through a voting trust agreement pursuant to which the holders of Class A
Exchangeable Shares can direct a trustee to
3
vote at meetings of Unitholders. The Class A Exchangeable Shares are listed and
posted for trading on the TSX under the symbol "PWX".
TRUSTEE
Computershare is the current trustee of the Trust and also acts as the
transfer agent for the Trust Units and the Class A Exchangeable Shares. 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 expires at the conclusion
of the 2005 annual meeting of Unitholders. 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.
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.
4
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 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 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
5
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.
UNITHOLDER RIGHTS PLAN
On March 31, 1999, PrimeWest announced that it had adopted a Unitholder
Rights Plan. The Rights Plan was approved by Unitholders at the special and
annual general meeting of the Unitholders held on May 18, 1999. The Unitholders
reconfirmed the Rights Plan at the special and annual general meeting of the
Unitholders held on May 21, 2002. The Rights Plan will expire on the date of
PrimeWest's Annual general meeting in 2005 unless the Unitholders reconfirm the
Rights Plan at that meeting.
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 Unitholder value in the event of an unsolicited
take-over bid.
If a Person acquires more than 20 percent of the Trust Units other than
by way of a permitted bid, other Unitholders may, at the discretion of the board
of directors of PrimeWest, acquire a number of Trust 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 Unitholders;
6
(b) The bid must be open for a minimum of 45 days following the
date of the bid, and no Trust Units may be taken up prior to
such time;
(c) Take-up and payment of Trust Units may not occur unless the
bid is accepted by Unitholders holding more than 50 percent of
the outstanding Trust Units, excluding Trust Units held by the
bidder and its associates;
(d) Trust 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 Unitholders holding the requisite
percentage of Trust Units, the bidder must extend the bid for
an additional ten business days to permit other Unitholders to
tender into the bid, should they so wish.
INTERNALIZATION OF MANAGEMENT
On September 26, 2002, the Trust announced the planned elimination,
effective October 1, 2002, of its external management structure and all related
management, acquisition and disposition fees, as well as the acquisition of the
right to mandatory quarterly dividends commonly referred to as the "1% retained
royalty". The transaction was completed on November 6, 2002.
The transaction resulted in the elimination of a 2.5% management fee on
net production revenue, quarterly incentive payments payable in the form of
Trust Units, a 1.5% acquisition fee and a 1.25% disposition fee, which resulted
in payments to the Manager in 2001 totalling $21.3 million. In addition, the
amount of the 1% retained royalty paid in 2001 was $3.4 million.
The internalization transaction was achieved through the purchase by
PrimeWest of all of the issued and outstanding shares of the Manager for a total
consideration of approximately $26.3 million comprised of a cash payment of
$13.2 million and the issuance of Class A Exchangeable Shares exchangeable,
based on an agreed initial exchange ratio, for approximately 491,000 Trust Units
and valued at approximately $13.1 million based on the closing price of the
Trust Units on the TSX on September 26, 2002. In addition, PrimeWest agreed to
issue Class A Exchangeable Shares valued at $1.5 million to certain senior
managers other than Kent J. MacIntyre (then the Chief Executive Officer of
PrimeWest and the Manager) to terminate a management incentive program of the
Manager and created a special executive retention plan for those senior managers
which provides for long term incentive bonuses in the form of Class A
Exchangeable Shares valued, in the aggregate, at $3.5 million. Class A
Exchangeable Shares will be issued pursuant to the retention plan on each of the
second, third, fourth and fifth anniversaries of the completion of the
internalization transaction. The cash component of the purchase price for the
shares of the Manager was funded using PrimeWest's then existing credit
facility.
7
The total consideration payable for the shares of the Manager, in the
opinion of the independent directors of PrimeWest, represented a reasonable
payment (i) in lieu of fees that would have been payable by PrimeWest to the
Manager during the remainder of the initial term of the management agreement
among the Trust, PrimeWest and the Manager to October 15, 2003, including
management fees, quarterly incentive payments and acquisition and disposition
fees, (ii) for the shares of PrimeWest held by the Manager, the holder of which
shares is entitled to approximately 1% of net production revenue for the
remaining life of the oil and natural gas reserves of PrimeWest, and (iii) for
the benefits accruing to Unitholders through continuity of management.
The internalization transaction included the continued commitment of
the senior management team at PrimeWest.
DECISION MAKING
Unitholders are entitled to direct the election of directors of
PrimeWest, the approval of the financial statements of PrimeWest, and the
appointment of its auditors and other matters relating to the business and
affairs of PrimeWest and the Trust.
The board of directors of PrimeWest is responsible for making
significant decisions with respect to PrimeWest, including all decisions
relating to, among other things: (a) the acquisition and disposition of
significant petroleum and natural gas properties; (b) the approval of capital
expenditure budgets; (c) the approval of risk management activities; 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 or the royalty agreement
and other aspects respecting the relationship between the Trust and PrimeWest,
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 (before giving effect to the Consolidation) 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 to acquire certain oil and gas properties.
Since its inception, PrimeWest has been an active acquiror of crude oil
and natural gas properties in the Western Canadian Sedimentary Basin. Many of
those
8
acquisitions were financed, directly or indirectly, through the issuance of
Trust Units and what are now Class A Exchangeable Shares. The following tables
summarize the more significant acquisitions and equity financings completed by
PrimeWest since January 1, 2000.
ACQUISITIONS
COMPANY/PROPERTIES AGGREGATE PURCHASE ESTABLISHED RESERVES AND
DATE ACQUIRED PRICE (CURRENCY) PRODUCTION ACQUIRED
---- -------- ---------------- -------------------
April 2000 Venator Petroleum Company Ltd. $32.5 million (cash and 3.0 mmboe
exchangeable shares) 1,500 boe/d
July 2000 Reserve Royalty Corp. $84.0 million (cash and Trust 6.1 mmboe
Units) 1,700 boe/d
March 2001 Cypress Energy Inc. $820.8 million (cash, Trust 57.5 mmboe
Units and exchangeable shares) 15,000 boe/d
December 2002 Caroline/Ells $45.6 million (cash) 5.7 mmboe
1,550 boe/d
January 2003 Caroline/Peace $206.1 million (cash) 17.6 mmboe
River Arch 6,800 boe/d
PUBLIC OFFERINGS
NO. OF TRUST
DATE UNITS ISSUED PRICE PER TRUST UNIT GROSS PROCEEDS
---- ------------ -------------------- --------------
September 2000 1,207,500(1) $33.40(1) $40.3 million
June 2001 2,472,500(1) 38.40(1) 94.9 million
November 2001 2,475,000(1) 28.40(1) 70.3 million
November 2002 4,200,000 26.20 110.0 million
February 2003 6,000,000 25.75 154.5 million
NOTE:
1. Adjusted to give effect to the Consolidation completed on August 16, 2002.
Other significant developments since January 1, 2000 include the
following:
o In the second half of 2001, in a number of separate transactions,
PrimeWest disposed of several properties for total proceeds of
approximately $78.2 million. These proceeds were applied to reduce
outstanding debt.
9
o On November 19, 2002, the Trust Units were listed for trading on the
New York Stock Exchange under the symbol "PWI".
o On December 23, 2002, the Board of Directors of PrimeWest confirmed the
succession of Donald A. Garner to the position of President and Chief
Executive Officer, effective January 2, 2003. Kent MacIntyre, the
founder of PrimeWest, resigned as Vice-chairman and Chief Executive
Officer of PrimeWest effective January 2, 2003, but will remain a
member of the Board of Directors of PrimeWest. The Board also appointed
Tim Granger, PrimeWest's Vice-president, Operations and Development, as
Chief Operating Officer.
DEVELOPMENTS SINCE YEAR-END
On January 8, 2003, PrimeWest announced the appointment of W. Glen
Russell as an independent member of the Board of Directors.
On January 23, 2003, a wholly owned subsidiary of PrimeWest acquired
all of the issued and outstanding shares of two private Canadian exploration and
production companies for an aggregate purchase price of $206.1 million, net of
adjustments (including working capital), payable in cash. Of the purchase price,
$191.1 million is attributed by PrimeWest to oil and gas reserves and $15
million is attributed by PrimeWest to certain natural gas processing and
midstream assets. The transaction added approximately 17.6 mmboe of Established
Reserves, as at July 1, 2002, and approximately 6,800 boe per day of current
production. That production is weighted 83% to natural gas and the properties
are located primarily in the Caroline and Peace River Arch areas of Alberta.
On February 13, 2003, the Trust closed the issue of 6 million Trust
Units at a price of $25.75 per Trust Unit. The issue was done on a bought-deal
basis for gross proceeds of $154.5 million.
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 to continue to source and acquire petroleum and natural gas properties
both for and on behalf of itself 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.
10
OPERATORSHIP
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.
Currently, PrimeWest operates properties representing approximately 80%
of the aggregate daily production.
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 continually decline.
PrimeWest 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, PrimeWest 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".
RISK MANAGEMENT & MARKETING
Prices received for production and associated operating expenses are
impacted in varying degrees by factors outside the Trust's control. These
include but are not limited to:
(a) World market forces, including the ability of OPEC to set and
maintain production levels and prices for crude oil;
(b) Potential conditions, including the risk of hostilities in the
Middle East;
(c) Increases or decreases in crude-oil quality differentials, and
their implications for prices received by PrimeWest on the
portion of oil production that is medium gravity crude;
(d) To the extent that crude oil 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.
(e) 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;
11
(f) Global and domestic economic and weather conditions;
(g) Price and availability of alternative fuels; and
(h) The effect of energy conservation measures and government
regulations.
Fluctuations in commodity prices, quality differentials and foreign
exchange and interest rates, among other factors, 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 these risks, 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 of directors of PrimeWest.
As part of PrimeWest's risk-management strategy in 2002, 69% of
full-year crude oil production (2001 - 84%) and 71% of full-year natural gas
production (2001 - 78%) was hedged, net of royalties. Strategies utilized
included both physical and financial instruments with the primary objective of
enhancing the stability of cash distributions. No electrical power requirements
were hedged in 2002.
The gas hedging instruments are floors, swaps, costless collars, 3-way
deals and swaptions. Costless collars involve the simultaneous purchase of a put
option and sale of a call option at no cost. 3-way deals are the simultaneous
purchase of a near the money put option and the sale of both an out of the money
put and an out of the money call all at no cost. Swaptions give PrimeWest the
future right to enter into swap transactions for fixed prices and terms. The oil
hedging instruments consist of floors, swaps, costless collars and calls.
As at February 28, 2003:
(a) PrimeWest employed hedging structures using swaps and
option-based instruments on approximately 51% of anticipated
crude oil production, net of royalties, for 2003 and on none
of its anticipated crude oil production, net of royalties, for
2004;
(b) PrimeWest employed hedging structures using swaps and
option-based instruments on approximately 57% of anticipated
natural gas production, net of royalties, for 2003 and on
approximately 12% of anticipated natural gas production, net
of royalties, for 2004;
(c) PrimeWest employed hedging structures using heat rate
instruments (involving the exchange of natural gas production
for electrical power) on approximately 42% of anticipated
electrical power requirements for 2003 and on approximately
28% of anticipated electrical power requirements for 2004; and
12
(d) all 2003 and 2004 hedging contracts mark-to-market represented
a net loss of $54.5 million, as compared to a net loss of
$13.6 million as at December 31, 2002.
Beyond the hedging strategy, PrimeWest also mitigates risk by having a
well diversified marketing portfolio for natural gas and by transacting with a
number of counterparties to limit exposure to any one counterparty.
Approximately 30% of natural gas production is sold to aggregators and
approximately 70% 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, while PrimeWest's
portfolio of assets is weighted to natural gas, a significant portion of the
portfolio consists of crude oil and NGLs reserves. Because oil and gas price
cycles do not necessarily coincide, such a balance often provides a natural
mitigation of price risk.
For 2002, PrimeWest's commodity mix was approximately 38% oil and NGLs
and 62% natural gas, compared to approximately 41% oil and NGLs and 59% natural
gas in 2001. PrimeWest realized hedge gains of $28 million in 2002 and $39
million in 2001.
IMPACT OF ENVIRONMENTAL PROTECTION REQUIREMENTS
PrimeWest carries out its activities and operations in compliance with
all relevant and applicable environmental regulations and good industry
practice. At present, PrimeWest believes that it meets all existing
environmental standards and regulations. PrimeWest has created a segregated fund
devoted to funding future costs for well abandonment and site cleanup. In 2002,
PrimeWest contributed $0.37 per boe of production, totalling $4.1 million paid
into this fund, while $3.9 million was paid out for active projects completed,
leaving a balance of $0.01 million at the end of the year. The 2003 contribution
rate has been set at $0.50 per boe, which is expected to be sufficient to meet
the future funding requirements. In addition, PrimeWest records a provision for
site reclamation and abandonment based on cost estimates made by both PrimeWest
and external engineers. The provision for 2002 was $4.0 million compared to $3.5
million in 2001 and is charged to depletion, depreciation and amorization on a
unit of production basis. Expenditures for environmental matters or site
restoration are not reported as part of the development capital. Since the
environmental standards and regulations to which PrimeWest is subject apply to
all participants in the oil and gas industry, it is not anticipated that
PrimeWest's competitive position within the industry will be adversely affected.
13
RESERVE CONTINUITY
Gilbert Laustsen Jung Associates Ltd., independent petroleum
consultants, has evaluated the crude oil, natural gas, natural gas liquids and
sulphur reserves of PrimeWest and the Trust since their inception in 1996.
Gilbert Laustsen Jung Associates Ltd. has prepared the Gilbert Report evaluating
the crude oil, natural gas, natural gas liquids and sulphur reserves
attributable to properties owned by PrimeWest and the Trust as at January 1,
2003. The following table sets forth the reconciliation of the reserves of
PrimeWest and the Trust for the year ended December 31, 2002, using escalated
price and cost estimates derived from the Gilbert Report.
ESTABLISHED
CRUDE OIL NATURAL GAS NGLS TOTAL RESERVES
(mbbls) (mmcf) (mmbls) (mboe) (mboe)
------------------- ------------------- ------------------- ------------------ -----
PROVED PROBABLE(1) PROVED PROBABLE(1) PROVED PROBABLE(1) PROVED PROBABLE(1)
------ ----------- ------ ----------- ------ ----------- ------------------
As at January 1, 2002 24,719 7,651 349,310 128,800 7,830 3,432 90,767 32,551 107,043
Additions,
Extensions 129 (16) 27,035 810 106 33 1,047 153 1,123
Discoveries 53 120 4,875 23,190 690 642 5,249 4,627 7,562
Acquisitions 373 128 23,840 4,940 862 125 5,208 1,075 5,746
Divestments (512) (242) (6,710) (2,180) (158) (55) (1,789) (660) (2,119)
Revision 27 (1,554) (7,440) (17,560) (138) (697) (1,351) (5,177) (3,940)
2002 Production (3,372) (41,440) (741) (11,020) (11,020)
------ ------ ------- ------- ----- ----- ------- ------ -------
As at January 1, 2003 21,417 6,087 349,470 138,000 8,451 3,480 88,111 32,569 104,395
====== ====== ======= ======= ===== ===== ====== ====== =======
NOTES:
1. No discount factor has been applied to the Probable Reserves to account for
the risk associated with the probability of obtaining production from such
reserves.
2. Established Reserves are the sum of Proved Reserves and 50 percent of
Probable Reserves.
3. All technical revisions on acquired reserves are included in revisions
category.
DRILLING ACTIVITY
During the Trust's last two financial years, PrimeWest drilled or
participated in the drilling of the following wells:
YEAR ENDED YEAR ENDED
DECEMBER 31, 2002 DECEMBER 31, 2001
--------------------------------- ------------------------------------
Gross Net Gross Net
------------- --------------- -------------- ---------------
Natural Gas 55 33.8 45 22.49
Crude Oil 1 0.3 30 24.06
Dry 9 6.5 7 4.50
------------- --------------- -------------- ---------------
Total 65 40.6 82 51.05
============= =============== ============== ===============
14
CAPITAL EXPENDITURES
The ongoing capital expenditures of PrimeWest are financed through the
issuance of additional Trust Units, bank borrowing and undistributed net cash
flow. The following table summarizes PrimeWest's capital expenditures in the
categories and for the periods indicated.
2002
--------------------------------------------------------
($ 000'S) FIRST SECOND THIRD FOURTH TOTAL FOR
QUARTER QUARTER QUARTER QUARTER YEAR
------- ------- ------- ------- ----
Development drilling and completions $15,337 $207 $12,052 $14,369 $41,965
Plant and facilities 8,002 6,329 3,377 3,474 21,182
Office and other expenditures 1,128 1,187 1,337 2,256 5,908
-------- -------- -------- -------- --------
24,467 7,723 16,766 20,099 69,055
Acquisitions 291 1,089 25,062 33,164 59,606
-------- -------- -------- -------- --------
Total capital expenditures 24,758 8,812 41,828 53,263 128,661
Property dispositions (2,066) (781) (873) (809) (4,529)
-------- -------- -------- -------- --------
Net capital expenditures $22,692 $8,031 $40,955 $52,454 $124,132
======== ======== ======== ======== ========
2001
--------------------------------------------------------
($ 000'S) FIRST SECOND THIRD FOURTH TOTAL FOR
QUARTER QUARTER QUARTER QUARTER YEAR
------- ------- ------- ------- ----
Development drilling and completions $5,748 $11,802 $18,194 $22,901 $58,645
Plant and facilities 449 4,330 6,414 10,609 21,802
Office and other expenditures 666 575 609 1,607 3,457
-------- -------- -------- -------- --------
6,863 16,707 25,217 35,117 83,904
Acquisitions 767,569 4,713 2,894 47,422 822,598
-------- -------- -------- -------- --------
Total capital expenditures 774,432 21,420 28,111 82,539 906,502
Property dispositions (3,333) (2,185) (23,447) (49,179) (78,144)
-------- -------- -------- -------- --------
Net capital expenditures $771,099 $19,235 $4,664 $33,360 $828,358
======== ======== ======== ======== ========
EXPLORATION AND DEVELOPMENT
The primary focus of PrimeWest is to pursue growth opportunities
through the development of existing reserves, the monetization of PrimeWest's
exploratory lands and the acquisition of new properties. High risk exploration
plays, as well as PrimeWest's undeveloped acreage, will continue to be farmed
out, sold, or exchanged for producing properties with upside potential.
Development efforts will be concentrated on optimizing production from existing
and new reserves, and developing new properties in a cost effective manner.
PrimeWest will continue its ongoing property rationalization program and any
sales proceeds may be used to acquire interests in core areas or new prospects
with exploitation opportunities.
15
ATTRIBUTES OF THE PROPERTIES
The properties of PrimeWest 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, 2002,
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 approximately 10 years;
(b) OPERATED PROPERTIES: Approximately 80% 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;
(c) NATURAL GAS WEIGHTED PORTFOLIO: For the year ended December
31, 2002 production from the properties is approximately 38
percent crude oil and natural gas liquids and 62 percent
natural gas, on a barrel-of-oil-equivalent basis. As at
January 1, 2003, Established Reserves for the properties are
approximately 34 percent crude oil and natural gas liquids and
66 percent natural gas on a barrel-of-oil-equivalent basis.
Crude oil reserves are predominantly light-gravity oil,
averaging 31 degree API;
(d) CONCENTRATED PORTFOLIO: While the properties are diversified
from a geological and geographic perspective, PrimeWest
generally has the largest working interest in these
properties; and
(e) 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
Gilbert has prepared the Gilbert Report evaluating the properties as at
January 1, 2003. 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.
16
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 ($MILLIONS)
----------------------------------------------------- ------------------------------------------
CRUDE OIL AND
NATURAL GAS NATURAL GAS SULPHUR
LIQUIDS (mmbbls) (bcf) (mlt) DISCOUNTED AT
----------------- ----------------- ----------------- ---------------------------
GROSS NET GROSS NET GROSS NET UNDISCOUNTED 10% 15% 20%
-------- ------- ------- -------- -------- -------- -------------- -------- ------- --------
Proved
Producing...... 26.9 22.9 287 228 588 492 1,254 705 595 521
Non-Producing.. 2.9 2.3 62 49 96 80 224 111 88 73
-------- ------- ------- -------- -------- -------- -------------- -------- ------- --------
Total Proved...... 29.8 25.2 349 277 684 572 1,478 816 683 594
Risked Probable... 4.9 3.9 69 55 128 108 297 107 79 61
-------- ------- ------- -------- -------- -------- -------------- -------- ------- --------
Established....... 34.7 29.1 418 332 812 680 1,775 923 762 655
======== ======= ======= ======== ======== ======== ============== ======== ======= ========
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 ($MILLIONS)
----------------------------------------------------- ------------------------------------------
CRUDE OIL AND
NATURAL GAS NATURAL GAS SULPHUR
LIQUIDS (mmbbls) (bcf) (mlt) DISCOUNTED AT
----------------- ----------------- ----------------- ---------------------------
GROSS NET GROSS NET GROSS NET UNDISCOUNTED 10% 15% 20%
-------- ------- ------- -------- -------- -------- -------------- -------- ------- --------
Proved
Producing...... 28.0 23.7 289 230 591 495 1,773 999 838 728
Non-Producing.. 2.8 2.3 63 49 96 80 302 156 125 103
-------- ------- ------- -------- -------- -------- -------------- -------- ------- --------
Total Proved...... 30.8 26.0 352 279 687 575 2,075 1,155 963 831
Risked Probable... 5.0 4.0 69 55 128 108 385 148 109 86
-------- ------- ------- -------- -------- -------- -------------- -------- ------- --------
Established....... 35.8 30.0 421 334 815 683 2,460 1,303 1,072 917
======== ======= ======= ======== ======== ======== ============== ======== ======= ========
NOTES:
1. 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.
(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.
2. 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.
17
3. All natural gas reserve values are reserves remaining after deducting
surface losses due to processing shrinkage and raw gas used as lease fuel.
4. The $US/$Cdn exchange rate is assumed in the Gilbert Report to be $0.6410
in 2003 and $0.6467 in 2004, $0.6500 in 2005, $0.6533 in 2006, and 0.6567
in 2007.
5. The Gilbert Report estimates total capital expenditures (net to PrimeWest)
to achieve the estimated future pre-tax net cash flows from the Established
Reserves based on escalating cost and price assumptions to be $95.1 million
($65.3 million if discounted by 12 percent per annum) with $21.6 million,
$23.5 million and $11.0 million of those capital expenditures estimated for
the calendar years 2003, 2004 and 2005 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 $92.7 million ($63.5 million if discounted by 12 percent per annum)
with $21.6 million, $23.1 million and $10.7 million of these capital
expenditures estimated for the calendar years 2003, 2004 and 2005
respectively.
6. The Gilbert Report estimates total capital expenditures (net to PrimeWest)
to achieve the estimated future pre-tax net cash flows from the Total
Proved Reserves based on escalating cost and price assumptions to be $76.6
million ($50.4 million if discounted by 12 percent per annum) with $15.5
million, $16.3 million and $7.9 million of those capital expenditures
estimated for the calendar years 2003, 2004 and 2005, respectively. The
corresponding capital expenditures to achieve the estimated future pre-tax
net cash flows from the Total Proved Reserves based on constant cost and
price assumptions are $73.4 million ($48.7 million if discounted by 12
percent per annum) with $15.5 million, $16.0 million and $7.7 million of
these capital expenditures estimated for the calendar years 2003, 2004 and
2005, respectively.
7. The extent and character of the interests of PrimeWest and the Trust
evaluated in the Gilbert Report and all factual data supplied to Gilbert
were accepted by Gilbert as represented. The crude oil and natural gas
reserve calculations and any projections on which the Gilbert Report is
based were determined in accordance with generally accepted petroleum
engineering evaluation practices.
8. The constant cost and price evaluation was based on December 31, 2002
reference prices. The prices shown below incorporate oil quality and
heating value adjustments, as well as transportation adjustments to a
property level:
AVERAGE FIRST YEAR UNIT VALUES (Cdn.$)
------------------------------ -------
Crude Oil.................................................$43.69 per bbl
Condensate................................................$48.00 per bbl
Propane...................................................$32.75 per bbl
Butane....................................................$35.56 per bbl
Ethane....................................................$18.40 per bbl
Natural Gas................................................$5.85 per mcf
Sulphur.....................................................$9.94 per lt
Operating and capital costs were not escalated in the constant cost and
price evaluation.
9. 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, 2003 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.
18
Consultant's Average (Escalated)
LIGHT CRUDE OIL NATURAL GAS LIQUIDS AT EDMONTON NATURAL GAS
------------------------ ------------------------------- -----------------------------------
ALBERTA
WTI EDMONTON SPOT
CUSHING PAR PRICE PENTANES HENRY HUB AECO-C BC DIRECT
OKLAHOMA* 40 Degree API PROPANE BUTANE PLUS $US/ $Cdn./ $Cdn./ SULPHUR
$US/bbl $/bbl $/bbl $/bbl $/bbl MMBTU MMBTU MMBTU $/lt
------- ----- ----- ----- ----- ----- ----- ----- ----
2003...... 25.83 38.84 23.46 25.90 39.49 4.22 5.61 5.46 7.75
2004...... 23.20 34.41 20.82 22.42 34.85 3.89 5.13 5.03 8.56
2005...... 21.84 32.14 19.85 21.04 32.57 3.61 4.76 4.66 9.40
2006...... 21.92 32.09 19.89 21.02 32.52 3.54 4.70 4.59 15.85
2007...... 22.28 32.53 20.10 21.29 32.97 3.60 4.76 4.65 19.21
2008...... 22.72 33.11 20.41 21.74 33.55 3.65 4.79 4.70 20.08
2009...... 23.09 33.89 20.96 22.28 34.35 3.71 4.89 4.79 20.95
2010...... 23.45 34.48 21.28 22.73 34.93 3.79 4.97 4.87 21.83
2011...... 23.82 35.06 21.63 23.15 35.52 3.85 5.05 4.95 22.95
2012...... 24.27 35.65 21.99 23.60 36.12 3.91 5.15 5.05 23.83
2013...... 24.64 36.28 22.43 24.06 36.75 3.97 5.23 5.13 24.71
2014...... 25.01 36.87 22.76 24.43 37.35 4.03 5.33 5.21 25.09
2015...... 25.39 37.47 23.11 24.77 37.95 4.09 5.42 5.29 25.47
2016...... 25.76 38.06 23.44 25.14 38.55 4.15 5.52 5.38 25.85
2017...... 26.17 38.69 23.80 25.52 39.18 4.22 5.62 5.48 26.24
2018...... 26.61 39.34 24.20 25.95 39.83 4.29 5.72 5.57 26.68
2019...... 27.05 39.99 24.60 26.38 40.50 4.36 5.82 5.66 27.12
Thereafter 1.00% 1.00% 1.00% 1.00% 1.00% 1.00% 1.00% 1.00% 1.00%
NOTES:
1. Operating and capital costs have been escalated at 1.67 percent annually
for 16 years and 1 percent thereafter.
2. Price forecasts used to generate the above price projections:
Gilbert Laustsen Jung Associates Ltd. - Effective January 1, 2003
Sproule Associates Limited - Effective January 1, 2003
McDaniel & Associates Consultants Ltd. - Effective January 1, 2003
19
ESTIMATED PRE-TAX NET CASH FLOWS
ESTABLISHED RESERVES OF THE PROPERTIES
ESCALATING COST AND PRICE CASE (CONSULTANT'S AVERAGE)
($millions except for production)
NET
REVENUE ALBERTA NET CASH
COMPANY AFTER ROYALTY NET FLOW BEFORE
ANNUAL INTEREST ROYALTY ROYALTY TAX OPERATING OTHER NET ABANDONMENT CAPITAL INCOME
PRODUCTION REVENUE(1) BURDENS(2) BURDENS CREDIT EXPENSES(3) INCOME(4) COSTS INVESTMENT TAXES(5)(6)
---------- ---------- ---------- ------- ------ ----------- --------- ----- ---------- -----------
(mboe) (MM$) (MM$) (MM$) (MM$) (MM$) (MM$) (MM$) (MM$) (MM$)
2003...... 10,862 358.1 74.3 283.7 0.5 57.2 4.2 3.3 21.6 206.5
2004...... 10,203 304.7 61.3 243.4 0.5 56.4 5.1 4.0 23.5 165.1
2005...... 9,074 251.3 48.6 202.8 0.5 53.1 5.1 4.0 11.0 140.3
2006...... 7,958 218.7 40.8 177.9 0.5 49.6 4.7 3.5 6.7 123.3
2007...... 6,942 193.3 34.9 158.4 0.5 46.7 4.4 3.7 4.1 108.8
2008...... 6,044 170.5 30.0 140.5 0.5 44.0 4.0 1.6 3.9 95.3
2009...... 5,267 152.2 26.1 126.1 0.5 40.6 3.6 2.3 2.2 85.0
2010...... 4,631 136.2 23.0 113.2 0.4 37.3 3.2 2.4 3.1 74.0
2011...... 4,036 121.1 20.1 101.0 0.4 33.4 2.9 1.2 3.2 66.4
2012...... 3,591 109.9 17.9 92.0 0.4 31.0 2.6 1.6 3.9 58.5
2013...... 3,223 100.4 16.1 84.2 0.4 28.7 2.5 1.3 2.9 54.3
2014...... 2,912 92.2 14.6 77.6 0.3 27.5 2.3 1.1 2.3 49.3
Remainder 29,652 1,085.6 156.7 928.8 2.5 370.5 18.8 24.6 6.5 548.4
------- ------- ----- ------- --- ----- ---- ---- ---- -------
TOTAL..... 104,395 3,294.0 564.5 2,729.5 7.9 876.0 63.3 54.7 95.1 1,775.0
======= ======= ===== ======= === ===== ==== ==== ==== =======
Total net cash flow before income taxes discounted at:
10 percent: $923 million
15 percent: $762 million
20 percent: $655 million
NOTES:
1. Includes working-interest revenue and royalty-interest revenue.
2. Includes royalties net of gas processing allowances.
3. Includes other expenses, capital taxes and certain third party processing
income.
4. Includes other income less net profits interest payments and mineral taxes.
5. Undiscounted.
6. Net cash flow before income taxes is stated prior to interest, general and
administrative expenses and management fees.
7. Columns may not add due to rounding.
20
ESTIMATED PRE-TAX NET CASH FLOWS
ESTABLISHED RESERVES OF THE PROPERTIES
CONSTANT COST AND PRICE CASE
($millions except for production)
NET
REVENUE ALBERTA NET CASH
COMPANY AFTER ROYALTY NET FLOW BEFORE
ANNUAL INTEREST ROYALTY ROYALTY TAX OPERATING OTHER NET ABANDONMENT CAPITAL INCOME
PRODUCTION REVENUE(1) BURDENS(2) BURDENS CREDIT EXPENSES(3) INCOME(4) COSTS INVESTMENT TAXES(5)(6)
---------- ---------- ---------- ------- ------ ----------- --------- ----- ---------- -----------
(mboe) ($) ($) ($) ($) ($) ($) ($) ($) ($)
2003...... 10,869 412.4 86.1 326.3 0.5 57.2 3.9 2.7 21.6 249.2
2004...... 10,233 388.0 79.7 308.4 0.5 56.0 4.4 3.4 23.1 230.8
2005...... 9,134 345.8 68.9 276.9 0.5 52.7 4.5 3.8 10.7 214.7
2006...... 8,014 303.1 58.3 244.8 0.5 48.7 4.3 3.4 6.3 191.1
2007...... 6,990 264.3 49.2 215.1 0.5 45.1 4.0 3.6 3.8 167.1
2008...... 6,087 230.3 41.6 188.7 0.5 41.8 3.6 1.5 3.6 145.9
2009...... 5,323 201.5 35.6 165.9 0.5 38.2 3.5 1.6 2.0 127.9
2010...... 4,690 177.5 30.8 146.7 0.5 34.8 3.0 1.6 2.8 111.0
2011...... 4,145 157.0 26.7 130.3 0.4 31.9 2.8 1.3 2.8 97.6
2012...... 3,677 139.3 23.3 115.9 0.4 29.0 2.6 1.5 3.4 85.0
2013...... 3,299 124.8 20.6 104.3 0.4 26.3 2.5 1.5 2.6 76.8
2014 2,969 112.4 18.3 94.1 0.4 24.5 2.2 0.9 2.0 69.3
Remainder.. 30,543 1,161.0 173.7 987.3 2.9 290.7 20.0 18.2 7.9 693.5
------- ------- ----- ------- --- ----- ---- ---- ---- -------
TOTAL..... 105,975 4,017.4 712.7 3,304.6 8.5 777.0 61.3 45.0 92.7 2,459.9
======= ======= ===== ======= === ===== ==== ==== ==== =======
Total net cash flow before income taxes discounted at:
10 percent: $1,303 million
15 percent: $1,072 million
20 percent: $917 million
NOTES:
1. Includes working-interest revenue and royalty-interest revenue.
2. Includes royalties net of gas processing allowances.
3. Includes other expenses, capital taxes and certain third party processing
income.
4. Includes other income less net profits interest payments and mineral taxes.
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.
PRINCIPAL PROPERTIES
The following is a description of the average daily production for the
year ending December 31, 2002 and reserves as of January 1, 2003 associated with
the significant properties owned by PrimeWest as of January 1, 2003. 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 PrimeWest in the properties.
21
DAILY PRODUCTION VOLUMES BY COMMODITY AND SIGNIFICANT PROPERTY
NATURAL GAS CRUDE OIL NATURAL GAS LIQUIDS TOTAL
(mcf/d) (bbls/d) (bbls/d) (boe/d)
- ----------------------------------------------------------------------------------------------
DAWSON
Dawson 17,841 1,082 -- 4,056
Stowe 11,813 287 -- 2,256
NORTHWEST
NW Alberta 661 -- -- 105
NE Alberta 847 -- -- 141
Laprise 8,468 -- 192 1,603
Boundary Lake 108 1,202 7 1,227
Kaybob 477 374 17 471
Grande Prairie 1,979 75 96 501
Meekwap 304 455 15 521
CENTRAL
Thunder 4,945 46 98 968
Thorsby 21,865 384 794 4,822
Crossfield / Lone Pine Creek 10,336 82 202 2,007
CAROLINE 5,878 208 275 1,463
SOUTHEAST
Brant Farrow 8,764 163 13 1,636
Dinosaur/ MedHat 4,944 1 -- 825
Grand Forks 2,206 2,999 38 3,404
Jumping Pound / Whiskey Creek 2,691 -- 107 555
Saskatchewan 468 562 3 643
Others 4,162 513 74 1,290
Royalties 4,743 806 99 1,695
- ----------------------------------------------------------------------------------------------
TOTAL 113,500 9,239 2,030 30,189
==============================================================================================
22
RESERVES BY COMMODITY AND SIGNIFICANT PROPERTY
PROVED PROBABLE(1) ESTABLISHED
----------------------------- ------------------------------ ------------------------------------
CRUDE NATURAL NATURAL CRUDE NATURAL
OIL GAS NGLS CRUDE OIL GAS NGLS OIL GAS NGLS TOTAL
PROPERTY (mbbls) (mmcf) (mbbls) (mbbls) (mmcf) (mbbls) (mbbls) (mmcf) (mbbls) (mboe)
------- ------ ------- ------- ------ ------- ------- ------ ------- ------
DAWSON
Dawson 808 17,800 -- 326 6,280 -- 971 20,940 -- 4,461
Stowe 717 21,761 -- 318 6,673 -- 876 25,098 -- 5,059
NORTHWEST
NW Alberta 2 1,896 2 -- 516 -- 2 2,154 2 363
NE Alberta -- 10,452 -- -- 1,573 -- -- 11,238 -- 1,873
Laprise -- 35,923 833 -- 10,028 232 -- 40,937 949 7,772
Boundary Lake 5,671 484 35 768 94 6 6,055 531 38 6,182
Kaybob 1,015 568 67 322 186 18 1,176 661 76 1,362
Grande Prairie 274 2,792 162 178 929 64 363 3,257 194 1,100
Meekwap 703 467 22 704 382 17 1,055 658 30 1,195
North Other 582 1,906 46 130 2,232 5 647 3,022 48 1,199
CENTRAL
Thunder 161 8,368 161 36 4,038 80 179 10,387 201 2,111
Thorsby 1,021 73,696 2,595 358 15,303 540 1,200 81,347 2,865 17,623
Crossfield/Lone Pine
Creek 224 41,720 580 116 23,800 276 282 53,620 718 9,937
Others 130 4,323 89 37 1,329 30 147 4,988 104 1,084
CAROLINE 1,168 37,140 2,306 238 27,835 1,626 1,287 51,058 3,119 12,916
SOUTHEAST
Brant Farrow 146 17,547 46 86 15,151 29 189 25,122 61 4,437
Dinosaur/Med Hat -- 29,204 -- -- 7,309 -- -- 32,858 -- 5,476
Grand Forks 5,512 3,421 79 1,848 1,337 24 6,436 4,089 91 7,209
Jumping Pound/
Whiskey Creek -- 25,410 1,220 -- 9,504 492 -- 30,162 1,466 6,493
Saskatchewan 1,580 2,094 13 356 1,544 2 1,758 2,866 14 2,250
Others 129 127 -- 14 11 -- 138 133 -- 158
ROYALTIES 1,573 12,371 195 252 1,946 40 1,699 13,344 215 4,138
------ ------- ----- ----- ------- ----- ------ ------- ------ -------
TOTAL 21,416 349,470 8,451 6,087 138,000 3,481 24,460 418,470 10,191 104,396
====== ======= ===== ===== ======= ===== ====== ======= ====== =======
NOTES:
1. No discount factor has been applied to the Probable Reserves to account for
the risk associated with the probability of obtaining production from such
reserves.
2. Based on escalated prices and costs derived from the Gilbert Report.
OIL AND NATURAL GAS WELLS
The following table summarizes, as at December 31, 2002, PrimeWest's
interests in producing and shut-in wells which it believes are capable of
production.
PRODUCING WELLS SHUT-IN WELLS(1)
------------------------------------------- --------------------------------------------------
OIL NATURAL GAS OIL NATURAL GAS
-------------------- ---------------------- ----------------------- -------------------------
GROSS(2) NET(3) GROSS(2) NET(3) GROSS(2) NET(3) GROSS(2) NET(3)
-------- ------ -------- ------ -------- ------ -------- ------
Alberta 1,602 578 1,134 634 658 331 533 348
British Columbia 168 43 27 19 23 13 11 10
Saskatchewan 432 77 120 120 94 32 2 2
----- --- ----- --- --- --- --- ---
Total 2,202 698 1,281 773 775 376 546 360
===== === ===== === === === === ===
NOTES:
1. "Shut-In" wells means wells which are not producing but which may be
capable of production. Shut-in wells in which PrimeWest has an interest are
located no further than 10 kilometres from gathering systems, pipelines or
other means of transportation.
2. "Gross" wells and acres are defined as the total number of wells and acres
in which PrimeWest has an interest.
3. "Net" wells and acres are defined as the aggregate of the numbers obtained
by multiplying each gross well and acre by PrimeWest's percentage working
interest therein.
23
DAWSON
The Dawson area consists of extensive land holdings from Twps. 75 to 81
and Ranges 14 to 23W5M, approximately 80 miles northeast of Grande Prairie,
Alberta. PrimeWest generally holds a 50 percent working interest in the majority
of lands. The lands are located in the Normandville, Dawson, Roxana, Lalby,
Fahler, Seal, Stowe and Kimiwan fields. The Dawson area is characterised by
natural gas reservoirs located in multiple shallow depth horizons such as the
Notekiwen, Fahler, BlueSky, Shunda and Debolt formations. The deep oil
production originates in the Beaverhill Lake and Slave Point formations.
PrimeWest operates the majority of its activities in this area.
PrimeWest operates three gas processing plants, which have 20 mmcf/d of
capacity, net to PrimeWest.
NORTHWEST
PrimeWest's significant holdings in the Northwest Alberta area are
located in Twps. 90 to 97, Range 21W5 to Range 3W6M, approximately 100 miles
southeast of Rainbow Lake, Alberta. The lands are located in the Hotchkiss,
Naylor, Sutton and Keg River Post fields. The Northwest Alberta area is
characterized by 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. PrimeWest's current focus in this area is the
development of natural gas reserves in the shallow Cretaceous formations.
PrimeWest operates a gas processing plant in the area that has 22 mmcf/d of
capacity.
Included in the NorthWest are Meekwap, NE B.C., Kaybob, and Grande
Prairie.
MEEKWAP
- -------
Meekwap is comprised of the Nisku D2A unitized waterflood with a 48%
PrimeWest working interest. PrimeWest operates this property.
NORTHEAST B.C.
- --------------
Northeast B.C. is comprised of Boundary Lake and Laprise.
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 PrimeWest has 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
24
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. PrimeWest also has a 2.1 percent working interest
in the Boundary Lake Unit No. 1.
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. PrimeWest has 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, PrimeWest has a 100
percent interest in one producing non-unit gas well.
KAYBOB
- ------
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. PrimeWest
has 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.
CAROLINE
The Caroline area is located approximately 60 miles northwest of
Calgary, Alberta. Production in the area is obtained from the Cardium, Viking
and Manville formations. PrimeWest owns a high working interest and is the
operator of this predominantly gas producing area.
The properties include working interests ranging from gross overriding
royalty interests to 100%. Average net daily production in 2001 was 2,344 boe/d
and in September 2002 was 2,810 boe/d.
On January 23, 2003, PrimeWest acquired additional reserves and
production at Caroline, consistent with the Trust's strategy of consolidating
interests in an existing core area where a competitive advantage exists and
resident technical skills can be leveraged. Caroline is now the Trust's largest
core operating area with production of 5,500 boe/d.
Effective December 18, 2001, the East Caroline portion of the Caroline
properties were sold.
At Caroline, the Trust acquired, effective January 1, 2003, a 100%
interest in the 25 mmcf/d Sundre Gas Plant and related gas gathering
infrastructure in addition to liquids rich natural gas production and reserves.
PrimeWest plans to process certain of the
25
Trust's preacquisition volumes as well as new development production through
this plant at lower processing costs, relative to what it has previously
incurred in this area.
Future reserve growth in this area will be enhanced by a significant
farm-in opportunity on undeveloped lands, including the right to purchase the
farmor's share of developed reserves at a future date. Furthermore, an area of
mutual interest has been established focused on low risk, high impact gas
development drilling activities.
CENTRAL
The Central area encompasses properties at Thorsby, Thunder and
Crossfield/Lone Pine Creek. These properties are located between Calgary and
Edmonton.
CROSSFIELD / LONE PINE CREEK
- ----------------------------
The Crossfield/Lone Pine Creek area is located 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, Viking
and Nisku Formations.
All operated natural gas production is processed at the East Crossfield
Sour Gas Processing Facility. The East Crossfield gas processing facility has a
throughput capacity of 74 mmcf/d. 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 and adjacent levels to the plant on a
life reserves basis. After this sale, PrimeWest's ownership in the facility is
28.8 percent. All of PrimeWest's natural gas produced from this area is
processed on a plant operating-cost basis. During 2002, plant utilization was
approximately 50 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 no ownership interest in the Sulphur Block or any
liability related to future clean-up costs.
THORSBY
- -------
The Thorsby property is located in Twps. 47 to 50, Ranges 27 W4 to
Range 2 W5M, approximately 35 miles southwest of Edmonton, Alberta. The lands
are located in the Pembina, Thorsby, Holburn, Wizard Lake and Bonnie Glen
fields. PrimeWest holds an average 83 percent working interest in this natural
gas and crude oil producing area.
26
The majority of the production is derived from regionally extensive
Glauconitic Sandstone.
SOUTHEAST
BRANT/FARROW
- ------------
The Brant/Farrow property is located in Twps. 18 to 21, Ranges 23 to 26
W4M, approximately 40 miles southeast of Calgary. The lands are located in the
Brant, Farrow, Mossleigh and Herronton fields. Gas is the major product
constituting approximately 95 percent of the total production volumes. The
Brant/Farrow area is characterised by shallow to medium depth natural gas and
oil reservoirs. The area produces from the Mississippian, Basal Quartz,
Glauconite, Belly River, and Medicine Hat formations.
When acquired, the majority of production was from deep, high decline
formations. Since the acquisitions, PrimeWest has redirected development to low
risk, shallow drilling in the Belly River and Medicine Hat Formations. For the
year ended December 31, 2002 PrimeWest drilled 12 gross (9 net) wells in the
area. This area is a high activity development area and further drilling is
expected.
PrimeWest operates two gas-processing plants in the area, which have 15
mmcf/d of capacity.
DINOSAUR/MEDICINE HAT
- ---------------------
The Dinosaur area is located approximately 110 miles east of Calgary.
PrimeWest owns 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 Medicine Hat property covers a 25 mile radius around Medicine Hat,
Alberta. PrimeWest is working interest owner and operator of the Medicine Hat
Consolidated Unit #2, which is located 25 miles northeast of Medicine Hat. Gas
is produced from the Medicine Hat "A", "C", "D", Lower Colorado and Milk River
Zones". In 2002, the Medicine Hat Consolidated Owners installed their own
compression which helped alleviate the custom processing charges previously
paid.
Both the Dinosaur and Medicine Hat properties are shallow gas plays
with low operating costs, stable production, and long reserve life indexes.
GRAND FORKS
- -----------
The Grand Forks property is located 45 miles west of Medicine Hat,
Alberta. Crude oil reserves are found predominantly in the Sawtooth and Arcs
(Nisku) formations at an average depth of 3,100 feet. PrimeWest has an average
73 percent
27
working interest in 190 (138.7 net) producing oil wells and a 94 percent working
interest in 10 (9.4 net) producing gas wells.
JUMPING POUND WEST / WHISKEY CREEK
- ----------------------------------
PrimeWest has 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 in 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 liquids rich,
yielding 40 bbls of liquids per mmcf of natural gas.
Whiskey Creek is a non-operated property that has one well on
production and tied-in with another well completed and currently waiting to be
tied in. The third well is currently being drilled.
Both the Jumping Pound and Whiskey Creek properties have deep thrusted
Mississippian reservoirs characterized with long-life, stable production and
long reserve life indexes.
Early in 2002, the joint venture partners experienced a pipeline
failure which halted production. The well resumed production in February 2003.
GROSS OVERRIDING ROYALTY (GORR) INTERESTS
These interests, principally acquired from Reserve Royalty Corp. in
July 2000, entitle PrimeWest to a share of the gross sales price on production
from the underlying properties generally without deduction for royalties and
operating expenses. As well, as the owner of the GORR interest, PrimeWest is not
generally responsible for any capital costs or abandonment and restoration costs
associated with any exploration or development activities undertaken by the
underlying working interest owner of the lands subject to the GORR.
28
UNPROVED LANDS
PrimeWest has an interest in approximately 1,286,883 (938,683 net)
acres of unproved lands at December 31, 2002. PrimeWest is currently reviewing
available seismic and other data, and developing an exploitation plan for these
properties. Capital expenditures, farmouts and/or dispositions may result in
future revenues from these undeveloped lands. The province and value of the
unproved lands is as follows:
GROSS
ROYALTY TOTAL NET VALUE OF NET
GROSS ACRES NET ACRES ACRES ACRES ACRES
----------------- ---------------- ---------------- ---------------- ----------------
Alberta 1,062,147 724,567 165,723 890,290 $43,467,422
B.C. 13,482 4,202 0 4,202 350,820
Sask 6,463 5,123 39,068 44,191 416,498
----------------- ---------------- ---------------- ---------------- ----------------
TOTAL 1,082,092 733,892 204,791 938,683 $44,234,740
================= ================ ================ ================ ================
UNPROVED LANDS 2002 2001
---- ----
ACRES NET VALUE Acres Net Value
- -------------------------------------------------------------------------- --------------------------------------------
GROSS NET ($) Gross Net ($)
DAWSON
Dawson 236,488 144,647 $11,571,760 247,608 156,229 $14,129,465
Stowe 218,571 201,885 9,084,825 8,256 4,992 8,884,822
Other 6,880 4,160 270,400 158,467 144,842 697,859
NORTHWEST
NW Alberta 28,000 19,554 586,620 32,699 22,835 685,050
NE B.C. 13,482 4,202 350,820 14,830 4,622 323,540
Kaybob 7,200 1,420 78,100 7,920 1,562 109,340
Meekwap 7,040 3,166 221,620 8,096 3,640 254,800
GP 20,347 15,840 633,600 23,399 18,216 1,275,120
Other 81,574 41,249 2,580,545 71,731 35,065 3,895,369
CAROLINE
Caroline 49,362 35,802 2,506,140 47,489 35,063 1,402,550
CENTRAL
Thorsby 62,048 48,775 2,194,875 56,931 49,011 3,430,770
Crossfield / Lone Pine Creek 45,178 23,866 2,413,575 46,468 35,781 2,504,670
Thunder 53,920 24,987 1,124,415 67,680 33,813 2,366,910
Other 36,168 11,854 766,000 44,439 21,224 2,307,444
SOUTHEAST
Brant Farrow 116,888 88,090 5,285,400 78,609 60,414 4,228,980
Dinosaur/Medicine Hat 13,907 9,618 376,950 15,530 13,779 543,127
Grand Forks 43,732 20,328 813,120 48,835 29,122 1,971,582
Jumping Pound / Whiskey Creek 5,438 4,095 163,800 6,073 5,867 236,011
Saskatchewan 6,463 5,123 237,425 7,109 5,635 394,450
Other 29,406 25,231 926,840 32,466 26,754 2,344,729
- ------------------------------------------------------------------------------------------------------------------------
Total Working Interest Acres 1,082,092 733,892 42,186,830 1,024,635 708,466 51,986,588
Gross Royalty Acres 204,791 204,791 2,047,910 244,961 244,961 3,674,415
- ------------------------------------------------------------------------------------------------------------------------
TOTAL 1,286,883 938,683 $44,234,740 1,269,596 953,427 $55,661,003
========================================================================================================================
29
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 PrimeWest is unable to predict what additional legislation or
amendments may be enacted.
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.
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 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.
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
30
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 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
31
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 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. PrimeWest believes that
it is in material compliance with applicable environmental laws and regulations
properties.
KYOTO PROTOCOL
In December of 2002, Canada became a signatory to the Kyoto Protocol.
The implementation of this plan has not been fully defined by the federal
government. Until an implementation plan is developed it is impossible to assess
the impact on specific industries and individual businesses within an industry.
It is generally believed that the oil and gas industry, as a major producer of
carbon dioxide as a necessary by-product and emission of hydrocarbon production,
will bear a disproportionately large share of the anticipated cost of
implementation.
RISKS RELATED TO OUR BUSINESS
VOLATILITY IN OIL AND NATURAL GAS PRICES COULD HAVE A MATERIAL ADVERSE EFFECT ON
RESULTS OF OPERATIONS AND FINANCIAL CONDITION WHICH, IN TURN, COULD AFFECT THE
MARKET PRICE OF THE TRUST UNITS AND THE AMOUNT OF DISTRIBUTIONS TO UNITHOLDERS.
Results of operations and financial condition are dependent on the
prices received for the oil and natural gas that the Trust sells. Historically,
the markets for oil and natural gas have been volatile and are likely to
continue to be volatile in the future. Oil and natural gas prices may fluctuate
widely on a daily basis in response to a variety of factors beyond the Trust's
control, including:
o global energy policy, including the ability of OPEC to set and maintain
production levels and prices for oil;
o political conditions, including the risk of hostilities in the Middle
East;
o global and domestic economic conditions;
o weather conditions;
o the supply and price of imported oil and liquified natural gas;
o the production and storage levels of North American natural gas;
o the level of consumer demand;
32
o the price and availability of alternative fuels;
o the proximity of reserves to, and capacity of, transportation
facilities;
o the effect of worldwide energy conservation measures; and
o government regulations.
Any decline in crude oil or natural gas prices may have a material
adverse effect on PrimeWest's operations, financial condition, borrowing
ability, reserves and the level of expenditures for the development of oil and
natural gas reserves. Any resulting decline in PrimeWest's cash flow could
reduce distributions.
PrimeWest uses financial derivative instruments and other hedging
mechanisms to try to limit a portion of the adverse effects resulting from
changes in natural gas and oil commodity prices. To the extent PrimeWest hedges
its commodity price exposure, it foregoes the benefits it would otherwise
experience if commodity prices were to increase. In addition, its commodity
hedging activities could expose PrimeWest to losses. Such losses could occur
under various circumstances, including if the other party to a hedge does not
perform its obligations under the hedge agreement, the hedge is imperfect or
PrimeWest's hedging policies and procedures are not followed. Furthermore,
PrimeWest cannot guarantee that its hedging transactions will fully offset the
risks of changes in commodities prices.
AN INCREASE IN OPERATING COSTS OR A DECLINE IN PRIMEWEST'S PRODUCTION LEVEL
COULD HAVE A MATERIAL ADVERSE EFFECT ON OUR RESULTS OF OPERATIONS AND FINANCIAL
CONDITIONS AND, THEREFORE, COULD REDUCE DISTRIBUTIONS TO UNITHOLDERS.
Higher operating costs for the underlying properties of the Operating
Company will directly decrease the amount of cash flow received by the Trust
and, therefore, may reduce distributions to our unitholders. Electricity,
chemicals, supplies, reclamation and abandonment and labour costs are a few of
the operating costs that are susceptible to material fluctuation.
The level of production from existing properties may decline at rates
greater than anticipated due to unforeseen circumstances, many of which are
beyond PrimeWest's control. A significant decline in production could result in
materially lower revenues and cash flow and, therefore, could reduce the amount
available for distributions to Unitholders.
DISTRIBUTIONS MAY BE REDUCED DURING PERIODS IN WHICH PRIMEWEST MAKES CAPITAL
EXPENDITURES OR DEBT REPAYMENTS USING CASH FLOW.
To the extent that PrimeWest uses cash flow to finance acquisitions,
development costs and other significant expenditures, the net cash flow that the
Trust receives from PrimeWest will be reduced. Hence, the timing and amount of
capital expenditures may
33
affect the amount of net cash flow received by the Trust and, as a consequence,
the amount of cash available to distribute to Unitholders. Therefore,
distributions may be reduced, or even eliminated, at times when significant
capital or other expenditures are made.
The board of directors of PrimeWest has the discretion to determine the
extent to which cash flow from PrimeWest will be allocated to the payment of
debt service charges as well as the repayment of outstanding debt, including
under the credit facility. Funds used for such purposes will not be payable to
the Trust. As a consequence, the amount of funds retained by PrimeWest to pay
debt services charges or reduce debt will reduce the amount of cash distributed
to Unitholders during those periods in which funds are so retained.
A DECLINE IN PRIMEWEST'S ABILITY TO MARKET ITS OIL AND NATURAL GAS PRODUCTION
COULD HAVE A MATERIAL ADVERSE EFFECT ON PRODUCTION LEVELS OR ON THE PRICE THAT
IT RECEIVED FOR PRODUCTION WHICH, IN TURN, COULD REDUCE DISTRIBUTIONS TO
UNITHOLDERS.
PrimeWest's business depends in part upon the availability, proximity
and capacity of gas gathering systems, pipelines and processing facilities.
Canadian federal and provincial, as well as United States federal and state,
regulation of oil and gas production, processing and transportation, tax and
energy policies, general economic conditions, and changes in supply and demand
could adversely affect PrimeWest's ability to produce and market oil and natural
gas. If market factors change and inhibit the marketing of PrimeWest's
production, overall production or realized prices may decline, which could
reduce distributions to our unitholders.
FLUCTUATIONS IN FOREIGN CURRENCY EXCHANGE RATES COULD ADVERSELY AFFECT
PRIMEWEST'S BUSINESS.
The price that PrimeWest receives for a majority of its oil and natural
gas is based on United States dollar denominated benchmarks, and therefore the
price that PrimeWest receives in Canadian dollars is affected by the exchange
rate between the two currencies. A material increase in the value of the
Canadian dollar relative to the United States dollar may negatively impact net
production revenue by decreasing the Canadian dollars received for a given
United States dollar price. To the extent that PrimeWest has engaged, or in the
future engages, in risk management activities related to foreign exchange rates,
through entry into forward foreign exchange contracts or otherwise, PrimeWest
will be subject to unfavourable price changes.
IF PRIMEWEST IS UNABLE TO ACQUIRE ADDITIONAL RESERVES, THE VALUE OF THE TRUST
UNITS AND DISTRIBUTIONS TO UNITHOLDERS MAY DECLINE.
The Trust and PrimeWest do not explore for oil and natural gas
reserves. Instead, PrimeWest adds to its oil and natural gas reserves primarily
through acquisitions. As a result, future oil and natural gas reserves are
highly dependent on PrimeWest's success in exploiting existing properties and
acquiring additional reserves.
34
PrimeWest also distributes the majority of its net cash flow to Unitholders
rather than reinvesting it in reserve additions. Accordingly, if external
sources of capital, including the issuance of additional Trust Units, become
limited or unavailable on commercially reasonable terms, PrimeWest's ability to
make the necessary capital investments to maintain or expand its oil and natural
gas reserves will be impaired. To the extent that PrimeWest is required to use
cash flow to finance capital expenditures or property acquisitions, the level of
cash flow available for distribution to Unitholders will be reduced.
Additionally, PrimeWest cannot guarantee that it will be successful in
developing additional reserves or acquiring additional reserves on terms that
meet its investment objectives. Without these reserve additions, PrimeWest's
reserves will deplete and as a consequence, either production from, or the
average reserve life of, its properties will decline. Either decline may result
in a reduction in the value of Trust Units and in a reduction in cash available
for distributions to Unitholders.
ACTUAL RESERVES WILL VARY FROM RESERVE ESTIMATES, AND THOSE VARIATIONS COULD BE
MATERIAL.
The value of the Trust Units depends upon, among other things, the
reserves attributable to PrimeWest's properties. Estimating reserves is
inherently uncertain. Ultimately, actual reserves attributable to PrimeWest's
properties will vary from estimates, and those variations may be material. The
reserve information contained herein are only estimates. A number of factors are
considered and a number of assumptions are made when estimating reserves. These
factors and assumptions include, among others:
o historical production in the area compared with production rates from
similar producing areas;
o future commodity prices, production and development costs, royalties
and capital expenditures;
o initial production rates;
o production decline rates;
o ultimate recovery of reserves;
o success of future development activities;
o marketability of production;
o effects of government regulation; and
o other government levies that may be imposed over the producing life of
reserves.
35
Reserve estimates are based on the relevant factors, assumptions and
prices on the date the relevant evaluations were prepared. Many of these factors
are subject to change and are beyond PrimeWest's control. If these factors,
assumptions and prices prove to be inaccurate, actual results may vary
materially from reserve estimates.
IF PRIMEWEST EXPANDS ITS OPERATIONS BEYOND OIL AND NATURAL GAS PRODUCTION IN
WESTERN CANADA, IT MAY FACE NEW CHALLENGES AND RISKS. IF PRIMEWEST IS
UNSUCCESSFUL IN MANAGING THESE CHALLENGES AND RISKS, ITS RESULTS OF OPERATIONS
AND FINANCIAL CONDITION COULD BE ADVERSELY AFFECTED.
PrimeWest's operations and expertise are currently focused on
conventional oil and gas production and development in the Western Canadian
Sedimentary Basin. In the future, it may acquire oil and gas properties outside
this geographic area. In addition, the Declaration of Trust does not limit the
activities to oil and gas production and development, and PrimeWest could
acquire other energy related assets, such as oil and natural gas processing
plants or pipelines. Expansion of PrimeWest's activities into new areas may
present challenges and risks that it has not faced in the past. If PrimeWest
does not manage these challenges and risks successfully, its results of
operations and financial condition could be adversely affected.
IN DETERMINING THE PURCHASE PRICE OF ACQUISITIONS, PRIMEWEST RELIES ON
ASSESSMENTS RELATING TO ESTIMATES OF RESERVES THAT MAY PROVE TO BE INACCURATE.
The price PrimeWest is willing to pay for reserve acquisitions is based
largely on estimates of the reserves to be acquired. Actual reserves could vary
materially from these estimates. Consequently, the reserves PrimeWest acquires
may be less than expected, which could adversely impact cash flows and
distributions to Unitholders.
An initial assessment of an acquisition may be based on a report by
engineers or firms of engineers that have different evaluation methods and
approaches than those of PrimeWest's engineers, and these initial assessments
may differ significantly from PrimeWest's subsequent assessments.
SOME OF PRIMEWEST'S PROPERTIES ARE NOT OPERATED BY PRIMEWEST AND, THEREFORE,
RESULTS OF OPERATIONS MAY BE ADVERSELY AFFECTED BY THE FAILURE OF THIRD-PARTY
OPERATORS.
The continuing production from a property, and to some extent the
marketing of that production, is dependent upon the ability of the operators of
those properties. At December 31, 2002, approximately 20% of PrimeWest's daily
production was from properties operated by third parties. To the extent a
third-party operator fails to perform its functions efficiently or becomes
insolvent, PrimeWest's revenue may be reduced. Third party operators also make
estimates of future capital expenditures more difficult.
Further, the operating agreements which govern the properties not
operated by PrimeWest typically require the operator to conduct operations in a
good and
36
"workmanlike" manner. These operating agreements generally provide, however,
that the operator has no liability to the other non-operating working interest
owners, such as Unitholders, for losses sustained or liabilities incurred,
except for liabilities that may result from gross negligence or wilful
misconduct.
DELAYS IN BUSINESS OPERATIONS COULD ADVERSELY AFFECT DISTRIBUTIONS TO
UNITHOLDERS.
In addition to the usual delays in payment by purchasers of oil and
natural gas to the operators of PrimeWest's properties, and the delays of those
operators in remitting payment to PrimeWest, payments between any of these
parties may also be delayed by:
o restrictions imposed by lenders;
o accounting delays;
o delays in the sale or delivery of products;
o delays in the connection of wells to a gathering system;
o blowouts or other accidents;
o adjustments for prior periods;
o recovery by the operator of expenses incurred in the operation of the
properties; or
o the establishment by the operator of reserves for these expenses.
Any of these delays could reduce the amount of cash available for
distribution to Unitholders in a given period and expose PrimeWest to additional
third party credit risks.
THE TRUST AND PRIMEWEST'S INDEBTEDNESS MAY LIMIT THE TIMING OR AMOUNT OF THE
DISTRIBUTIONS THAT ARE PAID TO UNITHOLDERS.
The payments of interest and principal, and other costs, expenses and
disbursements to the providers of the Trust and PrimeWest's credit facility
reduces amounts available for distribution to Unitholders. Variations in
interest rates and scheduled principal repayments could result in significant
changes to the amount of the cash flow required to be applied to the debt before
payment of any amounts to the Unitholders. The credit facility provides that if
the Trust or PrimeWest are in default under the credit facility, exceed certain
borrowing thresholds or fail to comply with certain covenants, the ability to
make distributions to Unitholders may be restricted.
The lenders under the credit facility have been provided with a
security interest in substantially all of the Trust's and PrimeWest's assets. If
the Trust and PrimeWest
37
are unable to pay the debt service charges or otherwise commit an event of
default, such as bankruptcy, these lenders may foreclose on and sell the
properties. The proceeds of any sale would be applied to satisfy amounts owed to
the creditors. Only after the proceeds of that sale were applied towards the
debt would the remainder, if any, be available for distribution to Unitholders.
THE CURRENT CREDIT FACILITY AND ANY REPLACEMENT CREDIT FACILITY MAY NOT PROVIDE
SUFFICIENT LIQUIDITY.
The amounts available under the existing credit facility may not be
sufficient for future operations, or the Trust and PrimeWest may not be able to
obtain additional financing on economic terms attractive to them, if at all. The
existing credit facility is available on a one year revolving basis. If the
lenders do not extend the facility at the end of the annual revolving period,
the loan will convert to a term basis with 60% of the aggregate principal amount
of the loan repayable on the date which is 366 days after that conversion date
and the remaining 40% of the aggregate principal amount outstanding repayable on
the date which is 365 days after the initial term repayment date. If this
occurs, the Trust and PrimeWest may need to obtain alternate financing. Any
failure to obtain suitable replacement financing may have a material adverse
effect on the business, and distributions to Unitholders may be materially
reduced.
THE TRUST MAY BE UNABLE TO SUCCESSFULLY COMPETE WITH OTHER ORGANIZATIONS IN THE
TRUST'S INDUSTRY.
The oil and natural gas industry is highly competitive. The Trust
competes for capital, acquisitions of reserves, undeveloped lands, skilled
personnel, access to drilling rigs, service rigs and other equipment, access to
processing facilities, pipeline and refining capacity and in many other respects
with a substantial number of other organizations, many of which may have greater
technical and financial resources than the Trust. Some of these organizations
not only explore for, develop and produce oil and natural gas but also carry on
refining operations and market oil and other products on a worldwide basis. As a
result of these complementary activities, some of the Trust's competitors may
have greater and more diverse competitive resources to draw on than the Trust
does.
THE INDUSTRY IN WHICH PRIMEWEST OPERATES EXPOSES THE TRUST AND PRIMEWEST TO
POTENTIAL LIABILITIES THAT MAY NOT BE COVERED BY INSURANCE.
PrimeWest's operations are subject to all of the risks associated with
the operation and development of oil and natural gas properties, including the
drilling of oil and natural gas wells, and the production and transportation of
oil and natural gas. These risks and hazards include encountering unexpected
formations or pressures, blow-outs, craterings and fires, all of which could
result in personal injury, loss of life, or environmental and other damage to
PrimeWest's property and the property of others. PrimeWest cannot fully protect
against all of these risks, nor are all of these
38
risks insurable. PrimeWest may become liable for damages arising from these
events against which PrimeWest cannot insure or against which PrimeWest may
elect not to insure because of high premium costs or other reasons. Any costs
incurred to repair these damages or pay these liabilities would reduce funds
available for distribution to Unitholders.
THE OPERATION OF OIL AND NATURAL GAS WELLS COULD SUBJECT PRIMEWEST TO
ENVIRONMENTAL CLAIMS AND LIABILITY.
The oil and natural gas industry is subject to extensive environmental
regulation pursuant to local, provincial and federal legislation. A breach of
that legislation may result in the imposition of fines or the issuance of "clean
up" orders. Legislation regulating the oil and natural gas industry may be
changed to impose higher standards and potentially more costly obligations. For
example, the 1997 Kyoto Protocol to the United Nation's Framework Convention on
Climate Change, known as the Kyoto Protocol, was ratified by the Canadian
government in December, 2002 and will require, among other things, significant
reductions in greenhouse gases. The impact of the Kyoto Protocol on PrimeWest is
uncertain and may result in significant additional costs (future) for
PrimeWest's operations. Although PrimeWest has established a reclamation fund
for the purpose of funding our estimated future environmental and reclamation
obligations based on PrimeWest's current knowledge and expectations, PrimeWest
cannot guarantee that it will be able to satisfy its actual future environmental
and reclamation obligations.
PrimeWest is not fully insured against certain environmental risks,
either because such insurance is not available or because of high premium costs.
In particular, insurance against risks from environmental pollution occurring
over time (as opposed to sudden and catastrophic damages) is not available on
economically reasonable terms. Accordingly, PrimeWest's properties may be
subject to liability due to hazards that cannot be insured against, or that have
not been insured against due to prohibitive premium costs or for other reasons.
Any site reclamation or abandonment costs actually incurred in the
ordinary course of business in a specific period will be funded out of cash flow
and, therefore, will reduce the amounts available for distribution 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.
LOWER OIL AND GAS PRICES INCREASE THE RISK OF WRITE-DOWNS OF PRIMEWEST'S OIL AND
GAS PROPERTY INVESTMENTS.
Under Canadian accounting rules, the net capitalized cost of oil and
gas properties may not exceed a "ceiling limit" that is based, in part, upon
estimated future net cash flows from reserves. If the net capitalized costs
exceed this limit, PrimeWest
39
must charge the amount of the excess against earnings. If oil and natural gas
prices decline, PrimeWest's net capitalized cost may exceed this cost ceiling,
ultimately resulting in a charge against PrimeWest's earnings. Under United
States GAAP, the cost ceiling is generally lower than under Canadian GAAP
because the future net cash flows used in the United States ceiling test are
discounted to a present value. Accordingly, PrimeWest would have more risk of a
ceiling test write-down in a declining price environment if PrimeWest reported
under United States GAAP. While these write-downs would not affect cash flow,
the charge against earnings could be viewed unfavourably in the market.
UNFORESEEN TITLE DEFECTS MAY RESULT IN A LOSS OF ENTITLEMENT TO PRODUCTION AND
RESERVES.
PrimeWest conducts title reviews in accordance with industry practice
prior to any purchase of resource assets. However, these reviews do not
guarantee that an unforeseen defect in the chain of title will not arise and
defeat PrimeWest's title to the purchased assets. If such a defect were to
occur, PrimeWest's entitlement to the production from such purchased assets
could be jeopardized and, as a result, distributions to Unitholders may be
reduced.
THE ECONOMIC IMPACT ON PRIMEWEST OF CLAIMS OF ABORIGINAL TITLE IS UNKNOWN.
Aboriginal people have claimed aboriginal title and rights to a
substantial portion of western Canada. PrimeWest is not aware that any claims of
aboriginal title have been made in respect of its property and assets, and
PrimeWest is unable to assess the effect, if any, that any such claim would have
on its business and operations.
RISKS RELATED TO THE TRUST STRUCTURE AND THE OWNERSHIP OF TRUST UNITS
CHANGES IN TAX AND OTHER LAWS MAY ADVERSELY AFFECT UNITHOLDERS.
Income tax laws, other laws or government incentive programs relating
to the oil and gas industry, such as the treatment of mutual fund trusts and
resource allowance, may in the future be changed or interpreted in a manner that
adversely affects the Trust and Unitholders. Tax authorities having jurisdiction
over the Trust or the Unitholders may disagree with how the Trust calculates its
income for tax purposes or could change their administrative practices to the
Trust's detriment or the detriment of its Unitholders.
THERE WOULD BE MATERIAL ADVERSE TAX CONSEQUENCES IF THE TRUST LOST ITS STATUS AS
A MUTUAL FUND TRUST UNDER CANADIAN TAX LAWS.
It is intended that the Trust continue to qualify as a mutual fund
trust for purposes of the INCOME TAX ACT (Canada). The Trust may not, however,
always be able to satisfy any future requirements for the maintenance of mutual
fund trust status. Should the status of the Trust as a mutual fund trust be lost
or successfully challenged by a relevant tax authority, certain adverse
consequences may arise for the Trust and
40
Unitholders. Some of the significant consequences of losing mutual fund trust
status are as follows:
o The Trust would be taxed on certain types of income distributed to
Unitholders, including income generated by the royalties held by the
Trust. Payment of this tax may have adverse consequences for some
Unitholders, particularly Unitholders that are not residents of Canada
and residents of Canada that are otherwise exempt from Canadian income
tax.
o The Trust would cease to be eligible for the capital gains refund
mechanism available under Canadian tax laws if it ceased to be a mutual
fund trust.
o Trust units held by Unitholders that are not residents of Canada would
become taxable Canadian property. These non-resident holders would be
subject to Canadian income tax on any gains realized on a disposition
of Trust Units held by them.
o The Trust Units would not constitute qualified investments for
Registered Retirement Savings Plans, or "RRSPs," Registered Retirement
Income Funds, or "RRIFs," Registered Education Savings Plans, or
"RESPs," or Deferred Profit Sharing Plans, or "DPSPs." If, at the end
of any month, one of these exempt plans holds Trust Units that are not
qualified investments, the plan must pay a tax equal to 1% of the fair
market value of the Trust Units at the time the Trust Units were
acquired by the exempt plan. An RRSP or RRIF holding non-qualified
Trust Units would be subject to taxation on income attributable to the
Trust Units. If an RESP holds non-qualified Trust Units, it may have
its registration revoked by the Canada Customs and Revenue Agency.
In addition, the Trust may take certain measures in the future to the
extent the Trust believes them necessary to ensure that the Trust maintains its
status as a mutual fund trust. These measures could be adverse to certain
holders of Trust Units.
RIGHTS AS A UNITHOLDER DIFFER FROM THOSE ASSOCIATED WITH OTHER TYPES OF
INVESTMENTS.
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 the
Trust or PrimeWest. The Trust Units represent an equal fractional beneficial
interest in the Trust and, as such, the ownership of the Trust Units does not
provide Unitholders with the statutory rights normally associated with ownership
of shares of a corporation, including, for example, the right to bring
"oppression" or "derivative" actions. The unavailability of these statutory
rights may also reduce the ability of Unitholders to seek legal remedies against
other parties on PrimeWest's behalf.
The Trust Units are also unlike conventional debt instruments in that
there is no principal amount owing to Unitholders. The Trust Units will have
minimal value when
41
reserves from PrimeWest's properties can no longer be economically produced or
marketed. Unitholders will only be able to obtain a return of the capital they
invested during the period when reserves may be economically recovered and sold.
Accordingly, the distributions received over the life of the investment may not
meet or exceed the initial capital investment.
CHANGES IN MARKET-BASED FACTORS MAY ADVERSELY AFFECT THE TRADING PRICE OF TRUST
UNITS.
The market price of the Trust's Trust Units is primarily a function of
anticipated distributions to Unitholders and the value of the properties owned
by PrimeWest and the Trust. The market price of the Trust's Trust Units is
therefore sensitive to a variety of market based factors, including, but not
limited to, interest rates and the comparability of the Trust Units to other
yield oriented securities. Any changes in these market-based factors may
adversely affect the trading price of the Trust Units.
THE OPERATION OF THE TRUST IS ENTIRELY INDEPENDENT FROM THE UNITHOLDERS AND LOSS
OF KEY MANAGEMENT AND OTHER PERSONNEL COULD IMPACT THE BUSINESS.
Unitholders are entirely dependent on the management of the Trust with
respect to the acquisition of oil and gas properties and assets, the development
and acquisition of additional reserves, the management and administration of all
matters relating to the properties and the administration of the Trust. The loss
of the services of key individuals who currently comprise the management team
could have a detrimental effect on the Trust. Investors should carefully
consider whether they are willing to rely on the existing management before
investing in the Trust Units.
THERE MAY BE FUTURE DILUTION.
One of the Trust's objectives is to continually add to its resource
reserves through acquisitions and through development. Because the Trust does
not reinvest its cash flow, its success is, in part, dependent on its ability to
raise capital from time to time by selling Trust Units. Unitholders will suffer
dilution as a result of these offerings if, for example, the cash flow,
production or reserves from the acquired assets do not reflect the additional
number of trust units issued to acquire those assets. Unitholders may also
suffer dilution in connection with future issuances of Trust Units to effect
acquisitions.
THE TRUST UNITS HAVE A SHORT PRIOR TRADING HISTORY IN THE UNITED STATES AND AN
ACTIVE TRADING MARKET HAS NOT YET DEVELOPED AND MAY NOT DEVELOP.
The Trust is a reporting issuer in Alberta, Canada under the SECURITIES
ACT (Alberta) and a reporting issuer or the equivalent in the other provinces of
Canada under similar legislation. The Trust Units are currently listed on the
Toronto Stock Exchange and the New York Stock Exchange. The Trust Units only
began trading on the New York Stock Exchange on November 19, 2002 and,
accordingly, prior to the date of this Annual Information Form, there has been
only a short period in which a public
42
market for the Trust Units in the United States has had the opportunity to
develop. The Trust therefore cannot guarantee that an active trading market will
develop or be sustained in the United States. Furthermore, there can be no
assurance that an active trading market will be sustained in Canada.
THE LIMITED LIABILITY OF UNITHOLDERS IS UNCERTAIN.
Because of uncertainties in the law relating to investment trusts,
there is a risk that a Unitholder could be held personally liable for
obligations of the Trust in respect of contracts or undertakings which the Trust
enters into and for certain liabilities arising otherwise than out of contracts
including claims in tort, claims for taxes and possibly certain other statutory
liabilities. Although every written contract or commitment of the Trust must
contain an express disavowal of liability of the Unitholders and a limitation of
liability to Trust property, such protective provisions may not operate to avoid
Unitholder liability. Notwithstanding attempts to limit Unitholder liability,
Unitholders may not be protected from liabilities of the Trust to the same
extent that a shareholder is protected from the liabilities of a corporation.
Further, although the Trust has agreed to indemnify and hold harmless each
Unitholder from any costs, damages, liabilities, expenses, charges and losses
suffered by the Unitholder resulting from or arising out of that Unitholder not
having limited liability, the Trust cannot guarantee that any assets would be
available in these circumstances to reimburse Unitholders for any such
liability.
THE TRUST HAS ADOPTED A UNITHOLDERS' RIGHTS PLAN THAT MAY DISCOURAGE A TAKEOVER
ATTEMPT.
Provisions contained in the Trust's Unitholders' rights plan could make
it more difficult for a third party to acquire the Trust, even if doing so might
be beneficial to Unitholders. The rights plan imposes various procedural and
other requirements on a potential bidder, including a requirement that a
potential bidder keep the bid open for a period of at least 45 days and that the
bid be approved by Unitholders holding at least 50% of the Trust Units, other
than the Trust Units held by the potential bidder. In addition, if a Unitholder
acquires more than 20% of the outstanding Trust Units, other Unitholders may, at
the discretion of the board of PrimeWest, acquire a number of Trust Units at 50%
of the then prevailing market price, causing significant dilution to the 20%
Unitholder. These rights may have the effect of delaying or deterring a change
of control of the Trust, and could limit the price that investors might be
willing to pay in the future for Trust Units.
THE REDEMPTION RIGHTS OF UNITHOLDERS IS LIMITED.
Unitholders have a limited right to require the Trust to repurchase
their Trust Units, which is referred to as a redemption right. It is anticipated
that the redemption right will not be the primary mechanism for Unitholders to
liquidate their investment. The Trust's ability to pay cash in connection with a
redemption is subject to limitations.
43
Any securities which may be distributed IN SPECIE to Unitholders in connection
with a redemption may not be listed on any stock exchange and a market may not
develop for such securities. In addition, there may be resale restrictions
imposed by law upon the recipients of the securities pursuant to the redemption
right.
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
($000's except per Trust Unit) FOR THE YEAR ENDED DECEMBER 31
2002 2001 2000 1999 1998
----------------------------------------------------------
EARNINGS INFORMATION
Total Revenue, net of royalties.................. 264,248 306,515 156,561 83,063 66,057
Expenses, including D, D & A and taxes........... 263,628 226,979 100,949 77,078 79,604
Net Income (Loss) ............................... 620 79,536 55,612 5,985 (13,547)
Net Income (Loss) per Trust Unit ($)
Basic.................................... 0.02 3.12 5.00 0.72 (1.72)
Diluted.................................. 0.02 3.08 4.84 0.72 (1.72)
CASH DISTRIBUTION INFORMATION
Cash Available for Distribution.................. 159,546 236,834 79,832 37,728 26,030
Cash Distribution to Trust Unitholders .......... 157,951 234,465 79,033 37,351 25,769
Cash Distribution per Trust Unit ($)............. 4.80 9.24 7.08 4.40 3.28
BALANCE SHEET INFORMATION
Total Assets .................................... 1,502,252 1,522,310 441,573 320,210 316,140
Long Term Debt, including current portion ....... 225,000 195,067 79,046 92,286 73,112
Average Trust Units Outstanding (000's).......... 34,134 25,633 11,162 8,491 7,857
SELECTED QUARTERLY INFORMATION
($000's except per Trust Unit) FOR THE QUARTERS ENDED - 2002
--------------------------------------------------------------------
MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31
---------------- -------------- --------------- ---------------
Total Revenue, net of royalties ........ 69,442 62,198 63,814 68,794
Expenses including D, D & A and taxes .. 63,466 68,392 55,636 76,134
Net Income (Loss)....................... 5,976 (6,194) 8,178 (7,340)
Net Income (Loss) per Trust Unit
Basic.............................. 0.05 (0.05) 0.24 (0.19)
Diluted............................ 0.04 (0.05) 0.24 (0.19)
FOR THE QUARTERS ENDED - 2001
--------------------------------------------------------------------
MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31
---------------- -------------- --------------- ---------------
Total Revenue, net of royalties ........ 56,990 87,974 83,105 78,446
Expenses including D, D & A and taxes... 32,800 53,742 59,255 81,182
Net Income ............................. 24,190 34,232 23,850 (2,736)
Net Income per Unit
Basic.............................. 1.80 1.32 0.80 (0.08)
Diluted............................ 1.76 1.32 0.80 (0.08)
44
In addition, applicable securities laws require the Trust to provide
certain historical financial statements of Cypress in connection with any
offering of Trust Units. Those financial statements are attached to this Annual
Information Form as Schedule A.
SELECTED FINANCIAL AND OPERATIONAL INFORMATION
The information in the tables below sets forth certain quarterly
comparative financial and operations data which is intended to supplement the
financial and operations results otherwise set forth herein and in the documents
incorporated by reference herein.
AVERAGE DAILY PRODUCTION VOLUME (BEFORE ROYALTIES)
FOR THE QUARTERS ENDED - 2002
-------------------------------------------------------------------
MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31
---------------- -------------- --------------- --------------
Crude Oil (bbls/d)................ 10,244 8,990 8,975 8,766
Natural Gas Liquids (bbls/d)...... 2,240 2,055 1,950 1,878
Natural Gas (mmcf/d).............. 113.3 111.1 115.5 114.2
FOR THE QUARTERS ENDED - 2001
-------------------------------------------------------------------
MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31
---------------- -------------- --------------- --------------
Crude Oil (bbls/d)................ 6,988 11,453 11,216 10,425
Natural Gas Liquids (bbls/d)...... 1,613 2,614 2,414 2,441
Natural Gas (mmcf/d).............. 49.6 127.7 121.3 119.7
AVERAGE MARGINS - CRUDE OIL AND NGLS (PER BBL)
FOR THE QUARTERS ENDED - 2002
-------------------------------------------------------------------
MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31
---------------- -------------- --------------- --------------
Average net product price......... 32.07 31.62 34.57 33.12
Royalties......................... 4.40 4.89 6.36 6.81
Operating expenses (1)............ 5.10 5.44 5.38 6.16
Margin received................... 20.58 21.29 22.83 20.15
FOR THE QUARTERS ENDED - 2001
-------------------------------------------------------------------
MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31
---------------- -------------- --------------- --------------
Average net product price......... 33.05 35.35 32.37 28.98
Royalties......................... 5.78 6.42 6.24 4.32
Operating expenses (1)............ 5.49 4.80 6.08 5.69
Margin received................... 21.78 24.13 20.05 18.97
NOTE:
1. Operating expenses have been allocated to crude oil and NGLs produced based
on the relative production of crude oil and NGLs as compared to production
of natural gas.
45
AVERAGE MARGINS - NATURAL GAS (PER MCF)
FOR THE QUARTERS ENDED - 2002
-------------------------------------------------------------------
MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31
---------------- -------------- --------------- --------------
Average net product price......... 4.38 4.47 4.07 5.09
Royalties......................... 0.57 0.97 0.73 1.02
Operating expenses (1)............ 0.85 0.91 0.90 1.03
Margin received................... 3.15 2.60 2.45 3.04
FOR THE QUARTERS ENDED - 2001
-------------------------------------------------------------------
MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31
---------------- -------------- --------------- --------------
Average net product price......... 10.38 6.21 5.32 5.16
Royalties......................... 2.50 1.70 0.75 0.67
Operating expenses (1)............ 0.92 0.81 0.91 0.95
Margin received................... 6.96 3.70 3.66 3.54
NOTE:
1. Operating expenses have been allocated to natural gas produced based on the
relative production of natural gas as compared to production of crude oil
and NGLs.
CAPITAL EXPENDITURES (IN THOUSANDS)
FOR THE QUARTERS ENDED - 2002
-------------------------------------------------------------------
MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31
---------------- -------------- --------------- --------------
Property acquisitions............. 291 1,089 25,062 33,164
Exploration, including drilling... -- -- -- --
Development, including facilities. 23,339 6,536 15,429 17,843
Other (1)......................... 1,128 1,187 1,337 2,256
FOR THE QUARTERS ENDED - 2001
-------------------------------------------------------------------
MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31
---------------- -------------- --------------- --------------
Property acquisitions............. $ 767,569 $ 4,713 $ 2,894 $ 47,422
Exploration, including drilling... -- -- -- --
Development, including facilities. 6,197 16,132 24,608 33,510
Other (1)......................... 666 575 609 1,607
NOTE:
1. Other capital expenditures include capitalized general and administrative
expenses and other corporate expenditures.
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 the Trust are listed for trading on the
Toronto Stock Exchange under the symbol PWI.UN and on the New York Stock
Exchange under
46
the symbol PWI. The outstanding Class A Exchangeable Shares of PrimeWest are
listed for trading on the Toronto Stock Exchange under the symbol PWX.
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.
DIRECTORS
The Trust has the right to nominate and elect a majority of the board
of directors of PrimeWest to serve until the next annual meeting of Unitholders.
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 December 31, 2002, are as follows:
TRUST UNITS BENEFICIALLY
DIRECTOR OF OWNED OR OVER WHICH CONTROL
NAME AND PRESENT PRINCIPAL PRIMEWEST MUNICIPALITY OF OR DISCRETION IS EXERCISED AS
OCCUPATION OR EMPLOYMENT SINCE RESIDENCE AT DECEMBER 31, 2002
- ------------------------ ----- --------- --------------------
HAROLD P. MILAVSKY(1)(2)(3) 1996 Calgary, Alberta 19,152
Chairman
Quantico Capital Corp.
BARRY E. EMES(3) 1996 Calgary, Alberta 2,250
Partner
Stikeman Elliott LLP
HAROLD N. KVISLE(1)(2)(3) 1996 Calgary, Alberta 10,911
President
TransCanada PipeLines Limited
KENT J. MACINTYRE 1996 Calgary, Alberta 696,940(4)
Independent Businessman
MICHAEL W. O'BRIEN(1)(2)(3) 2000 Canmore, Alberta 2,500
Corporate Director
W. GLEN RUSSELL(1)(2)(3) 2003 Calgary, Alberta Nil
Management Consultant
NOTES:
1. Member of the Audit and Reserves Committee.
2. Member of the Compensation Committee.
3. Member of the Corporate Governance and Nominating Committee.
4. Includes Trust Units and 1,032,030 Class A Exchangeable Shares (which, at
December 31, 2002, were exchangeable into 386,537 Trust Units), of which
250,158 Trust Units and all Class A Exchangeable Shares were held by
Canadian Income Fund Group Inc., a corporation wholly-owned by Mr.
MacIntyre.
Each of the foregoing persons has been engaged in the occupation set
forth above or similar occupations with the same employer for the five preceding
years, other than: (a) 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.; (b) Mr. MacIntyre who prior
47
to January 2003 was Vice-Chairman and Chief Executive Officer of PrimeWest; (c)
Mr. O'Brien who prior to June 2002 was Executive Vice President, Corporate
Development and Chief Financial Officer of Suncor Energy Inc. (December 1999 to
June 2002) and prior to December 1999 was Executive Vice-President of Sunoco
Inc., a wholly-owned subsidiary of Suncor Energy Inc.; and (d) Mr. Russell who
prior to January 1998 was President and Chief Operating Officer of Chauvco
Resources Ltd.
OFFICERS
The name, municipality of residence, position held and holdings of
Trust Units by each officer of PrimeWest on the date hereof are set out below:
TRUST UNITS BENEFICIALLY OWNED OR
OVER WHICH CONTROL OR DISCRETION IS
EXERCISED AS
NAME AND MUNICIPALITY PRINCIPAL OCCUPATION AT DECEMBER 31, 2002(1)
- --------------------- -------------------- -----------------------
Donald A. Garner President and Chief Executive Officer 5,303
Calgary, Alberta Since January 2003
Timothy S. Granger Chief Operating Officer 900
Calgary, Alberta Since January 2003
Ronald J. Ambrozy Vice-President, Business Development 11,915
Calgary, Alberta Since October 1997
Dennis G. Feuchuk Vice-President, Finance and Chief Financial 11,875
Calgary, Alberta Officer
Since October 2001
James T. Bruvall Partner, Stikeman Elliott LLP 18,787
Calgary, Alberta (Secretary of PrimeWest since October 1996)
NOTE:
1. Includes holdings of Class A Exchangeable Shares.
DONALD A. GARNER, PRESIDENT AND CHIEF EXECUTIVE OFFICER
Mr. Garner joined PrimeWest in June 2001 and has overall responsibility
for leading and overseeing the business direction of the day-to-day business and
operations. He has more than 24 years experience in the oil and gas industry. He
was President and Chief Operating Officer of Northstar Energy Corporation from
January 1998 to February 2001. Prior to that Mr. Garner spent a good portion of
his career at Imperial Oil Limited in various capacities, including executive
responsibility for the Oilsands Business Unit.
An engineering graduate of the University of Saskatchewan, Mr. Garner
has undertaken postgraduate studies through the Wharton School, The American
Graduate School of International Management and University of Calgary.
TIMOTHY S. GRANGER, CHIEF OPERATING OFFICER
Mr. Granger joined PrimeWest in June 1999 and has overall
responsibility for the day-to-day business and operations of PrimeWest. Mr.
Granger has more than 22 years
48
of extensive experience in exploitation, production operations and asset
management. From 1996 to 1999, Mr. Granger held various managerial positions at
Pogo Canada Ltd. and 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.
RONALD J. AMBROZY, VICE-PRESIDENT, BUSINESS DEVELOPMENT
Mr. Ambrozy has over 28 years of experience in the petroleum and
natural gas industry. Prior to joining PrimeWest 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.
DENNIS G. FEUCHUK, VICE-PRESIDENT, FINANCE AND CHIEF FINANCIAL OFFICER
Mr. Feuchuk joined PrimeWest in October 2001 and is responsible for the
general financial operations of PrimeWest including tax and accounting matters.
Mr. Feuchuk has over 27 years of experience in finance, accounting, audit and
income tax in the oil and natural gas industry. He was Vice President,
Controller of Gulf Canada Resources from February 1995 to February 2001. Mr.
Feuchuk also was Vice President and Treasurer of Athabasca Oil Sands Trust from
inception in December 1995 to February 2001. Mr. Feuchuk has a Bachelor of
Business Management from Ryerson University and has completed the Richard Ivey
School of Business Executive Development Program and is a Certified Management
Accountant.
EMPLOYEES
As of December 31, 2002, PrimeWest had 144 employees.
POTENTIAL CONFLICTS OF INTEREST
Mr. Emes, a director of PrimeWest, and Mr. Bruvall, the Secretary of
PrimeWest, are partners in a law firm which provides services to PrimeWest.
The Board of Directors of PrimeWest does not believe that any of the
activities set forth above and undertaken by such individuals interferes in any
way with their ability to act in their respective capacities for PrimeWest and
with a view to the best interests of PrimeWest.
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
49
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,
2002, 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, 2002 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, 2002 and a copy of the Circular dated April 1,
2003.
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 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.
50
DEFINITIONS
In this Annual Information Form, the capitalized terms set forth below
have the following meanings:
ANNUAL REPORT means the 2002 Annual Report of PrimeWest Energy Trust filed on
SEDAR at WWW.SEDAR.COM.
ARTC means Alberta royalty tax credit.
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, to be
dated on or about April 1, 2003.
CLASS A EXCHANGEABLE SHARES means class A exchangeable shares in the capital of
PrimeWest.
COMPUTERSHARE means Computershare Trust Company of Canada.
CONSOLIDATION means the consolidation of the Trust Units on a one for four
basis, effective August 16, 2002.
CREDIT FACILITY means a bank syndication of Canadian chartered banks offering a
maximum borrowing capability of $490 million.
CYPRESS means Cypress Energy Inc.
DECLARATION OF TRUST means the declaration of trust dated August 2, 1996 among
the Trustee, PrimeWest and the Initial Unitholder (as therein defined), as
amended and restated as of October 26, 2001, as amended from time to time.
DISTRIBUTABLE INCOME means all amounts received by the Trust in respect of the
Royalty, ARTC and other income, less certain expenses and other deductions.
DRIP means the Distribution Reinvestment Plan 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 by or in respect of PrimeWest, the Trust or the
Royalty or in the management and administration of PrimeWest, the Trust or the
Royalty.
GILBERT means Gilbert Laustsen Jung Associates Ltd.
51
GILBERT REPORT means the reserve report prepared by Gilbert evaluating the crude
oil, natural gas, natural gas liquids and sulphur reserves attributable to
properties owned by PrimeWest and the Trust as at January 1, 2003.
MANAGER means PrimeWest Management Inc.
NEB means National Energy Board.
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
(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.
52
OIL & GAS means PrimeWest Oil and Gas Corp.
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 the Trust.
PRIMEWEST ROYALTY means PrimeWest Royalty 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, 2002.
RESOURCES means PrimeWest Resources Ltd.
RIGHTS PLAN means the Unitholder Rights Plan of the Trust which is embodied in
the Unitholder Rights Plan Agreement dated as of March 31, 1999 between the
Trust and the Trust Company of Bank of Montreal as rights agent, as amended and
restated as of April 5, 2002 between the Trust and Computershare.
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 amended and restated royalty agreement dated January
1, 2002 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.
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, 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
53
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 Computershare, or its successor as trustee of the Trust.
UNITHOLDERS means the holders from time to time of one or more Trust Units.
VENATOR means Venator Petroleum Company Ltd.
54
SCHEDULE A
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 (signed) Ernst & Young LLP
April 16, 2001 Chartered Accountants
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
A-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
A-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
A-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
A-5
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.
A-6
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.
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.
A-7
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:
A-8
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
================================================================================
1) 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).
A-9
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 counterpart 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.
A-10
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 558 5,580
of year 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).
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.
A-11
(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 - $0.6 million).
STOCK OPTIONS
The Company has established a stock option plan whereby options may be granted
to its directors, officers and employees. The exercise price of each option
equals the market price of the Company's stock on the date of the grant and an
option's maximum term is five years. The stock options are exercisable over a
five-year period from the date of grant. The options are exercisable on a
cumulative basis of 20 percent immediately and 20 percent per year for each of
the first four years of the plan. No compensation expense is recognized for the
plan when stock options are issued or exercised. The following is a continuity
of stock options outstanding for which shares have been reserved:
A-12
2000 1999 1998
- -------------------------------------------------------------------------------------------------------------------------
WEIGHTED WEIGHTED
AVERAGE AVERAGE WEIGHTED
EXERCISE EXERCISE AVERAGE
SHARES PRICE SHARES PRICE SHARES EXERCISE
(000S) ($) (000S) ($) (000S) PRICE
- -------------------------------------------------------------------------------------------------------------------------
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.
A-13
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.
A-14
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, less 3% September 30, 2003
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.
A-15
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.
A-16
DOCUMENT 2
----------
MANAGEMENT RESPONSIBILITY FOR FINANCIAL STATEMENTS AND MANAGEMENT'S DISCUSSION
AND ANALYSIS
The consolidated financial statements of PrimeWest Energy Trust and Management's
Discussion and Analysis (MD&A) were prepared by, and are the responsibility of,
the management of PrimeWest Energy Inc. The consolidated financial statements
have been prepared in accordance with accounting principles generally accepted
in Canada. The financial and operating information presented in this annual
report is consistent with that shown in the consolidated financial statements.
Management has designed and maintains a system of internal controls to safeguard
assets and ensure that transactions are properly authorized and recorded and
form part of these financial statements. Where estimates are used in the
preparation of these financial statements, management has ensured that careful
judgement has been made and that these estimates are reasonable, based on all
information known at the time the estimates are made.
The Board of Directors of PrimeWest is responsible for ensuring that management
fulfills its responsibilities for financial reporting, and it has reviewed and
approved these financial statements and MD&A. The Board carries out this
responsibility through the audit and reserves committee, which consists of the
independent directors of the Board.
Unitholders have appointed the external audit firm of PricewaterhouseCoopers LLP
to express their opinion on the consolidated financial statements. The auditors
have full and unrestricted access to the audit and reserves committee to discuss
their findings.
((signed)) ((signed))
Don Garner Dennis G. Feuchuk
PRESIDENT AND CHIEF EXECUTIVE OFFICER VICE-PRESIDENT, FINANCE AND
FEBRUARY 7, 2003 CHIEF FINANCIAL OFFICER
AUDITORS' REPORT
To the unitholders of PrimeWest Energy Trust:
We have audited the consolidated balance sheets of PrimeWest Energy Trust as at
December 31, 2002, 2001 and 2000 and the consolidated statements of income, cash
distributions, unitholders' equity, and cash flows for the years then ended.
These financial statements are the responsibility of the management of the
Trust. 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 from 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 Trust as at December 31, 2002,
2001 and 2000, and the results of its operations and cash flows for the years
then ended, in accordance with Canadian generally accepted accounting
principles.
((signed))
PricewaterhouseCoopers LLP, CHARTERED ACCOUNTANTS
CALGARY, ALBERTA
FEBRUARY 7, 2003
CONSOLIDATED BALANCE SHEETS
As at December 31 (thousands of Canadian dollars) 2002 2001 2000
- -----------------------------------------------------------------------------------------------------------------
ASSETS
Current Assets
Accounts Receivable $ 71,635 $ 60,609 $ 40,561
Prepaid Expenses 9,759 9,112 4,398
Inventory 2,204 3,173 840
- -----------------------------------------------------------------------------------------------------------------
83,598 72,894 45,799
Cash Reserved for Site Restoration
and Reclamation (NOTE 7) 12 755 398
Property, Plant and Equipment (NOTE 4) 1,404,463 1,448,661 395,376
Other Assets (NOTE 5) 14,179 -- --
- -----------------------------------------------------------------------------------------------------------------
$ 1,502,252 $ 1,522,310 $ 441,573
=================================================================================================================
LIABILITIES AND UNITHOLDERS' EQUITY
Current Liabilities
Bank Overdraft $ 3,057 $ 14,613 $ 834
Accounts Payable 43,109 26,207 19,057
Accrued Liabilities 23,950 39,350 13,440
Accrued Distributions to Unitholders 13,918 11,980 9,961
Due to Related Company (NOTE 10) -- 10,108 2,057
Current Portion of Long-term Debt (NOTE 6) -- 67 106
- -----------------------------------------------------------------------------------------------------------------
84,034 102,325 45,455
Long-term Debt (NOTE 6) 225,000 195,000 78,940
Future Income Taxes (NOTE 11) 339,888 362,595 16,596
Site Restoration and
Reclamation Provision (NOTE 7) 6,232 6,113 1,958
- -----------------------------------------------------------------------------------------------------------------
655,154 666,033 142,949
Unitholders' Equity
Net Capital Contributions (NOTE 8) 1,299,968 1,152,551 435,342
Capital Issued but Not Distributed 884 1,035 614
Long-Term Incentive Plan Equity (NOTE 9) 10,068 7,932 8,930
Accumulated Income 123,170 122,550 43,014
Accumulated Cash Distributions (578,934) (420,983) (186,518)
Accumulated Dividends (8,058) (6,808) (2,758)
847,098 856,277 298,624
- -----------------------------------------------------------------------------------------------------------------
$ 1,502,252 $ 1,522,310 $ 441,573
=================================================================================================================
Commitments and Contingencies (NOTE 13)
The accompanying notes form an integral part of these financial statements.
((signed)) ((signed))
Harold P. Milavsky Don Garner
CHAIRMAN OF THE BOARD OF DIRECTORS PRESIDENT AND CHIEF EXECUTIVE OFFICER
CONSOLIDATED STATEMENTS OF UNITHOLDERS' EQUITY
For the Years Ended December 31
(thousands of Canadian dollars) 2002 2001 2000
- -----------------------------------------------------------------------------------------------------------------
Unitholders' Equity - Beginning of Year,
as previously reported $ 856,277 $ 298,624 $ 200,039
Future Income Tax
Accounting Change (NOTE 11) -- -- (10,219
Net Income for the Year 620 79,536 55,612
Capital Contributions, Net of Costs 147,417 717,209 124,293
Cash Distributions (157,951) (234,465) (79,033)
Dividends (1,250) (4,050) (1,612)
Long-Term Incentive Plan Equity 2,136 (998) 8,930
Capital Issued but Not Distributed (151) 421 614
- -----------------------------------------------------------------------------------------------------------------
Unitholders' Equity - End of Year $ 847,098 $ 856,277 $ 298,624
=================================================================================================================
The accompanying notes form an integral part of these financial statements.
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31
(thousands of Canadian dollars,
except per Trust Unit amounts) 2002 2001 2000
- -----------------------------------------------------------------------------------------------------------------
REVENUES
Sales of Crude Oil, Natural Gas
& Natural Gas Liquids $ 320,517 $ 378,155 $ 191,339
Crown & Other Royalties, Net of ARTC (56,496) (73,156) (35,157)
Other Income 227 1,516 379
- -----------------------------------------------------------------------------------------------------------------
264,248 306,515 156,561
EXPENSES
Depletion, Depreciation & Amortization 181,956 159,332 42,865
Operating 60,773 58,951 30,174
General & Administrative 11,281 10,394 4,140
Unit Appreciation Rights 6,125 4,158 10,296
Interest 10,788 13,800 6,359
Cash Management Fees (NOTE 10) 3,982 6,431 3,277
Non-Cash Management Fees (NOTE 10) 1,414 1,819 731
Cash Internalization Costs 3,598 -- --
Non-Cash Internalization Costs (NOTE 10) 13,124 -- --
- -----------------------------------------------------------------------------------------------------------------
293,041 254,885 97,842
- -----------------------------------------------------------------------------------------------------------------
Income/(Loss) Before Taxes for the Year (28,793) 51,630 58,719
- -----------------------------------------------------------------------------------------------------------------
Income and Capital Taxes 2,887 2,428 549
Future Taxes (Recovery) (NOTE 11) (32,300) (30,334) 2,558
- -----------------------------------------------------------------------------------------------------------------
(29,413) (27,906) 3,107
- -----------------------------------------------------------------------------------------------------------------
Net Income $ 620 $ 79,536 $ 55,612
- -----------------------------------------------------------------------------------------------------------------
NET INCOME PER TRUST UNIT
Basic $ 0.02 $ 3.12 $ 5.00
Diluted $ 0.02 $ 3.08 $ 4.84
=================================================================================================================
The accompanying notes form an integral part of these financial statements.
CONSOLIDATED STATEMENTS OF CASH DISTRIBUTIONS
For the Years Ended December 31
(thousands of Canadian dollars,
except per Trust Unit amounts) 2002 2001 2000
- -----------------------------------------------------------------------------------------------------------------
Net Income for the Year $ 620 $ 79,536 $ 55,612
Add Back (Deduct)
Depletion, Depreciation & Amortization 181,956 159,332 42,865
Cash (Retained)/Paid from Cash
Available for Distribution (7,315) 25,822 (29,266)
Contribution to Reclamation Fund (4,078) (3,499) (2,964)
Management Fees Paid in Trust Units 1,414 1,819 731
Internalization Costs Paid in Trust Units 13,124 -- --
Unit Appreciation Rights Expense 6,125 4,158 10,296
Future Income Taxes (Recovery) (32,300) (30,334) 2,558
- -----------------------------------------------------------------------------------------------------------------
$ 159,546 $ 236,834 $ 79,832
=================================================================================================================
Cash Distributions to Trust Unitholders (99%) $ 157,951 $ 234,465 $ 79,033
=================================================================================================================
Cash Distributions per Trust Unit (1) $ 4.80 $ 9.24 $ 7.08
=================================================================================================================
(1) After giving effect to 4 for 1 Trust Unit consolidation on August 16, 2002.
The accompanying notes form an integral part of these financial statements.
CONSOLIDATED STATEMENTS OF CASH FLOW
For the Years Ended December 31
(thousands of Canadian dollars) 2002 2001 2000
- -----------------------------------------------------------------------------------------------------------------
OPERATING ACTIVITIES
Net Income for the Year $ 620 $ 79,536 $ 55,612
Add: (Deduct) Items Not Involving
Cash Flow from Operations
Depletion, Depreciation & Amortization 181,956 159,332 42,865
Non-Cash Internalization Costs 13,124 -- --
Unit Appreciation Rights Expense 6,125 4,158 10,296
Non-Cash Management Fees 1,414 1,819 731
Future Income Taxes (32,300) (30,334) 2,558
- -----------------------------------------------------------------------------------------------------------------
Cash Flow from Operations 170,939 214,511 112,062
Expenditures on Site Restoration
& Reclamation (NOTE 7) (3,909) (3,769) (3,561)
Change in Non-Cash Working Capital (10,729) (20,487) (15,570)
- -----------------------------------------------------------------------------------------------------------------
156,301 190,255 92,931
- -----------------------------------------------------------------------------------------------------------------
FINANCING ACTIVITIES
Proceeds from Issue of Trust Units,
Net of Costs 118,333 159,542 38,036
Acquisition of Trust Units pursuant to
Normal Course Issuer Bid -- -- (926)
Cash Distributions to Unitholders (145,887) (223,658) (77,173)
Dividends Paid (1,250) (602) (1,612)
Increase (Decrease) in Long-Term Debt 29,933 (62,980) (41,449)
Change in Non-Cash Working Capital 1,797 2,019 6,291
- -----------------------------------------------------------------------------------------------------------------
2,926 (125,679) (76,833)
- -----------------------------------------------------------------------------------------------------------------
INVESTING ACTIVITIES
Expenditures on Property,
Plant and Equipment (69,055) (84,206) (25,791)
Acquisition of Capital/
Corporate Assets (NOTES 3 AND 10) (59,606) (84,054) (6,306)
Proceeds on Disposition of Property,
Plant and Equipment 4,529 78,144 855
Expenditures for Future Acquisition (NOTE 5) (14,179) -- --
Cash Reserved for Future Site
Restoration & Reclamation 743 (357) 661
Proceeds on Disposition of
Short-Term Investments -- -- 174
Change in Non-Cash Working Capital (10,103) 12,118 7,971
- -----------------------------------------------------------------------------------------------------------------
(147,671) (78,355) (22,436)
- -----------------------------------------------------------------------------------------------------------------
INCREASE (DECREASE) IN CASH FOR THE YEAR 11,556 (13,779) (6,338)
CASH (BANK OVERDRAFT), BEGINNING OF YEAR (14,613) (834) 5,504
- -----------------------------------------------------------------------------------------------------------------
(BANK OVERDRAFT), END OF YEAR $ (3,057) $ (14,613) $ (834)
=================================================================================================================
CASH INTEREST PAID $ 10,275 $ 13,159 $ 6,872
=================================================================================================================
CASH TAXES PAID $ 3,960 $ 460 $ 453
=================================================================================================================
The accompanying notes form an integral part of these financial statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (all amounts are expressed in
thousands of Canadian dollars unless otherwise indicated)
1. Structure Of The Trust
PrimeWest Energy Trust (the Trust) is an open-ended investment trust
formed under the laws of Alberta in accordance with a declaration of
trust dated August 2, 1996. The beneficiaries of the Trust are the
holders of Trust Units (the unitholders).
The common shares of PrimeWest Energy Inc. (PrimeWest) are 100% owned
by the Trust.
The principal undertaking of the Trust's operating company, PrimeWest,
is to acquire and hold, directly and indirectly, interests in oil and
gas properties. One of the Trust's primary assets is a royalty
entitling it to receive 99% of the net cash flow generated by the oil
and gas interests owned by PrimeWest. The royalty acquired by the Trust
effectively transfers substantially all of the economic interest in the
properties to the Trust.
On November 4, 2002, unitholders voted, by a 92% majority, to
internalize management. PrimeWest Management Inc. received a total of
$26.3 million. Approximately $13.2 million related to the acquisition
of the 1% retained royalty and was recorded as an acquisition in
property, plant and equipment. The balance was charged to non-cash
internalization expense. In addition, retention provisions for senior
management totaling $3.5 million were agreed to and $1.5 million was
accrued relating to the termination of the management incentive program
(see Note 10).
2. Accounting Policies
CONSOLIDATION
These consolidated financial statements include the accounts of the
Trust and its wholly-owned subsidiaries, PrimeWest, PrimeWest
Management Inc., and PrimeWest Gas Inc. The Trust, through the royalty,
obtains substantially all of the economic benefits of the operations of
PrimeWest. In addition, the unitholders of the Trust elect the Board of
Directors of PrimeWest.
CASH AND SHORT TERM INVESTMENTS
Short term investments, with maturities less than three months at date
of acquisition, are considered to be cash equivalents and are recorded
at cost, which approximates market value.
INVENTORY
Inventory is measured at lower of cost and net realizable value.
PROPERTY, PLANT AND EQUIPMENT
PrimeWest follows the full cost method of accounting. All costs of
acquiring oil and gas properties and related development costs are
capitalized and accumulated in one cost centre. Maintenance and repairs
are charged against earnings. Renewals and enhancements that extend the
economic life of the capital asset are capitalized.
Gains and losses are not recognized on disposition of oil and gas
properties unless that disposition would alter the rate of depletion by
20% or more.
I) CEILING TEST
PrimeWest places a limit on the aggregate cost of capital assets which
may be carried forward for depletion against net revenues of future
periods (the ceiling test). The ceiling test is a cost recovery test
whereby; capitalized costs, less accumulated depletion and site
restoration, the lower of cost and market value of unproved land and
future income taxes,
are limited to an amount equal to estimated undiscounted future net
revenues from proved reserves, less general and administrative
expenses, site restoration, future financing costs and applicable
income taxes. Costs and prices at the balance sheet date are used. Any
costs carried on the balance sheet in excess of the ceiling test
limitation are charged to income.
II) SITE RESTORATION AND RECLAMATION PROVISION
PrimeWest provides for the cost of future site restoration and
reclamation, based on estimates by management, using the
unit-of-production method. Actual site-restoration costs are charged
against the accumulated liability. PrimeWest places cash in reserve to
fund actual expenditures as they are incurred.
III) DEPLETION, DEPRECIATION AND AMORTIZATION
Provision for depletion and depreciation is calculated on the
unit-of-production method, based on proved reserves before royalties.
Reserves are estimated by independent petroleum engineers. Reserves are
converted to equivalent units on the basis of approximate relative
energy content. Depreciation and amortization of head office furniture
and equipment is provided for at rates ranging from 10% to 30%.
JOINT VENTURE ACCOUNTING
PrimeWest conducts substantially all of its oil and gas production
activities through joint ventures, and the accounts reflect only
PrimeWest's proportionate interest in such activities.
LONG-TERM INCENTIVE PLAN
Liabilities under the Trust's Long-term Incentive Plan are estimated at
each balance sheet date, based on the amount of Unit Appreciation
Rights that are in the money using the unit price as at that date.
Expenses are recorded through non-cash general and administrative
costs, with an offsetting amount in long-term incentive plan equity. As
Trust Units are issued under the plan, the exercise value is recorded
in net capital contributions.
INCOME TAXES
The Trust is considered an inter-vivos trust for income tax purposes.
As such, the Trust is subject to tax on any taxable income that is not
allocated to the unitholders. Periodically, current taxes may be
payable by PrimeWest, depending upon the timing of income tax
deductions. Should these taxes prove to be unrecoverable, they will be
deducted from royalty income in accordance with the royalty agreement.
Future income taxes are recorded for PrimeWest using the liability
method of accounting. Future income taxes are recorded to the extent
that the carrying value of PrimeWest's capital assets exceeds the
available tax pools.
FINANCIAL INSTRUMENTS
PrimeWest uses financial instruments to manage its exposure to
fluctuations in commodity prices and interest rates. PrimeWest does not
use financial instruments for speculative trading purposes and,
accordingly, they are accounted for as hedges. Gains and losses on
hedging activity are reflected in revenue, or in the case of interest
rate hedges, in interest expense, at the time of sale of the related
hedged production, or when the monthly exchange contracts expire.
MEASUREMENT UNCERTAINTY
Certain items recognized in the financial statements are subject to
measurement uncertainty. The recognized amounts of such items are based
on PrimeWest's best information and judgement. Such amounts are not
expected to change materially in the near term. They include:
o the amounts recorded for depletion, depreciation
and future site restoration costs which depend on
estimates of oil and gas reserves or the economic
lives and future cash flows from related assets;
and
o the amounts recorded for assets and liabilities
of acquired companies which depend on estimates
of their fair values on the acquisition date.
3. Corporate Acquisitions
a) On March 29, 2001, PrimeWest Oil & Gas Corp. (Oil & Gas) completed
the acquisition of all of the issued and outstanding shares of Cypress
Energy Inc. (Cypress) pursuant to a takeover bid. In aggregate,
PrimeWest issued 50.2 million Trust Units and PrimeWest issued 5.2
million exchangeable shares of Oil & Gas and paid $59.2 million in
exchange for the shares of Cypress. Subsequent to the transaction,
Cypress and Oil & Gas were amalgamated. The acquisition was accounted
for using the purchase method of accounting with net assets acquired
and consideration paid as follows:
NET ASSETS ACQUIRED AT ASSIGNED VALUES CONSIDERATION PAID
---------------------------------------------------------------------------------------------------------
Petroleum and natural gas assets $ 1,201,485
Working capital (deficit) assumed (19,174) Cash $ 59,235
Long-term debt assumed (179,000) Trust Units issued 489,815
Site restoration provision (4,307) Exchangeable shares issued 50,254
Future income taxes (376,334) Costs associated with acquisition 23,366
---------------------------------------------------------------------------------------------------------
$ 622,670 $ 622,670
=========================================================================================================
b) On April 19, 2000, PrimeWest Resources Ltd. (Resources) completed
the acquisition of all of the issued and outstanding shares of Venator
Petroleum Company Limited (Venator) on a unit/share for share exchange.
Resources issued 0.657 Trust Units or 0.657 exchangeable shares for
each Venator share. In aggregate, 2.4 million Trust Units and 2.0
million exchangeable shares were issued for total consideration,
including debt assumed, of $32.5 million.
Subsequent to the transaction, the assets of Venator were transferred
to Resources and Venator was dissolved. The acquisition was accounted
for using the purchase method of accounting with the purchase price
allocated as follows:
NET ASSETS ACQUIRED AT ASSIGNED VALUES CONSIDERATION PAID
---------------------------------------------------------------------------------------------------------
Petroleum and natural gas assets $ 34,392 Trust Units issued $ 15,637
Working capital (deficit) assumed (2,323) Exchangeable shares issued 13,282
Future income taxes (1,898) Costs associated with acquisition 1,252
---------------------------------------------------------------------------------------------------------
$ 30,171 $ 30,171
=========================================================================================================
c) On July 27, 2000, PrimeWest Royalty Corp. (Royalty Corp.) completed
the acquisition of all of the issued and outstanding shares of Reserve
Royalty Corporation on a unit for share exchange. Royalty Corp. issued
0.65 Trust Units for each Reserve Royalty share. In aggregate, 6.67
million Trust Units were issued for total consideration, including debt
assumed, of $84.0 million. Subsequent to the transaction, Reserve
Royalty was amalgamated into Royalty Corp. and the majority of its
assets transferred to the Trust. The acquisition was accounted for
using the purchase method of accounting with the purchase price
allocated as follows:
NET ASSETS ACQUIRED AT ASSIGNED VALUES CONSIDERATION PAID
---------------------------------------------------------------------------------------------------------
Petroleum and natural gas assets $ 85,860
Working capital assumed 1,049
Long-term debt assumed (28,210) Trust Units issued $ 53,947
Future income taxes (1,921) Costs associated with acquisition 2,831
---------------------------------------------------------------------------------------------------------
$ 56,778 $ 56,778
=========================================================================================================
As of January 1, 2002, Oil & Gas, Resources and Royalty Corp. were
amalgamated with PrimeWest.
4. Property, Plant and Equipment
2002
----------------------------------------------------------------------------------------
ACCUMULATED
DEPLETION,
DEPRECIATION AND NET BOOK
COST AMORTIZATION VALUE
----------------------------------------------------------------------------------------
PROPERTY ACQUISITION OIL AND GAS RIGHTS $ 1,682,592 $ (430,636) $ 1,251,956
DRILLING AND COMPLETION 139,885 (34,684) 105,201
PRODUCTION FACILITIES AND EQUIPMENT 60,497 (15,395) 45,102
HEAD OFFICE FURNITURE AND EQUIPMENT 5,209 (3,005) 2,204
----------------------------------------------------------------------------------------
$ 1,888,183 $ (483,720) $ 1,404,463
========================================================================================
2001
----------------------------------------------------------------------------------------
ACCUMULATED
DEPLETION,
DEPRECIATION AND NET BOOK
COST AMORTIZATION VALUE
----------------------------------------------------------------------------------------
Property acquisition oil and gas rights $ 1,608,435 $ (268,137) $ 1,340,298
Drilling and completion 103,583 (24,074) 79,509
Production facilities and equipment 38,198 (11,537) 26,661
Head office furniture and equipment 4,238 (2,045) 2,193
----------------------------------------------------------------------------------------
$ 1,754,454 $ (305,793) $ 1,448,661
========================================================================================
2000
----------------------------------------------------------------------------------------
ACCUMULATED
DEPLETION,
DEPRECIATION AND NET BOOK
COST AMORTIZATION VALUE
----------------------------------------------------------------------------------------
Property acquisition oil and gas rights $ 474,091 $ (135,256) $ 338,835
Drilling and completion 51,769 (10,216) 41,553
Production facilities and equipment 16,397 (3,249) 13,148
Head office furniture and equipment 3,199 (1,359) 1,840
----------------------------------------------------------------------------------------
$ 545,456 $ (150,080) $ 395,376
========================================================================================
Unproved land costs of $ 44.2 million (2001 - $55.7 million, 2000 -
$17.2 million) are excluded from costs subject to depletion and
depreciation.
PrimeWest capitalized $3.8 million of general and administrative costs
in 2002 ($2.2 million in 2001; $0.9 million in 2000).
In accordance with stated accounting policies, PrimeWest has performed
a ceiling test using commodity prices as at the measurement date of
December 31, 2002. Using December 31, 2002 commodity prices of AECO
$5.59 per mcf for natural gas and WTI $US 29.39 per barrel for crude
oil, results in a ceiling test surplus of $900 million.
At December 31, 2001, PrimeWest performed its ceiling test using
commodity prices as at that measurement date of AECO $3.67 per mcf for
natural gas and WTI $US 19.84 per barrel for crude oil. The ceiling
test resulted in a deficiency of $150 million. PrimeWest did not record
a writedown at this time as the writedown occurred within the first two
years of the acquisition of Cypress.
5. Other Assets
2002 2001 2000
----------------------------------------------------------------------------------------
Deposit on acquisition $ 10,850 $ -- $ --
Expenditures incurred on acquisition 3,329 -- --
----------------------------------------------------------------------------------------
$ 14,179 $ -- $ --
========================================================================================
Other assets include expenditures required to effect the acquisition of
all of the issued and outstanding shares of two private Canadian
companies on January 23, 2003 (see Note 14).
6. Long -Term Debt
2002 2001 2000
----------------------------------------------------------------------------------------
Revolving credit facility $ 225,000 $ 195,000 $ 78,879
Capital lease obligation -- -- 61
----------------------------------------------------------------------------------------
225,000 195,000 78,940
Current portion -- 67 106
----------------------------------------------------------------------------------------
$ 225,000 $ 195,067 $ 79,046
========================================================================================
PrimeWest and the Trust (as co-borrowers) have a combined revolving
credit facility in the amount of $335 million (2001 - $350 million;
2000 - $150 million), with a borrowing base at December 31, 2002 of
$335 million (2001 - $350 million; 2000 - $150 million). The facility
consists of a revolving term loan of $310 million and an operating
facility of $25 million. The facility and borrowing base increased to
$390 million on January 23, 2003 upon the completion of the acquisition
of two private Canadian companies. In addition, PrimeWest had $100
million of bridge financing which was drawn on January 23, 2003 and was
repaid in February 2003 upon completion of the equity offering (see
Note 14). In addition to amounts outstanding under the facility as
indicated in the table above, PrimeWest has outstanding letters of
credit in the amount of $3.8 million (2001 - $2.8 million; 2000 - $4.3
million). Collateral for the credit facility is provided by a
floating-charge debenture covering all existing and after acquired
property in the principal amount of $750 million. Each borrower under
the facility has also provided an unconditional full liability
guarantee in respect of amounts borrowed under the facility.
Advances under the facility are made in the form of Banker's
Acceptances (BA), prime rate loans or letters of credit. In the case of
BA, interest is a function of the BA rate plus a stamping fee based on
the Trust's current ratio of debt to cash flow. In the case of prime
rate loans, interest is charged at the bank's prime rate. While any
amounts are outstanding under the bridge facility the interest rates
and stamping fees increase by 50 basis points. For 2002, the effective
interest rate was 4.6% (2001 5.6%, 2000 - 7.5%)
The credit facility revolves until April 30, 2003, by which time the
lender will have conducted its annual borrowing base review. The lender
also has the right to re-determine the borrowing base at one other time
during the year. During the revolving phase, the
facility has no specific terms of repayment. At the end of the
revolving period, the lender has the right to extend the revolving
period for a further 364-day period or to convert the facility to a
term facility. If the lender converts to a non-revolving facility 60%
of the aggregate principal amount of the loan shall be repayable on the
date which is 366 days after such conversion date and the remaining 40%
of the aggregate principal amount outstanding shall be repayable on the
date which is 365 days after the initial term repayment date.
7. Cash Reserve For Site Restoration And Reclamation
Commencing in 1998, funding for the reserve was provided for by
reducing distributions otherwise payable based on an amount per BOE
produced ($0.15 per BOE produced for 1998 and 1999, $0.24 per BOE
produced in 2000, $0.32 per BOE produced in 2001 and $0.37 per BOE
produced in 2002). The cash amount contributed, including interest
earned, was $4.1 million in 2002 (2001 - $4.2 million; 2000 - $3.0
million). Actual costs of site restoration and abandonment totaling
$3.9 million were paid out of this cash reserve for the year ended
December 31, 2002 (2001 - $3.8 million; 2000 - $3.6 million).
8. Unitholders' Equity
PrimeWest Energy Trust
The authorized capital of the Trust consists of an unlimited number of
Trust Units.
TRUST UNITS NUMBER OF UNITS AMOUNTS
($000'S)
-----------------------------------------------------------------------------------------
Balance, December 31, 1999 35,768,801 $ 311,049
Issued for cash 4,830,000 40,331
Issue expenses -- (2,741)
Retired pursuant to Normal Course Issuer Bid (141,900) (926)
Issued to acquire Venator Petroleum Company Ltd 2,368,936 15,637
Issued to acquire Reserve Royalty Corporation 6,660,082 53,947
Issued for payment of management fees 82,203 616
Issued on exchange of exchangeable shares 922,073 5,940
Issued pursuant to Distribution Reinvestment Plan 215,035 1,860
Issued pursuant to Long-Term Incentive Plan 226,423 1,841
Issued pursuant to Optional Trust Unit Purchase Plan 50,440 447
-----------------------------------------------------------------------------------------
Balance, December 31, 2000 50,982,093 $ 428,001
Issued for cash 19,790,000 165,234
Issue expenses -- (9,013)
Issued to acquire Cypress Energy Inc. 50,234,771 489,815
Issued for payment of management fees 199,841 1,635
Issued on exchange of exchangeable shares 2,415,363 20,298
Issued pursuant to Distribution Reinvestment Plan 1,623,171 10,807
Issued pursuant to Long-Term Incentive Plan 577,840 5,155
Issued pursuant to Optional Trust Unit Purchase Plan 142,528 3,321
-----------------------------------------------------------------------------------------
Balance, December 31, 2001 125,965,607 $ 1,115,253
8. Unitholders' Equity
PrimeWest Energy Trust
The authorized capital of the Trust consists of an unlimited number of
Trust Units.
Trust Units Number of Units Amounts
($000's)
-----------------------------------------------------------------------------------------
Balance, December 31, 1999 35,768,801 $ 311,049
Issued for cash 4,830,000 40,331
Issue expenses -- (2,741)
Retired pursuant to Normal Course Issuer Bid (141,900) (926)
Issued to acquire Venator Petroleum Company Ltd 2,368,936 15,637
Issued to acquire Reserve Royalty Corporation 6,660,082 53,947
Issued for payment of management fees 82,203 616
Issued on exchange of exchangeable shares 922,073 5,940
Issued pursuant to Distribution Reinvestment Plan 215,035 1,860
Issued pursuant to Long-Term Incentive Plan 226,423 1,841
Issued pursuant to Optional Trust Unit Purchase Plan 50,440 447
-----------------------------------------------------------------------------------------
Balance, December 31, 2000 50,982,093 $ 428,001
Issued for cash 19,790,000 165,234
Issue expenses -- (9,013)
Issued to acquire Cypress Energy Inc. 50,234,771 489,815
Issued for payment of management fees 199,841 1,635
Issued on exchange of exchangeable shares 2,415,363 20,298
Issued pursuant to Distribution Reinvestment Plan 1,623,171 10,807
Issued pursuant to Long-Term Incentive Plan 577,840 5,155
Issued pursuant to Optional Trust Unit Purchase Plan 142,528 3,321
-----------------------------------------------------------------------------------------
Balance, December 31, 2001 125,965,607 $ 1,115,253
Restated giving effect for 4 to 1 Trust Unit
consolidation on August 16, 2002 31,491,402
Issued for cash 4,200,000 110,040
Issue expenses -- (5,641)
Issued for payment of management fees 66,853 1,832
Issued on exchange of exchangeable shares 106,934 2,698
Issued pursuant to Distribution Reinvestment Plan 476,106 10,126
Issued pursuant to Long-Term Incentive Plan 153,749 4,000
Issue of units due to odd lot program 111 -
Issue of fractional units due to 4 to 1 consolidation 6,264 -
Issued pursuant to Optional Trust Unit Purchase Plan 503,103 13,936
-----------------------------------------------------------------------------------------
BALANCE, DECEMBER 31, 2002 37,004,522 $ 1,252,244
=========================================================================================
The number of units was restated giving effect of four for one Trust
Unit consolidation effective August 16, 2002.
The weighted average number of Trust Units and exchangeable shares
outstanding in 2002 was 34,134,230 (2001 - 25,633,250; 2000 -
11,162,900). For purposes of calculating diluted net income per Trust
Unit, 341,315 Trust Units (2001 - 311,789; 2000 - 249,516) issuable
pursuant to the long-term incentive plan were added to the weighted
average number. The per unit cash distribution amounts paid or declared
reflects distributions paid or declared to Trust Units outstanding on
the record dates.
PRIMEWEST EXCHANGEABLE CLASS A SHARES
In connection with the Cypress transaction (see Note 3a), PrimeWest Oil
& Gas Corp. (now amalgamated with PrimeWest Energy Inc.) amended its
articles to create an unlimited number of exchangeable shares. The
exchangeable shares are exchangeable into PrimeWest Trust Units at any
time up to March 29, 2010, based on an exchange ratio that adjusts each
time the Trust makes distribution to its unitholders. The exchange
ratio, which was 1:1 on the date that the transaction closed, is based
on the total monthly distribution, divided by the closing unit price on
the distribution payment date. The exchange ratio on December 31, 2002
was 0.37454 (2001 - 0.3126:1) (restated effecting 4 to 1 Trust Unit
consolidation).
EXCHANGEABLE SHARES # OF SHARES AMOUNTS
($000'S)
-----------------------------------------------------------------------
Balance, December 31, 2000 -- $ --
Issued to acquire Cypress Energy Inc. 5,154,225 50,254
Exchanged for Trust Units (1,837,483) (17,916)
-----------------------------------------------------------------------
Balance, December 31, 2001 3,316,742 32,338
Issued for internalization 1,363,714 13,124
Conversion of Class B shares 710,795 4,287
Exchanged for Trust Units (211,973) (2,025)
-----------------------------------------------------------------------
BALANCE, DECEMBER 31, 2002 5,179,278 $ 47,724
=======================================================================
PRIMEWEST EXCHANGEABLE CLASS B SHARES
In connection with the Venator transaction (see Note 3b), PrimeWest
Resources Ltd. (now amalgamated with PrimeWest Energy Inc.) amended its
articles to create an unlimited number of exchangeable shares. At
special meetings held in May and June of 2002, holders of Class B
Exchangeable Shares and Class A Exchangeable shares voted to approve a
special resolution amending the articles of the Corporation to convert
all Class B Exchangeable shares to Class A Exchangeable Shares. As at
June 14, 2002, 649,561 Class B Exchangeable shares were converted to
Class A Exchangeable Shares using an exchange ratio of 1.09427:1.
EXCHANGEABLE SHARES # OF SHARES AMOUNTS
($000'S)
----------------------------------------------------------------------------------
Balance, December 31, 1999 -- $ --
Issued to acquire Venator Petroleum Company Ltd 2,012,422 13,282
Exchanged for Trust Units (900,052) (5,940)
----------------------------------------------------------------------------------
Balance, December 31, 2000 1,112,370 7,342
Exchanged for Trust Units (360,838) (2,382)
----------------------------------------------------------------------------------
Balance, December 31, 2001 751,532 4,960
Exchanged for Trust Units (101,971) (673)
Converted to Class A Exchangeable Shares (649,561) (4,287)
----------------------------------------------------------------------------------
BALANCE, DECEMBER 31, 2002 -- $ --
==================================================================================
NORMAL COURSE ISSUER BID
On November 29, 1999, the Trust received approval from the Toronto
Stock Exchange to make a normal course issuer bid. During 2000, the
Trust acquired 141,900 Trust Units pursuant to the bid at an average
cost of $6.53 per Trust Unit. This bid expired on November 29, 2000. On
December 15, 2000, the Trust received approval from the Toronto Stock
Exchange to renew its bid for a further one year period. During 2001,
no
purchases were made under the renewed bid. This bid expired on December
15, 2001 and was not renewed in 2002.
TRUST UNITS AND EXCHANGEABLE SHARES ISSUED & OUTSTANDING (1)
2002 2001 2000
- -----------------------------------------------------------------------------------------------------------------
Trust Units issued & outstanding 37,004,522 31,491,402 12,745,523
Exchangeable shares
PrimeWest Resources Ltd. (2)
(2001 - 751,532 shares exchangeable at 0.34201 -- 257,035 304,039
2000 - 1,112,370 shares exchangeable at 0.2733)
PrimeWest Oil and Gas Corp. (2)
(5,179,278 shares exchangeable at 0.37454;
2001 - 3,316,742 shares exchangeable at 0.3126) 1,939,864 1,036,648 --
- -----------------------------------------------------------------------------------------------------------------
Total units and exchangeable shares issued & outstanding 38,944,386 32,785,085 13,049,562
Unit Appreciation Rights 341,315 311,788 249,516
- -----------------------------------------------------------------------------------------------------------------
Total units and exchangeable shares issued
& outstanding - diluted 39,285,701 33,096,873 13,299,078
=================================================================================================================
(1) Restated Trust Units to give effect to 4 for 1 unit consolidation
effective August 16, 2002.
(2) Amalgamated with PrimeWest Energy Inc. effective January 1, 2002
9. Trust Unit Incentive Plan
Under the terms of the Trust Unit Incentive Plan, a maximum of 622,500
Trust Units are reserved for issuance pursuant to the exercise of Unit
Appreciation Rights (UARs) granted to employees of PrimeWest. Payouts
under the plan are based on total unitholder return, calculated using
both the change in the Trust Unit price as well as cumulative
distributions paid. The plan requires that a hurdle return of 5% per
annum be achieved before payouts accrue. UARs have a term of 6 years
and vest equally over a 3-year period, except for the independent
members of the Board, whose UARs vest immediately. The Board of
Directors has the option of settling payouts under the plan in
PrimeWest Trust Units or in cash. To date, all payouts under the plan
have been in the form of Trust Units.
Effective January 1, 2002, the method of accounting for the long-term
incentive plan was changed to comply with new CICA accounting standard
3870. The calculation of the long-term incentive liability now includes
vested and unvested UARs. Previously, only vested UARs were included.
In addition, the long-term incentive liability has been reclassified as
equity on the balance sheet as the Trust intends to settle the
liability in the form of Trust Units.
10. Related - Party Transactions
On September 26, 2002, the Trust announced the planned elimination,
effective October 1, 2002, of its external management structure and all
related management, acquisition and disposition fees, as well as the
acquisition of the right to mandatory quarterly dividends commonly
referred to as the "1% retained royalty". The transaction was approved
by the Unitholders and the holders of Exchangeable Shares on November
4, 2002 and closed November 6, 2002. The transaction resulted in the
elimination of the 2.5% management fee on net production revenue,
quarterly incentive payments payable in the form of Trust Units, the
1.5% acquisition fee and the 1.25% disposition fee, which resulted in
payments to PrimeWest Management Inc. in 2002 totaling $5.8 million
(2001 - $21.3 million; 2000 - $5.7 million). In addition, the amount of
the 1% retained royalty paid in 2002 was $1.3 million (2001 - $3.4
million; 2000 - $0.8 million).
As at December 31, 2002, the Trust and PrimeWest owed $nil (2001 -
$10.1 million; 2000 - $2.1 million) to PrimeWest Management Inc. for
unpaid management and other fees and reimbursement of general and
administrative costs.
The internalization transaction was achieved through the purchase by
PrimeWest of all of the issued and outstanding shares of PrimeWest
Management Inc. for a total consideration of approximately $26.3
million comprised of a cash payment of $13.2 million and the issuance
of Exchangeable Shares exchangeable, based on an agreed exchange ratio,
for approximately 491,000 Trust Units and valued at approximately $13.1
million based on the closing price of the Trust Units on the TSX on
September 26, 2002. The $13.2 million that related to the acquisition
of the 1% retained royalty was capitalized; an additional $9.5 million
was capitalized with an offset to future tax liability as a result of
the property, plant and equipment having no tax basis. In addition,
PrimeWest agreed to issue Exchangeable Shares valued at $1.5 million to
certain senior managers to terminate a management incentive program of
PrimeWest Management Inc. and to create a special executive retention
plan for those senior managers which provides for long term incentive
bonuses in the form of Exchangeable Shares valued, in the aggregate, at
$3.5 million. Exchangeable Shares will be issued pursuant to the
retention plan on each of the second, third, fourth and fifth
anniversaries of the completion of the internalization transaction.
11. Income Taxes
The Trust, and consequently the unitholders of the Trust, had taxable
income totaling $86.9 million for 2002 representing approximately 55%
of distributions paid in the year (2001 - $155.8 million representing
67%; 2000 - $38.3 million representing 53%).
PrimeWest and its subsidiaries had no taxable income for 2002, 2001,
and 2000, as tax-pool deductions and the royalty payable were
sufficient to reduce taxable income in these entities to nil.
Effective January 1, 2000, the Company changed the method of accounting
for income taxes from the deferral method to the liability method. The
new method was applied retroactively without restatement of prior
periods. The effect of the change in accounting policy on the financial
statements was to decrease unitholders' equity by $10.2 million with a
corresponding increase in the provision for future income tax
liabilities on the balance sheet. The effect on the provision for
income taxes for 2000, as a result of this change in accounting policy,
was to decrease future income tax liability by $2.6 million. The future
income tax liability results from the carrying value of the capital
assets exceeding the available tax pools.
The future tax provision results from temporary differences in the
recognition of revenues and expenses for income taxes and accounting
purposes as follows:
2002 2001 2000
-----------------------------------------------------------------------
Loss carry forwards $ (4,977) $ (10,601) $ --
Capital assets 350,014 378,015 21,455
Site restoration provision (1,969) (2,283) (874)
Long-term incentive liability (3,180) (2,536) (3,985)
-----------------------------------------------------------------------
$ 339,888 $ 362,595 $ 16,596
=======================================================================
The provisions for income taxes varies from the amounts that would be
computed by applying the combined Canadian federal and provincial
income tax rates for the following reasons:
2002 2001 2000
- ------------------------------------------------------------------------------------------------------
Net income (loss) before taxes $ (28,793) $ 51,630 $ 58,719
- ------------------------------------------------------------------------------------------------------
Computed income tax expense (recovery) at the
Canadian statutory rate of 42.12%
(2001 - 43.12%; 2000 - 44.62%) (12,128) 22,263 26,200
Increase (decrease) resulting from:
Non-deductible crown royalties and other
payments, net of ARTC 5,725 273 157
Federal resource allowance (3,466) (9,729) (1,447
Amounts included in trust income and other (22,431) (43,141) (22,352
- ------------------------------------------------------------------------------------------------------
Future income taxes $ (32,300) $(30,334) $ 2,558
======================================================================================================
12. Financial Instruments
a) Commodity Price Risk Management PrimeWest generally sells its oil
and gas under short-term market-based contracts. Derivative financial
instruments, options and swaps may be used to hedge the impact of oil
and gas price fluctuations.
A summary of these contracts in place at December 31, 2002 follows:
CRUDE OIL
VOLUME WTI PRICE
PERIOD (BBLS/D) TYPE (U.S.$/BBL)
-----------------------------------------------------------------------------------
Jan - Jan 2003 500 Swap $ 30.50
Jan - Jan 2003 500 Swap 28.95
Jan - Mar 2003 1,000 Costless Collar 21.00 / 27.70
Jan - Mar 2003 1,000 Costless Collar 20.50 / 25.50
Jan - Mar 2003 500 Costless Collar 22.00 / 30.01
Jan - Mar 2003 500 Swap 27.28
Jan - Mar 2003 500 3 Way 19.50 / 24.50 / 29.90
Jan - Mar 2003 1000 Purchase Call 34.00
Jan - Jun 2003 1,000 3 Way 18.50 / 22.50 / 27.70
Feb - Feb 2003 500 Swap 28.75
Feb - Feb 2003 500 Swap 30.60
Mar - Mar 2003 500 Swap 29.00
Apr - Apr 2003 500 Swap 27.20
Apr - Jun 2003 500 Costless Collar 22.00 / 30.10
Apr - Dec 2003 1,000 3 Way 17.00 / 20.50 / 25.50
May - May 2003 500 Swap 27.05
Jun - Jun 2003 500 Swap 27.10
July - Dec 2003 1,000 3 Way 18.50 / 22.50 / 27.20
-----------------------------------------------------------------------------------
NATURAL GAS (AECO)
VOLUME AECO PRICE
PERIOD (MMCF/DAY) TYPE (CDN$/MCF)
-----------------------------------------------------------------------------------
Jan 2002 - Oct 2003 4.7 Swap $ 3.98
Jan 2002 - Oct 2003 4.7 Swap 4.17
Nov 2002 - Mar 2003 4.7 Costless Collar 4.22 by 5.96
Nov 2002 - Mar 2003 4.7 3 Way 3.17 / 4.48 / 6.59
Nov 2002 - Mar 2003 4.7 3 Way 3.17 / 3.96 / 5.46
Nov 2002 - Mar 2003 4.7 3 Way 4.22 / 5.28 / 7.04
Nov 2002 - Mar 2003 4.7 Swap 5.43
Nov 2002 - Oct 2004 9.5 3 Way 3.17 / 4.22 / 6.09
Jan 2003 - Mar 2003 4.7 Costless Collar 5.28 / 6.35
Jan 2003 - Mar 2003 23.7 Put 5.28
Feb - Feb 2003 4.7 Swap 7.02
Apr - Jun 2003 4.7 Put Swaption 5.28
Apr - Oct 2003 4.7 Fixed Price 4.75
Apr - Oct 2003 4.7 Swap 5.05
Apr - Oct 2003 4.7 3 Way 3.17 / 4.48 / 6.26
Apr - Oct 2003 4.7 3 Way 3.17 / 3.96 / 5.39
Apr - Oct 2003 4.7 3 Way 3.69 / 4.75 / 6.65
Apr - Oct 2003 9.5 Put Swaption 5.28
Nov 2003 - Mar 2004 4.7 3 Way 4.22 / 5.28 / 8.23
-----------------------------------------------------------------------------------
NATURAL GAS (BASIS DIFFERENTIAL $US / MCF)
VOLUME WTI PRICE
PERIOD (MMCF/DAY) TYPE (US$/MCF)
-----------------------------------------------------------------------------------
Nov 2002 - March 2003 5.0 Basis Swap 0.425
Apr 2003 - October 2003 5.0 Basis Swap 0.450
-----------------------------------------------------------------------------------
In 2002, the financial impact of contracts settling in the year was an
increase in sales revenues of $28.1 million (2001 - $39.5 million
increase in sales revenues; 2000 - $2.2 million decrease in sales
revenues).
The mark-to-market value of the hedges in place as at December 31, 2002
is a $13.6 million loss of which $11.7 million is attributable to
natural gas and $1.9 million is attributable to crude oil.
b) Interest Rate Risk Management PrimeWest has the following interest
rate swaps outstanding at December 31, 2002.
NOTIONAL FIXED MARK-TO
AMOUNT BA RATE MARKET VALUE
TERM ($ MILLIONS) (%) ($ MILLIONS)
-----------------------------------------------------------------------
Dec 18/02 - May 05/03 $ 20 4.50 (0.3)
Dec 04/01 - Dec 04/03 $ 25 3.21 (0.1)
May 24/98 - May 25/04 $ 25 6.48 (1.3)
Nov 26/01 - May 26/04 $ 25 3.85 (0.3)
=======================================================================
The effect of these swaps was to increase interest paid in 2002 by $1.5
million (2001 - $0.4 million, 2000 - $0.7 million).
c) Fair Value Of Financial Instruments Financial instruments include
cash, accounts receivable, accounts payable and accrued liabilities,
accrued distributions to unitholders, long-term debt and financial
hedges. As at December 31, 2002, 2001, and 2000, the fair market value
of the financial instruments,
other than long-term debt and financial hedges, approximate their
carrying value, due to the short-term maturity of these instruments.
The fair value of long-term debt approximates its carrying value,
because the cost of borrowing approximates the market rate for similar
borrowings.
13. Commitments And Contingencies
a) PrimeWest has lease commitments relating to office buildings. The
estimated annual minimum operating lease rental payments for the
buildings, after deducting sublease income will be $1.5 million in
2003, $1.2 million in 2004, $1.1 million in 2005, $1.1 million in 2006
and $2.4 million in 2007 - 2009, the remaining term of the leases.
b) As part of PrimeWest's internalization transaction (see Note 10),
PrimeWest agreed to pay $3.5 million in exchangeable shares as a
special executive retention plan. One quarter of the exchangeable
shares will be issuable to the Senior Managers of PrimeWest on each of
the second, third, fourth and fifth anniversary of transaction closing,
November 6, 2002. c) PrimeWest is engaged in a number of matters of
litigation, none of which could reasonably be expected to result in any
material adverse consequence.
14. Subsequent Event
On November 25, 2002, PrimeWest and PrimeWest Gas Inc. (PrimeWest Gas),
a wholly-owned subsidiary of PrimeWest, entered into an acquisition
agreement with two private Canadian companies for an aggregate purchase
price of $206.1 million, net of adjustments (including working capital)
in cash. Of the purchase price, $191.1 million is attributed by
PrimeWest Gas to oil and gas reserves and $15 million is attributed to
certain natural gas processing midstream assets. The acquisition closed
on January 23, 2003.
15. Prior Years' Comparative Numbers
Certain prior years' comparative numbers have been restated to conform
with the current year's presentation.
16. Differences Between Canadian And United States Generally Accepted Accounting
Principles
PrimeWest's financial statements are prepared in accordance with
accounting principles generally accepted (GAAP) in Canada which, in
some respects differ from those generally accepted in the United States
(U.S.). The following are those policies that result in significant
measurement differences.
1. Property, Plant And Equipment PrimeWest follows the full cost
accounting guideline as established by the Canadian Institute of
Chartered Accountants (CICA). 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.
2. 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 CICA. In prior years,
the company computed deferred income taxes using the deferral method.
The Canadian accounting standard is similar to the United States
Statement of Financial Accounting Standards (FAS) No. 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. Under U.S. GAAP, enacted tax rates are used to calculate
future taxes, whereas Canadian GAAP uses substantively enacted rates.
In Canada adjustments resulting from implementation of the new standard
are recorded in retained earnings. In the United States these
adjustments are booked to income.
3. Derivative Financial Instruments Effective January 1, 2001, the
company adopted FAS 133 Accounting for Derivative Instruments and
Hedging Activities, as amended by FAS 138, which establishes accounting
and reporting standards for derivative instruments, including certain
derivative instruments 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 resulted in OCI of $1.0 million. Assets
increased by $1.0 million as a result of recording derivative
instruments on the consolidated balance sheet at fair value.
Implementation of this accounting standard did not affect the Trust's
cash flow or liquidity.
RECENT ACCOUNTING PRONOUNCEMENTS ISSUED BUT NOT IMPLEMENTED
During 2002 and year to date 2003, the following new or amended
standards and guidelines were issued:
ACCOUNTING FOR GUARANTEES
In February, 2003, the CICA issued an accounting guideline on the
financial statement disclosures to be made by a guarantor relative to
its obligations under guarantees. Effective for the fiscal year
beginning January 1, 2003, the accounting guideline requires the
disclosure of the nature of the guarantee, the approximate term of the
guarantee, how it arose, the events or circumstances that would trigger
performance under the guarantee, the maximum potential amount of future
payments, the current carrying amount of the liability if any, the
nature of any recourse provision and any assets held as collateral.
In November 2002, the Financial Accounting Standards Board (FASB)
issued an interpretation FIN No. 45, "Gurantor's Accounting and
Disclosure Requirements for Guarantees, Including Indirect Guarantees
of Indebtedness of Others," which requires that a guarantor disclose
and recognize in its financial statements its obligations relating to
guarantees that it has issued. Liability recognition is required at the
inception of the guarantee, whether or not payment is probable. The
Trust is currently assessing the impact on its financial statements of
this guidance.
ACCOUNTING FOR GAINS AND LOSSES ON SETTLEMENT OF DEBT
In April 2002, FAS 145 was issued rescinding the requirement to include
gains and losses on the settlement of debt as extraordinary items. FAS
145 is applicable for fiscal years beginning on or after May 15, 2002.
The standard has been no impact on the Trust.
ACCOUNTING FOR COSTS ASSOCIATED WITH EXIT OR DISPOSAL ACTIVITIES
In June 2002, FAS 146 was issued. The standard requires that
liabilities for exit or disposal activity costs be recognized and
measured at fair value when the liability is incurred. This standard is
effective for disposal activities initiated after December 31, 2002.
ACCOUNTING FOR STOCK-BASED COMPENSATION - TRANSITION AND DISCLOSURE
In December 2002, FAS 148 "Accounting for Stock-Based Compensation -
Transition and Disclosure" was issued as an amendment to FAS 123
"Accounting for Stock-Based Compensation", to provide alternative
methods of transition for a voluntary change to the fair value based
method of accounting for stock-based employee compensation. FAS 148 is
applicable for fiscal years beginning after December 15, 2003. The
Trust does not expect that the adoption of this pronouncement will have
an impact on its financial statements.
HEDGING RELATIONSHIPS
The CICA issued Accounting Guideline 13 "Hedging Relationships" which
deals with the identification, designation, documentation and
effectiveness of hedging relationships for the purpose of applying
hedge accounting. The guideline establishes conditions for applying
hedge accounting, but does not specify hedge accounting methods. The
guideline is effective for fiscal years beginning on or after July 1,
2003. The Trust anticipates that adoption of Accounting Guideline 13
will not have a material effect on its consolidated financial
statements.
The following tables set out the significant differences in the
consolidated financial statements using U.S. GAAP.
a) Consolidated Net Income
2002 2001 2000
(RESTATED)
--------------------------------------------------------------------------------------
Net income as reported $ 620 $ 79,536 $ 55,612
Adjustments
Depletion and depreciation 67,255 (539,288) 6,523
FAS 133 adjustment (55,813) 43,300 --
Future income tax recovery/
(expense) (1,405) 165,202 (780)
Effect of change in accounting
policy -- -- (10,219)
--------------------------------------------------------------------------------------
Adjusted net (loss)/income 10,657 (251,250) 51,136
--------------------------------------------------------------------------------------
Other comprehensive income
Cumulative effect type adjustment -
fair value of cash flow
hedging instruments -- (970) --
Change during the year -- 970 --
--------------------------------------------------------------------------------------
Accumulated other comprehensive income -- -- --
--------------------------------------------------------------------------------------
Adjusted net and comprehensive
(loss)/income $ 10,657 $ (251,250) $ 51,136
======================================================================================
Net (loss)/income per Trust Unit
U.S. GAAP - basic $ 0.31 $ (9.80) $ 4.58
- diluted $ 0.31 $ (9.80) $ 4.58
======================================================================================
b) Consolidated Unitholders' Equity
2001
(THOUSANDS OF CANADIAN DOLLARS) 2002 (RESTATED)
--------------------------------------------------------------------------------------
Unitholders' Equity as reported $ 847,098 $ 856,277
Adjustments
Depletion and depreciation (530,880) (598,135)
FAS 133 adjustment (11,543) 44,270
Future income tax recovery 169,138 170,543
--------------------------------------------------------------------------------------
$ 473,813 $ 472,955
======================================================================================
c) Consolidated Balance Sheets
(thousands of Canadian dollars) 2002 2001
------------------------------------------------------------------------------------------
U.S.GAAP
CDN GAAP U.S. GAAP CDN GAAP (RESTATED)
------------------------------------------------------------------------------------------
Other assets $ 14,179 $ 14,179 $ -- $ 44,270
Property, plant and equipment, net 1,404,463 873,583 1,448,661 850,526
Other liabilities -- 11,543 -- --
Future income tax liability 339,888 170,750 362,595 192,052
Accumulated Income (deficit) 123,170 (250,115) 122,550 (260,772)
==========================================================================================
d) 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.
e) Restatement 2001 numbers have been restated to tax effect the FAS
133 adjustment. The effect is to increase future tax expense and future
income tax liability by $19,089 in 2001.
SFAS NO. 69 SUPPLEMENTAL RESERVE INFORMATION (UNAUDITED)
The following data supplements oil and gas disclosure in the Trust's Annual
Report, and is provided in accordance with the provision of the United States
Financial Accounting Standards Board's Statement No. 69.
OIL AND GAS RESERVES
Users of this information should be aware that the process of estimating
quantities of "proved" and "proved developed" crude oil and natural gas reserves
is very complex, requiring significant subjective decisions in the evaluation of
all available geological, engineering and economic data for each reservoir. The
data for a given reservoir may also change substantially over time as a result
of the numerous factors including, but not limited to, additional development
activity, evolving production history, and continual reassessment of the
viability of production under varying economic conditions. Consequently,
material revisions to existing reserve estimates occur from time to time.
Although every reasonable effort is made to ensure that reserve estimates
reported represent the most accurate assessments possible, the significance of
the subjective decisions required and variances in available data for various
reservoirs make these estimates generally less precise than other estimates
presented in connection with financial statement disclosures.
Proved oil and gas reserves are the estimated quantities of crude oil, natural
gas and natural gas liquids which geological and engineering data demonstrate
with reasonable certainty to be recoverable in future years from known
reservoirs under existing economic and operating conditions.
Proved developed oil and gas reserves are reserves that can be expected to be
recovered through existing wells with existing equipment and operating methods.
Canadian provincial royalties are determined based on a graduated percentage
scale which varies with prices and production volumes. Canadian reserves, as
presented on a net basis, assume prices and royalty rates in existence at the
time the estimates were made, and the Trust's estimate of future production
volumes. Future fluctuations in prices, production rates, or changes in
political or regulatory environments could cause the Trust's share of future
production from Canadian reserves to be materially different from that
presented.
Subsequent to December 31, 2002, no major discovery or other favorable or
adverse event is believed to have caused a material change in the estimates of
proved or proved developed reserves as of that date.
RESULTS OF OIL AND GAS OPERATIONS
(thousands of Canadian dollars) 2002 2001 2000
- ----------------------------------------------------------------------------------------------------------
Revenues $ 264,248 $ 306,515 $ 156,561
Expenses
Production costs 60,773 58,951 30,174
Depreciation, depletion and amortization 113,498 697,934 35,891
Tax (recovery)/expense (25,956) (217,053) 3,887
- ----------------------------------------------------------------------------------------------------------
148,315 539,832 69,952
- ----------------------------------------------------------------------------------------------------------
Results of operations from
oil and gas operations $ 115,933 $ (233,317) $ 86,609
==========================================================================================================
Although these calculations have been prepared according to the standards
described above, it should be emphasized that due to the number of assumptions
and estimates required in the calculation, the amounts are not indicative of the
amount of net revenue that the Trust expects to receive in future years. They
are also not indicative of the current value or future earnings that may be
realized from the production of proved reserves, nor should it be assumed that
they represent the fair market value of the reserves or of the oil and gas
properties.
Although the calculations are based on existing economic conditions at each
year-end, such economic conditions have changed and may continue to change
significantly due to events such as the continuing changes in the natural gas
market and changes in government policies and regulations. While the
calculations are based on the Trust's understanding of the established FASB
guidelines, there are numerous other equally valid assumptions under which these
estimates could be made that would produce significantly different results.
STANDARDIZED MEASURE
(millions of Canadian dollars) 2002 2001 2000
- -----------------------------------------------------------------------------------------------------------------
Future cash inflows $ 2,890.5 $ 1,732.5 $ 2,182.1
Future production costs (699.0) (642.5) (400.8)
Future development costs (73.4) (38.7) (31.1)
Other related future costs (43.4) (37.1) (25.2)
- -----------------------------------------------------------------------------------------------------------------
Future net cash flows 2,074.7 1,014.2 1,725.0
Discount at 10% (919.4) (415.9) (754.5)
- -----------------------------------------------------------------------------------------------------------------
Standardized measure of discounted future
net cash flow related to proved reserves $ 1,155.3 $ 598.3 $ 970.5
=================================================================================================================
SUMMARY OF CHANGES IN THE STANDARDIZED MEASURE DURING THE YEAR
(millions of Canadian dollars) 2002 2001 2000
- -----------------------------------------------------------------------------------------------------------------
Sales of oil and gas produced, net of production costs $ (203.5) $ (247.3) $ (126.3)
Net change in sales and transfer prices, net of
development and production costs 672.6 (586.6) 513.4
Sales of reserves in place (4.5) (78.1) (0.9)
Purchases of reserves in place 45.6 826.6 118.6
Extensions, discoveries and improved recovery,
less related costs 52.3 101.7 4.7
Changes in timing of future net cash flows and other (93.6) (389.3) 32.4
Revisions of previous quantity estimates 28.3 (96.3) 27.8
Accretion of discount 59.8 97.1 36.4
- -----------------------------------------------------------------------------------------------------------------
Net change 557.0 (372.2) 606.1
Balance at beginning of year 598.3 970.5 364.4
- -----------------------------------------------------------------------------------------------------------------
Balance at end of year $ 1,155.3 $ 598.3 $ 970.5
=================================================================================================================
DOCUMENT 3
----------
MANAGEMENT'S DISCUSSION & ANALYSIS (MD&A)
The following is management's discussion and analysis (MD&A) of PrimeWest's
operating and financial results for the year ended December 31, 2002 compared
with the prior year as well as information and opinions concerning the Trust's
future outlook based on currently available information. This discussion should
be read in conjunction with the Trust's audited consolidated financial
statements for the years ended December 31, 2002 and 2001, together with
accompanying notes. These are included on pages 37 through 60 of this annual
report.
CONSOLIDATION OF TRUST UNITS
On August 16, 2002 the Trust Units of PrimeWest began trading on a four to one
consolidated basis on the TSX. All per Trust Unit amounts have been restated to
conform to the four to one consolidated basis.
CURRENCY
All financial information contained in this MD&A is reported in Canadian
dollars, unless otherwise indicated.
NATURAL GAS CONVERSION EQUIVALENT
All calculations required to convert natural gas to a crude oil equivalent (BOE)
have been made using a ratio of 6,000 cubic feet of natural gas to 1 barrel of
crude oil.
RESERVES AND PRODUCTION INFORMATION
Established reserves include 100% of proved reserves and 50% of probable
reserves.
All production information is reported before the deduction of crown and
freehold royalties.
FORWARD-LOOKING INFORMATION
The following discussion, as well as other sections within this annual report,
contain forward-looking or outlook information with respect to PrimeWest.
The use of any of the words "anticipate", "continue", "estimate", "expect",
"may", "will", "project", "should", "believe", "outlook" and similar expressions
are intended to identify forward-looking statements. These statements involve
known and unknown risks, uncertainties and other factors that may cause actual
results or events to differ materially from those anticipated in our
forward-looking statements. We believe the expectations reflected in those
forward-looking statements are reasonable. However, we cannot assure the reader
that these expectations will prove to be correct. The reader should not unduly
rely on forward-looking statements included in this annual report. These
statements speak only as of the date of this annual report. In particular, this
annual report contains forward-looking statements pertaining to the following:
o the size of our reserves;
o the timing and amount of future production;
o prices for oil and natural gas produced;
o operating and other costs;
o business strategies and plans of management;
o supply and demand for oil and natural gas;
o expectations regarding our ability to raise capital and to add to
our reserves through
o acquisitions and exploration and development; and
o our treatment under governmental regulatory regimes.
Our actual results could differ materially from those anticipated in these
forward-looking statements as a result of the risk factors set forth below and
elsewhere in this annual report:
o volatility in market prices for oil and natural gas;
o risks inherent in our oil and gas operations;
o uncertainties associated with estimating reserves;
o competition for, among other things; capital, acquisitions of
reserves, undeveloped
o lands and skilled personnel;
o incorrect assessments of the value of acquisitions;
o geological, technical, drilling and processing problems; and
o the other factors discussed under "Operational and Other Business
Risks" at pages 34 to 36 of this MD&A.
These factors should not be construed as exhaustive. We undertake no obligation
to publicly update or revise any forward-looking statements.
EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES.
The Chief Executive Officer, Don Garner, and Chief Financial Officer, Dennis
Feuchuk, evaluated the effectiveness of PrimeWest Energy's disclosure controls
and procedures as of a date within 90 days of the filing of this report
(Evaluation Date), and concluded that, as of the Evaluation Date, PrimeWest
Energy's disclosure controls and procedures were effective to ensure that
information PrimeWest is required to disclose in its filings with the Securities
and Exchange Commission under the Securities Exchange Act of 1934 is recorded,
processed, summarized and reported, within the time periods specified in the
Commission's rules and forms, and to ensure that information required to be
disclosed by PrimeWest in the reports that it files under the Exchange Act is
accumulated and communicated to PrimeWest's management, including its principal
executive officer and principal financial officer, as appropriate to allow
timely decisions regarding required disclosure.
CHANGES TO INTERNAL CONTROLS AND PROCEDURES FOR FINANCIAL REPORTING.
There were no significant changes to PrimeWest's internal controls or in other
factors that could significantly affect these controls subsequent to the
Evaluation Date.
HOW PRIMEWEST MAKES MONEY - BUSINESS MODEL
ELEMENT 2002 2001 DESCRIPTION CRITICAL SUCCESS FACTORS 2003 OUTLOOK
- ------------------------------------------------------------------------------------------------------------------------------------
PRODUCTION 30,189 BOE/day 29,774 BOE/day Produce & sell natural -Stratetic acquisitions -Growth through accretive
gas, Crude oil & natural -Development success acquisitions
gas liquids -Production success -$70-$100 million of
capital development
-Average of 34,500-35,500
BOE per day
- ------------------------------------------------------------------------------------------------------------------------------------
PRICES(1) $29.11/ BOE $34.93 per BOE Commodity prices for -Market prices for -See "Price Outlook" on
natural Gas, crude oil natural gas, crude oil pages 22 & 23
& NGL's & NGL's -See "2003/2004 Hedging
-Commodity price risk Summary" on page 22
management (hedging)
- ------------------------------------------------------------------------------------------------------------------------------------
REVENUE $320.7 million $379.7 million Gross cash inflow -Dependent upon commodity
(including Hedging gains) prices and production
- ------------------------------------------------------------------------------------------------------------------------------------
LESS LESS
- ------------------------------------------------------------------------------------------------------------------------------------
ROYALTY EXPENSE $56.5 million $73.2 million Royalty expense (Percentage -Increase related to
(19.3% OF (21.5% OF of revenue before hedging higher royalties on
REVENUE BEFORE REVENUE BEFORE gains) Caroline / Peace River
HEDGING GAINS) HEDGING GAINS) Arch properties
- ------------------------------------------------------------------------------------------------------------------------------------
LESS LESS
- ------------------------------------------------------------------------------------------------------------------------------------
OPERATING EXPENSE $60.8 million $59.0 million Operating Costs -Continuous benchmarking -$6.00 - $6.50 per BOE
($5.52/BOE) ($5.42/BOE) & process improvement
-Acquire low
cost operations
- ------------------------------------------------------------------------------------------------------------------------------------
EQUALS EQUALS
- ------------------------------------------------------------------------------------------------------------------------------------
OPERATING MARGIN $203.4 million $247.5 million Variable Cash Flow -High quality production -Dependent upon variables
($18.46/BOE) ($22.78/BOE) -Low operating costs above
- ------------------------------------------------------------------------------------------------------------------------------------
LESS OTHER EXPENSES:
ELEMENT 2002 2001 DESCRIPTION CRITICAL SUCCESS FACTORS 2003 OUTLOOK
- ------------------------------------------------------------------------------------------------------------------------------------
G&A Costs $11.3 million $10.4 million General & administrative -Continuous benchmarking -$0.90 per BOE of
Costs & process improvement production
- ------------------------------------------------------------------------------------------------------------------------------------
Interest $10.8 million $13.8 million Interest -Debt levels managed to -Expected to be below 2
no more than 2 times times cash flow at
cash flow December 31
-Interest rates
- ------------------------------------------------------------------------------------------------------------------------------------
Taxes $2.9 million $2.4 million Capital taxes -Modest increases in 2003
- ------------------------------------------------------------------------------------------------------------------------------------
Reclamation Fund
Contribution $4.1 million $3.5 million Contribution to -Prudent reclamation -$0.50 per BOE of
reclamation fund program production
- ------------------------------------------------------------------------------------------------------------------------------------
Internalization Cost/$7.4 million $6.4 million Management contract -no similar costs
Management Fees eliminated effective
October 1, 2002
- ------------------------------------------------------------------------------------------------------------------------------------
= =
- ------------------------------------------------------------------------------------------------------------------------------------
Total Other
Expenses $36.5 million $36.5 million
- ------------------------------------------------------------------------------------------------------------------------------------
Cash Flow
Available for Cash flow available
Distribution to $166.9 million $211.0 million for distribution
Unitholders to unitholders (2)
- ------------------------------------------------------------------------------------------------------------------------------------
(1) Includes sulphur
(2) Cash flow available for distribution to unitholders is a non-GAAP
measurement and therefore is unlikely to be comparable to similar
measures presented by other issuers.
FINANCIAL AND OPERATING HIGHLIGHTS
(THOUSANDS OF DOLLARS EXCEPT PER BOE, PER TRUST UNIT AND MULTIPLE AMOUNTS)
2002 PER BOE 2001 Per BOE
- ------------------------------------------------------------------------------------------------------------------------------------
FINANCIAL
Gross revenues before hedging $ 292,623 $ 26.56 $ 340,191 $ 31.30
Hedging revenues 28,121 2.55 39,480 3.63
Royalty expense (56,496) (5.13) (73,156) (6.73)
Operating expense (60,773) (5.52) (58,951) (5.42)
- ------------------------------------------------------------------------------------------------------------------------------------
Operating margin 203,475 18.46 247,564 22.78
General and administrative expense (11,281) (1.02) (10,394) (0.96)
Cash management fees (3,982) (0.36) (6,431) (0.59)
Interest expense (10,788) (0.98) (13,800) (1.27)
Capital taxes (2,887) (0.26) (2,429) (0.22)
Contribution to reclamation fund (4,078) (0.37) (3,499) (0.32)
Cash internalization costs (3,598) (0.33) -- --
- ------------------------------------------------------------------------------------------------------------------------------------
Cash flow available for distribution $ 166,861 $ 15.14 $ 211,011 $ 19.42
- ------------------------------------------------------------------------------------------------------------------------------------
Per trust unit (1) $ 4.89 $ 8.23
- ------------------------------------------------------------------------------------------------------------------------------------
Cash distributed to unitholders $ 157,951 $ 234,465
- ------------------------------------------------------------------------------------------------------------------------------------
Per trust unit (1) $ 4.80 $ 9.24
- ------------------------------------------------------------------------------------------------------------------------------------
Net debt (2) $ 225,436 $ 224,431
- ------------------------------------------------------------------------------------------------------------------------------------
Net debt to cash flow from
operations multiple 1.32 1.05
- ------------------------------------------------------------------------------------------------------------------------------------
Trust units and exchangeable shares
issued and outstanding
Year end 38,944,386 32,785,085
Weighted average 34,134,230 25,633,250
====================================================================================================================================
2002 2001
- ------------------------------------------------------------------------------------------------------------------------------------
OPERATING
Daily sales volume
Natural gas (mmcf/day) 113.5 104.8
Crude oil (bbls/day) 9,239 10,033
Natural gas liquids (bbls/day) 2,030 2,273
- ------------------------------------------------------------------------------------------------------------------------------------
Total (BOE/day) 30,189 29,774
- ------------------------------------------------------------------------------------------------------------------------------------
(1) All unit and per unit figures have been restated to reflect the 4 for 1
unit consolidation effective August 16, 2002.
(2) Net debt is long term debt plus working capital.
FINANCIAL AND OPERATING HIGHLIGHTS
o Production stable throughout 2002 at approximately 30,000 BOE per day.
o Operating margin of $18.46 per BOE for 2002, down 19% from 2001
primarily due to lower prices for natural gas.
o Hedging gains of $28.1 million ($2.55 per BOE) in 2002, compared to
gains of $39.5 million ($3.63 per BOE) in 2001.
o Operating expenses up 2% on a BOE basis from 2001 as higher power and
third party processing fees more than offset the benefits from
continuing cost containment initiatives.
o Royalties per BOE down 24% compared to 2001 primarily due to
significantly lower natural gas prices year over year.
o General and administrative expenses increased over 2001 reflecting $0.8
million of nonrecurring costs in 2002 related to listing the Trust
Units on the New York Stock Exchange.
o Cash management fees down 39% compared to 2001 primarily due to the
internalization of management effective October 1, 2002 and lower net
revenues driven by lower natural gas prices in 2002.
o Interest expense down 23% from 2001 a result of lower average debt and
lower interest rates in 2002 compared to 2001. o Distributions of $4.80
per Trust Unit in 2002 compared to $9.24 in 2001 reflecting reduced
cash flow in 2002 due to lower natural gas prices and a 95% payout
ratio in 2002 compared to 111% in 2001.
o Capital development program of $63.1 million added 8.7 million BOE of
established reserves at $7.27 per BOE.
CASH FLOW RECONCILIATION
The following table shows a reconciliation of 2002 cash flow from operations to
the prior year.
INCREASE (DECREASE) IN CASH FLOW
(thousands of dollars)
- --------------------------------------------------------------------------------
2001 Cash Flow from Operations $ 214,511
Effect of: production volumes 3,452
natural gas price (55,317)
hedging gas(1) (4,100)
crude oil price 12,414
hedging crude oil(1) (7,300)
natural gas liquids price (3,253)
royalty expense 16,660
other (6,128)
- --------------------------------------------------------------------------------
2002 CASH FLOW FROM OPERATIONS $ 170,939
================================================================================
(1) Reflects change from previous year (ie: reduced hedging gains in 2002
compared to 2001). See 2002 Hedging Results at page 21.
CAPITAL SPENDING
Capital expenditures, including corporate acquisitions, totaled approximately
$124.1 million in 2002 as summarized in the following table:
(thousands of dollars) 2002 2001 2000
- --------------------------------------------------------------------------------
Land and lease $ 5,663 $ 6,831 $ 545
Geological and geophysical 1,814 4,048 817
Development drilling 34,488 47,766 16,416
Plant and facilities 21,182 21,802 5,665
Head office (includes capitalized G&A) 5,908 3,457 2,348
- --------------------------------------------------------------------------------
Total property, plant and equipment 69,055 83,904 25,791
Acquisitions 59,606 822,598 118,656
- --------------------------------------------------------------------------------
Total additions 128,661 906,502 144,447
Property dispositions (4,529) (78,144) (855)
- --------------------------------------------------------------------------------
Net additions $ 124,132 $ 828,358 $ 143,592
================================================================================
In 2002, PrimeWest completed $45.6 million in property acquisitions adding 5.7
million BOE of established reserves and approximately 1,550 BOE per day of
production. Acquisitions includes $13.2 million to acquire the 1% retained
royalty as part of the internalization of management plus $0.8 million in
capitalized costs to effect the internalization. For 2002, PrimeWest added 8.7
million BOE of established reserves at a cost of $7.27 per BOE from $63.1
million of development activities (2001 - $80.4 million; 2000 - $23.4 million).
2002 DEVELOPMENT ADDITIONS: 8.7 MILLION BOE OF ESTABLISHED RESERVES AT $7.27 PER
BOE
OUTLOOK FOR CAPITAL SPENDING
On November 25, 2002, PrimeWest announced its intention to acquire production
and reserves at Caroline and Peace River Arch for $206.1 million, including $15
million for certain natural gas processing midstream assets. Established
reserves were approximately 17.6 million BOE and production as of January 1,
2003 was approximately 6,800 BOE per day. At December 31, 2002, $14.2 million
had been incurred to effect the acquisition. The transaction closed on January
23, 2003.
PrimeWest plans to spend $70 to $100 million in 2003 on capital development
programs.
RESERVE RECONCILIATION
TOTAL PROVED RESERVES
NATURAL NET
OIL GAS NGL BOE(1) CHANGE
2002 (MBBLS) (BCF) (MMBLS) (MBOE) (%)
- --------------------------------------------------------------------------------------------------------------------
OPENING BALANCE 24,719 349.3 7,830 90,767
- --------------------------------------------------------------------------------------------------------------------
Additions, extensions, discoveries 182 31.9 796 6,296 (7%)
Acquisitions 373 23.8 862 5,208 (6%)
Divestments (512) (6.7) (158) (1,789) (2%)
Revision 26 (7.4) (138) (1,350) (2%)
2002 Production (3,372) (41.4) (741) (11,020) (12%)
- --------------------------------------------------------------------------------------------------------------------
CLOSING BALANCE 21,416 349.5 8,451 88,112 (3%)
====================================================================================================================
Reserve life index 7.1 8.7 11.2 8.4
- --------------------------------------------------------------------------------------------------------------------
(1) Natural gas to crude oil converted on a 6:1 basis
TOTAL ESTABLISHED RESERVES
NATURAL NET
OIL GAS NGL BOE(1) CHANGE
2002 (MBBLS) (BCF) (MMBLS) (MBOE) (%)
- --------------------------------------------------------------------------------------------------------------------
OPENING BALANCE 28,545 413.7 9,546 107,043
- --------------------------------------------------------------------------------------------------------------------
Additions, extensions, discoveries 234 43.9 1,133 8,685 8%
Acquisitions 437 26.3 925 5,746 5%
Divestments (633) (7.8) (186) (2,119) (2%)
Revision (751) (16.2) (486) (3,939) (4%)
2002 Production (3,372) (41.4) (741) (11,020) (10%)
- --------------------------------------------------------------------------------------------------------------------
Closing balance 24,460 418.5 10,191 104,396 (3%)
====================================================================================================================
Reserve life index 8.1 10.4 13.5 10.0
- --------------------------------------------------------------------------------------------------------------------
(1) Natural gas to crude oil converted on a 6:1 basis
CORE PROPERTIES
NORTH BUSINESS UNIT: SOUTH BUSINESS UNIT
NORTHWEST SOUTHEAST
Northwest Alberta Brant Farrow
Northeast Alberta Dinosaur/Medicine Hat
Meekwap Grand Forks
Northeast B.C. Whiskey Creek/Jumping Pound
Kaybob Saskatchewan
Grande Prairie East Other
North Other CENTRAL
DAWSON Crossfield/Lone Pine Creek
Dawson Thunder
Stowe Thorsby
West Other
CAROLINE
SUMMARY OF DAILY PRODUCTION VOLUMES
Team 2002 2001
- --------------------------------------------------------------------------------
Northwest 4,569 4,763
Dawson 6,312 6,008
Southeast 7,063 7,356
Central 7,797 8,853
Caroline 1,463 1,875
Other Properties 1,290 (882)
Royalties 1,695 1,801
- --------------------------------------------------------------------------------
Total 30,189 29,774
================================================================================
PRODUCTION SUMMARY
2002 % 2001 % Change
- --------------------------------------------------------------------------------
Natural gas (mmcf/day) 113.5 62 104.8 59 8%
Crude oil (bbls/day) 9,239 31 10,033 34 (8%)
Natural gas liquids (bbls/day) 2,030 7 2,273 7 (11%)
- --------------------------------------------------------------------------------
Total oil equivalent (BOE/day) 30,189 100 29,774 100 1%
================================================================================
Development success, particularly at Dawson, contributed to the increase in
natural gas production volumes in 2002 compared to 2001. Crude oil volume
declined in 2002 compared to 2001 as a significant majority of the 2002 capital
development program was focused on the development of natural gas reserves and
production.
Outlook For Production Volumes
Our target for 2003 is to produce an average of approximately 34,500 - 35,500
BOE per day, approximately 68% natural gas. Our natural decline rate for
production is 15% - 20% per year. Our capital development program of $70 to 100
million for 2003 is expected to significantly offset the impact of natural
decline.
COMMODITY PRICES
Average Realized Sales Prices (1)
(Canadian dollars) 2002 2001 Change
- --------------------------------------------------------------------------------
Natural gas ($/mcf) $ 4.55 $ 6.16 (26%)
Crude oil ($/bbl) 33.53 32.21 4%
Natural gas liquids ($/bbl) 26.56 30.96 (14%)
- --------------------------------------------------------------------------------
Total oil equivalent (2) ($/BOE) $ 29.16 $ 34.80 (16%)
- --------------------------------------------------------------------------------
(1) Includes hedging gains/losses
(2) Excludes sulphur
Natural gas, using the AECO daily index as the benchmark, entered 2002 at $3.67
per mcf and exited 2002 at $6.02 per mcf, an increase of 64%. High natural gas
storage levels depressed natural gas prices for much of the year, particularly
in the first and third quarters with the AECO price averaging $3.30 per mcf.
Natural gas prices rose in the second quarter on the prospect for a warmer than
normal summer of 2002, and fourth quarter natural gas prices strengthened on the
prospect for reduced supply combined with cold weather in the major U.S. natural
gas consuming areas.
For 2001, the price for natural gas reached record levels in the first quarter
of the year with an average AECO price of $10.91 per mcf. Prices fell through
the remainder of 2001 and averaged $6.30 for the year, also a record high.
PRODUCTION GROWTH
- -----------------
(Average BOE/day) (thousands)
1998 - 15.5
1999 - 15.0
2000 - 16.2
2001 - 29.8
2002 - 30.2
2003 Outlook - 34.5 - 35.5
NATURAL GAS: 62% OF 2002 PRODUCTION / 68% ESTIMATED FOR 2003
NATURAL GAS: AVERAGE REALIZED PRICE DOWN 26% FROM 2001
Crude oil, using West Texas Intermediate (WTI) as the benchmark, entered 2002 at
$US 19.84 per barrel, fell to a low of $US 17.97 per barrel on January 17, 2002
then reached a high of $US 32.72 per barrel on December 27, 2002, and exited
2002 at $US 31.20 per barrel. The threat of military action in the Middle East
combined with a general strike in Venezuela has driven the market to recent
highs.
MONTHLY AVERAGE AECO PRICES FOR 2001 AND 2002
2001 Jul - $4.49
Aug - $3.77
Sept -$3.52
Oct - $2.63
Nov - $3.53
Dec - $3.74
2002 Jan - $3.74
Feb - $3.00
Mar - $3.29
Apr - $4.47
May - $4.60
June - $4.21
Jul - $3.40
Aug - $2.77
Sep - $3.59
Oct - $4.61
Nov - $5.66
Dec - $5.50
MONTHLY AVERAGE WTI OIL PRICES FOR 2001 & 2002
2001 Jul - $26.47
Aug - $27.31
Sept $26.50
Oct - $22.21
Nov - $19.67
Dec - $19.40
2002 Jan - $19.73
Feb - $20.76
Mar - $24.44
Apr - $26.26
May - $26.95
June - $25.55
Jul - $26.94
Aug - $28.20
Sep - $29.67
Oct - $28.86
Nov - $26.19
Dec - $29.39
SALES REVENUE
Gross sales revenues fell by 15% in 2002 compared to 2001. Total sales revenue
was influenced both by production volumes, which increased year-over-year, and
natural gas prices, which decreased year-over-year as discussed above.
REVENUE ($ MILLIONS) 2002 % 2001 % CHANGE
- --------------------------------------------------------------------------------
Natural gas (1) $ 187.7 59 $ 234.5 62 (20%)
Crude oil 113.1 35 118.0 31 (4%)
Natural gas liquids 19.7 6 25.7 7 (23%)
- --------------------------------------------------------------------------------
$ 320.5 100 $ 378.2 100 (15%)
================================================================================
(1) Includes sulphur
NATURAL GAS: SALES REVENUE DOWN 20% DUE TO LOWER NATURAL GAS PRICES
NATURAL GAS REVENUES
The average daily production of natural gas was 8% higher in 2002 than 2001,
reflecting the significant weighting to natural gas of the 2002 capital
development program. The 26% drop in the average realized natural gas prices in
2002 compared to 2001, significantly outweighed the benefits of the production
increase, resulting in a 20% decrease in revenue from natural gas sales in 2002
compared to 2001.
CRUDE OIL REVENUES
Reduced crude oil production was partially offset by higher average crude oil
prices comparing 2002 to 2001.
NATURAL GAS LIQUIDS REVENUES
An 11% decrease in production volumes and a 14% decrease in prices, resulted in
a 23% decrease in natural gas liquids revenues in 2002 compared to 2001.
PrimeWest does not hedge its natural gas liquids prices.
2002 HEDGING RESULTS
During 2002, PrimeWest actively protected against the risk of falling prices on
a major portion of its production by either fixing the price or protecting the
downside risk through put or collar arrangements. In aggregate, total average
sales prices were higher by $2.55 per BOE in 2002 (2001 - $3.63 per BOE) than
would otherwise have been the case if PrimeWest had not entered into price
protection arrangements.
CRUDE OIL NATURAL GAS BOE (1)
($/BBL) ($/MCF) ($/BOE)
2002 2001 2002 2001 2002 2001
- -------------------------------------------------------------------------------------------------------------
Unhedged price $ 34.25 $ 30.86 $ 3.81 $ 5.26 $ 26.61 $ 31.17
Hedging gain (loss) (0.72) 1.35 0.74 0.90 2.55 3.63
- -------------------------------------------------------------------------------------------------------------
Realized price $ 33.53 $ 32.21 $ 4.55 $ 6.16 $ 29.16 $ 34.80
=============================================================================================================
(1) Excludes sulphur
2002 2001
HEDGING GAIN (LOSS) HEDGING GAIN
% HEDGED $ MILLION % HEDGED $ MILLION
- --------------------------------------------------------------------------------
Natural gas 71% $ 30.5 78% $ 34.6
Crude oil 69% (2.4) 84% 4.9
- --------------------------------------------------------------------------------
Total gain $ 28.1 $ 39.5
================================================================================
SALES REVENUE
- -------------
($ millions)
1998 - 77
1999 - 98
2000 - 191
2001 - 378
2002 - 321
2003/2004 HEDGING SUMMARY
Approximate percentage of future anticipated production volumes hedged as at
December 31, 2002, net of anticipated royalties, reflecting full production
declines with no offsetting additions:
2003 Q1 Q2 Q3 Q4 FULL YEAR
- --------------------------------------------------------------------------------
Crude oil 65% 38% 27% 28% 40%
Natural gas 69% 60% 60% 31% 55%
================================================================================
As at December 31, 2002, the mark-to-market loss for 2003 hedges totaled $13.8
million, $1.9 million for crude oil and $11.9 million for natural gas.
For 2004, PrimeWest has none of its crude oil production and 12% of its natural
gas hedged with a combination of swaps, and option based instruments. As at
December 31, 2002, there is no material gain or loss on a mark-to-market
valuation of these hedges.
PRICE OUTLOOK
NATURAL GAS
Natural gas is a commodity that moves through pipelines within North America and
as such is affected by supply and demand forces within North America. New gas
supply is added primarily by drilling, re-working of existing wells, and
additions to capital infrastructure. Disruptions to supply can come from extreme
weather conditions such as extreme cold hindering operations, extreme heat
reducing pipeline and compression efficiencies, and hurricane activity affecting
offshore operations. Demand comes from use of natural gas for central heating,
to generate electricity, and as a feedstock for commercial or industrial use.
Gas is currently stored in the summer months when heating demand is low and gas
is withdrawn in winter when heating demand is high.
After a year of robust pricing in 2001 (AECO gas averaged $6.30/mcf), the year
2002 started off with much more modest pricing ($3.67/mcf for the first nine
months). This led to a significant drop in industry drilling activity through
the year that has resulted in a reduction of North American supply capability in
the near term. In addition, hurricane activity in the Gulf of Mexico through the
summer and into early fall caused significant supply disruptions. On the demand
side, economic activity has not rebounded, but hot weather in North America over
the summer resulted in additional gas fired electricity demand and very cold
weather in the central and northeast parts of the continent this winter have
resulted in significant year-over-year demand increases. Early in 2003, natural
gas in storage is at historically low levels and concerns are being raised about
the ability to re-fill storage to adequate levels by the end of the summer in
time for the next winter heating season due to supply declines. Pricing
year-to-date has been exceptionally strong and is expected to remain so for the
next several years.
SIGNIFICANT STEP CHANGE IN NATURAL GAS PRICES
(HISTORICAL PRICE BASED ON DAILY AVERAGE SPOT PRICES)
(FORWARD STRIP PRICING BASED ON YEAR STRIP CONTRACTS AS AT FEBRUARY 28, 2003)
AECO GAS $CDN / MCF
- -------------------
1996 - $1.39
1997 - $1.88
1998 - $2.04
1999 - $2.96
2000 - $5.02
2001 - $6.30
2002 - $4.07
2003 - $8.04
2004 - $6.58
2005 - $5.75
2006 - $5.29
2007 - $5.26
CRUDE OIL
Crude oil can be transported by pipeline, tank truck, and ocean tanker. As such,
oil is truly a world commodity and is influenced by global supply and demand
fundamentals. World supply is dominated by the OPEC cartel and by production
changes within a few key non- OPEC exporting countries (e.g. Russia and other
Former Soviet Union nations, Norway). World demand fluctuates with the global
economies.
Oil entered 2002 with comfortable inventories and the prospect of global
oversupply. As the year progressed, overall tightening of OPEC quotas and
supply, combined with several global supply disruptions (a delay in renewing the
Iraq oil for food program, hurricane activity in the Gulf of Mexico, a general
strike in Venezuela) significantly reduced inventories.
Early in 2003, crude oil inventories have been reduced further and the potential
for hostilities in the Middle East remains high. Crude oil prices have increased
to levels not seen since the 1990 Gulf War.
CRUDE OIL HISTORICAL AND FORWARD STRIP PRICES
(HISTORICAL PRICE BASED ON DAILY AVERAGE SPOT PRICES)
(FORWARD STRIP PRICING BASED ON YEAR STRIP CONTRACTS AS AT FEBRUARY 28, 2003)
(US$/BBL/WTI)
- -------------
1996 - $22.01
1997 - $20.61
1998 - $14.43
1999 - $19.24
2000 - $30.20
2001 - $25.97
2002 - $26.08
2003 - $31.56
2004 - $25.43
2005 - $23.82
2006 - $23.70
2007 - $23.40
ROYALTIES (NET OF ARTC)
2002 2001 % CHANGE
- --------------------------------------------------------------------------------
Royalty expense (net of ARTC) ($ millions) $ 56.5 $ 73.2 (23%)
Per BOE $ 5.13 $ 6.73 (24%)
Royalties as % of sales revenues
- with hedging revenue 18% 19% (9%)
- excluding hedging revenue 19% 22% (10%)
================================================================================
Lower royalties are the direct result of lower revenues. The overall decrease in
the royalty rate is due to lower natural gas prices year-over-year. Hedging
gains, that do not attract royalties and result in lower royalty expense as a
percentage of sales, were substantial for both 2002 and 2001 as previously
discussed.
OPERATING EXPENSES
2002 2001 % CHANGE
- --------------------------------------------------------------------------------
Operating expenses ($ millions) $ 60.8 $ 59.0 3%
Per BOE $ 5.52 $ 5.42 2%
================================================================================
The year-over-year increase of $1.8 million is due, in part, to the 1% increase
in production volumes. On a BOE basis, operating expenses increased 2% over the
2001 level. PrimeWest continues as a low cost producer among the seven largest
oil and gas royalty trusts.
OPERATING MARGIN
($/BOE) 2002 2001 % CHANGE
- --------------------------------------------------------------------------------
Sales price and other revenue (1) $ 29.11 $ 34.93 (17%)
Royalties (5.13) (6.73) (24%)
Operating expenses (5.52) (5.42) 2%
- --------------------------------------------------------------------------------
Operating margin $ 18.46 $ 22.78 (19%)
================================================================================
(1) Includes hedging and sulphur
The decrease in operating margin reflects lower natural gas prices in 2002
compared to 2001 and PrimeWest's 62% natural gas production weighting in 2002,
partially offset by lower royalty expense. In 2001, record high prices for
natural gas benefited natural gas weighted producers including PrimeWest.
LOW COST OPERATIONS: TARGET $6.00 - $6.50 PER BOE OF OPERATING EXPENSES FOR 2003
OPERATING EXPENSES ($/BOE)
- --------------------------
1998 - $5.40
1999 - $5.23
2000 - $5.09
2001 - $5.42
2002 - $5.52
PRIMEWEST IS A LOW COST OPERATOR AMONG THE SEVEN LARGEST CONVENTIONAL OIL AND
GAS ROYALTY TRUSTS.
OPERATING MARGIN ($/BOE)
- ------------------------
1998 - $5.95
1999 - $9.62
2000 - $21.33
2001 - $22.78
2002 - $18.46
LOWER GAS PRICES AND 62% NATURAL GAS WEIGHTING RESULTED IN A LOWER OPERATING
MARGIN IN 2002.
GENERAL & ADMINISTRATIVE EXPENSES
2002 2001 % CHANGE
- --------------------------------------------------------------------------------
General & administrative expense ($ millions) $ 11.3 $ 10.4 9%
Per BOE $ 1.02 $ 0.96 6%
- --------------------------------------------------------------------------------
Excluding $0.8 million of 2002 expenses related to the NYSE listing, the full
year 2002 result would have been $10.5 million or $0.95 per BOE.
UNIT APPRECIATION RIGHTS EXPENSE
Unit Appreciation Rights (UAR) expense of $6.1 million (2001 - $4.2 million)
relates to PrimeWest's long-term incentive program for employees, directors and
officers. The program rewards employees based on total unitholder return, which
is comprised of cumulative distributions on a reinvested basis plus growth in
unit price. Total unitholder return was 19.5% in 2002 (2001 - a loss of 6%). No
benefit accrues to employees with respect to the first 5% of total unitholder
return. Expenses related to the UAR plan are recorded on a mark-to-market basis,
whereby increases or decreases in the valuation of the UAR liability are
reported quarterly, as a charge to the income statement, over the six year life
of the unit appreciation rights.
Unit appreciation rights in a trust are similar to stock options in a
corporation. The intent is to align employee and unitholder interests. The
outcome is expected to be a modest dilution to unitholders' positions over time.
Effective January 1, 2002 the method of accounting for the long-term incentive
plan was changed to comply with new CICA accounting standard 3870. The
calculation of the long-term incentive liability now includes vested and
unvested UARs. Previously, only vested UARs were included. The Trust has the
option of paying cash to settle the long term incentive liability. The long-term
incentive liability has been reclassified as equity on the balance sheet as the
Trust intends to settle the liability in the form of Trust Units.
COSTS OUTLOOK
PrimeWest's operating costs in 2002 and 2001 were among the lowest of the seven
largest conventional oil and gas royalty trusts. The acquisition of low cost
production at Caroline and Peace River Arch effective January 1, 2003, is
expected to reinforce our low cost leadership position. We are targeting
stabilization in our cost structure in 2003 as follows:
OPERATIONS:
o Per BOE costs of approximately $6.00 - $6.50 reflecting:
o lower costs associated with the Caroline and Peace River Arch
properties,
o continued rationalization of operations, particularly at
Caroline,
o offsetting the above, we expect to have higher power costs,
and third party processing fees for 2003.
GENERAL AND ADMINISTRATIVE:
o per BOE costs of $0.90. Increases in the cost of employee benefits and
corporate governance are expected to be offset by continued process
improvements.
At PrimeWest, we are committed to contain costs during all phases of the
commodity price cycle.
LOW COST OPERATIONS: CASH G&A TARGETED AT $0.90 PER BOE FOR 2003
MANAGEMENT FEES/INTERNALIZATION COSTS
($ millions) 2002 2001
- --------------------------------------------------------------------------------
Cash management fees $ 4.0 $ 6.4
Non-cash management fees 1.4 1.8
Non-cash internalization costs 13.1 --
Acquisition/disposition fees 0.4 13.0
1% retained royalty 1.3 3.4
Purchase of 1% retained royalty 13.2 --
- --------------------------------------------------------------------------------
$ 33.4 $ 24.6
================================================================================
On November 4, 2002, unitholders voted, by a 92% majority, to internalize
management at a cost of $26.3 million. Approximately $13.2 million of cash
consideration related to the acquisition of the 1% retained royalty and was
recorded as an acquisition. The balance of the consideration was paid in the
form of Class A Exchangeable Shares of PrimeWest Energy Inc., exchangeable for
approximately 491,000 Trust Units as at the effective date, and was charged to
expense. In addition, the internalization transaction included retention
provisions for senior management of $3.5 million payable in the form of Class A
Exchangeable Shares over a five year vesting period, and payment of $1.5 million
to terminate a management incentive program.
From inception in 1996 through September 30, 2002, PrimeWest Management Inc.
received a management fee of 2.5% of net production revenue as well as a
quarterly allocation of Trust Units and a 1% retained royalty. The 1% retained
royalty was based on the net cash flow from operations and the proceeds from
property dispositions.
In addition, PrimeWest Management Inc. was also entitled to an acquisition fee
representing 1.5% of capital spent on asset or corporate acquisitions and a
disposition fee representing 1.25% of proceeds received from asset dispositions.
The $13.0 million of acquisition/disposition fees in 2001 related primarily to
the Cypress acquisition.
WE CARE: ELIMINATED MANAGEMENT FEES EFFECTIVE OCTOBER 1, 2002
INTEREST EXPENSE
Interest expense decreased to $10.8 million in 2002 compared to $13.8 million in
2001. Lower year-over-year average debt levels and lower interest rates
contributed to the decrease.
2002 2001
- --------------------------------------------------------------------------------
Interest expense (millions) $ 10.8 $ 13.8
Year end net debt level (millions) $ 225.4 $ 224.4
Year end debt level per Trust Unit $ 5.79 $ 6.84
- --------------------------------------------------------------------------------
Average cost of debt 4.6% 5.4%
================================================================================
DEPLETION, DEPRECIATION AND AMORTIZATION
The 2002 depletion, depreciation and amortization (DD&A) rate was $16.51 per BOE
compared to $14.66 per BOE for 2001. The 2002 rate reflects a full year of
production from the Cypress properties acquired on March 29, 2001.
The 2002 and 2001 DD&A rates are inflated relative to the acquisition cost of
reserves due to the requirement to account for future income tax liabilities
associated with these reserves. Absent this tax adjustment, the 2002 DD&A rate
would have been lower by approximately $5.00 per BOE. (See also Income Taxes -
Trust.)
CEILING TEST
PrimeWest performs a ceiling test at each balance sheet date, which compares the
net book value of capital assets (i.e. the value of capital assets reflected on
the balance sheet, net of DD&A) with an estimate of the future net revenue from
proved reserves (as determined by independent engineers) less estimated future
general and administrative costs, debt servicing costs, and applicable income
taxes.
Performing this test at December 31, 2002, using commodity prices of AECO $5.59
per mcf for natural gas and $US 29.39 per barrel WTI for crude oil, a ceiling
test surplus of $900 million results.
SITE RECLAMATION AND RESTORATION RESERVE
Since the inception of the Trust, PrimeWest has maintained an environmental fund
to pay for future costs related to well abandonment and site clean-up. In 2002,
PrimeWest contributed $0.37 per BOE, totaling $4.1 million for 2002, to this
fund. The fund is used to pay for reclamation and abandonment costs as they are
incurred. In 2002, a total of $3.9 million was paid out of the reserve, leaving
a balance of $0.01 million in the fund at year end.
A provision of $4.0 million was made for site reclamation and abandonment during
2002, compared to $3.5 million for 2001. The provision is based on site
reclamation and abandonment cost estimates made by both PrimeWest and external
engineers and is charged to depletion, depreciation and amortization expense on
a unit of production basis.
The 2003 contribution rate has been set at $0.50 per BOE which is expected to be
sufficient to meet the funding requirements for the future.
INCOME TAXES - TRUST
Current income tax expense of $2.9 million for 2002 (2001 - $2.4 million) is
comprised of the Federal Large Corporations Tax and other capital taxes payable
by PrimeWest Energy Inc.
PrimeWest Energy Inc. manages its operating and financing activities such that
it is not subject to current tax payable, other than the capital taxes noted
above.
Future income taxes are recorded on corporate acquisitions to the extent that
the book value of capital assets acquired exceeds the tax pools acquired. These
future taxes increase the cost basis of the capital assets acquired and are
recovered over time as royalties are paid to the Trust. The income statement for
the year ended December 31, 2002 reflects a future income tax recovery of $32.3
million (2001 - $30.3 million) due primarily to the drawdown of future income
tax liability of $376.3 million recorded as part of the Cypress acquisition. The
future income tax liability was $339.9 million at December 31, 2002 ($362.6
million at December 31, 2001).
The unitholders of the Trust are allocated taxable income based on the amount of
royalty revenue, interest and revenue from direct investments earned
(essentially distributions before crown royalty charges), less certain tax
deductions such as Canadian Oil and Gas Property Expense (COGPE), resource
allowance, unit issue expenses and other direct costs.
INCOME TAXES - UNITHOLDERS
For the 2002 taxation year, unitholders of the Trust were paid $4.80 per Trust
Unit in distributions. Of these distributions, 45%, or $2.16 per Trust Unit is a
tax deferred return of capital and 55%, or $2.64 per Trust Unit, is taxable to
unitholders as other income (taxed at the same rate as interest income). The tax
deferred return of capital reduces the unitholder's adjusted cost base for
purposes of calculating a capital gain or loss upon ultimate disposition of
their Trust Units. It should be noted that this represents the tax treatment for
Canadian residents.
For unitholders resident in the United States, taxability of distributions is
calculated using U.S. tax rules which allow for the deduction of crown royalties
and accounting based depletion. As a result, none of the 2002 distribution is
taxable as dividends, 100% of the 2002 distributions are a tax deferred
reduction to the cost of units for tax purposes.
Unitholders contemplating a disposition may wish to consult the "Unitholder
Information" section on PrimeWest's website and use the adjusted cost base
calculator. Unitholders should always seek independent competent tax advice.
INCOME TAXES - UNITHOLDERS - OUTLOOK
Based on current expectations for cash flow for 2003, it is anticipated that
approximately 55% of 2003 distributions will be taxable and 45% will be tax
deferred, for unitholders resident in Canada. For residents of the United
States, Canadian withholding tax applies to 55% of the distribution.
NET ASSET VALUE
Net asset value (NAV) is a measure of the worth of PrimeWest's underlying assets
- - primarily crude oil, natural gas and natural gas liquids reserves. The value
placed on these reserves is the pre-tax present value of future net cash flows,
discounted at 10% from these reserves, as independently assessed by Gilbert
Laustsen Jung Associates Ltd. (GLJ) as at January 1, 2003. The commodity price
forecast used in this assessment is based on the arithmetic average of three
independent consultants' price forecasts. The present value of reserves reflects
provisions for royalties, operating costs, future capital costs and site
reclamation and abandonment costs, but is prior to deductions for income taxes,
interest costs and general and administrative costs.
This calculation is a "snapshot" in time and is heavily dependent upon future
commodity price expectations at the point in time the "snapshot" is taken.
Accordingly, the NAV as at January 1, 2003 may not reflect fairly the equity
market trading value of PrimeWest. It is also significant to note that NAV
reduces as reserves are produced and net operating cash flow is distributed.
Value is delivered to unitholders through such monthly distributions.
The following table sets forth the calculation of NAV:
As at December 31 ($ million except per Trust Unit amounts) 2002 2001
- ----------------------------------------------------------------------------------------
ASSETS
Present value of net cash flow from established
reserves discounted at 10% $ 923.0 $ 872.6
Hedging mark-to-market (13.6) 50.5
Unproved lands 44.2 55.7
Reclamation fund - 0.8
- ----------------------------------------------------------------------------------------
$ 953.6 $ 979.6
========================================================================================
LIABILITIES
Working capital deficiency $ (0.4) $ (29.4)
Long-term debt (225.0) (195.0)
- ----------------------------------------------------------------------------------------
(225.4) (224.4)
Total net asset value $ 728.2 $ 755.2
- ----------------------------------------------------------------------------------------
Net asset value pre-tax per Trust Unit $ 18.71 $ 23.03
- ----------------------------------------------------------------------------------------
Reference prices - Oil ($US WTI/bbl) $ 25.83 $ 19.68
- Exchange rate ($US/$Cdn) 0.64 0.63
- Natural gas ($Cdn/mcf) $ 5.85 $ 4.03
========================================================================================
The NAV calculation is based on the above reference prices as of January 1, 2003
and 2002 and is highly sensitive to changes in price forecasts over time. Also,
the NAV calculation assumes a "blow down" scenario whereby existing reserves are
produced without being replaced by acquisitions. A major cornerstone of
PrimeWest's strategy is to replace reserves through accretive acquisitions and
capital development.
NET INCOME
($ million) 2002 2001
- --------------------------------------------------------------------------------
Net income $ 0.6 $ 79.5
================================================================================
Net income declined by $78.9 million as a result of significantly lower natural
gas prices, increased DD&A reflecting a full year of Cypress volumes and costs
of $16.7 million associated with the internalization of management.
LIQUIDITY AND CAPITAL RESOURCES
LONG-TERM DEBT
At December 31, 2002, long-term debt, net of working capital was $225.4 million
or $5.79 per Trust Unit, compared to $224.4 million, or $6.84 per Trust Unit at
the end of 2001.
(thousands of dollars) 2002 2001
- --------------------------------------------------------------------------------
Long-term debt $ 225,000 $ 195,000
Working capital deficit 436 29,431
- --------------------------------------------------------------------------------
Net debt 225,436 224,431
Market value of Trust Units and
exchangeable shares outstanding (1) 989,187 834,053
- --------------------------------------------------------------------------------
Total capitalization $ 1,214,623 $ 1,058,484
================================================================================
Net debt as a percentage of total capitalization 19% 21%
================================================================================
(1) Based on December 31 closing price
OUTLOOK - LONG - TERM DEBT
Long-term debt net of working capital in 2003 is expected to increase as a
result of the 2003 capital development program, and the Caroline/Peace River
Arch acquisition which closed on January 23, 2003, partially offset by the net
proceeds of the equity issue which closed on February 13, 2003.
MONTHLY DISTRIBUTIONS AND ACTIVE FINANCIAL MANAGEMENT: CONSERVATIVE BALANCE
SHEET WITH NET DEBT TO CASH FLOW RATIO OF 1.32 TIMES
UNITHOLDERS' EQUITY
On August 16, 2002, Trust Units were consolidated on a 4 to 1 basis in
anticipation of the November 19, 2002 listing on the New York Stock Exchange.
The Trust had 37,004,522 Trust Units outstanding at December 31, 2002 compared
to 31,491,402 Trust Units at the end of 2001. In addition, there are 5,179,278
exchangeable shares (see below) outstanding at year end, exchangeable into a
total of 1,939,864 Trust Units. The weighted average number of Trust Units,
including those issuable by the exchange of exchangeable shares, was 34,134,230
Trust Units for 2002 compared to 25,633,250 for 2001.
During 2002, PrimeWest issued 979,209 Trust Units for $24.1 million pursuant to
the Distribution Reinvestment and Optional Trust Unit Purchase Plans (441,424
Trust Units, $14.1 million in 2001), 153,749 pursuant to the Long-Term Incentive
Plan for employees and 66,853 to PrimeWest Management Inc. pursuant to the
Management Agreement.
Net Debt to Cash Flow (multiple)
1998 - 2.85
1999 - 2.10
2000 - 0.71
2001 - 1.05
2002 - 1.32
Dividends declared were $1.3 million in 2002, compared to $4.1 million in 2001.
Dividends were paid to PrimeWest Management Inc. in conjunction with the
Management Agreement (see discussion under Management Fees).
PrimeWest completed a bought deal financing which closed on November 13, 2002
raising net proceeds of $104.5 million on the issuance of 4.2 million Trust
Units at $26.20 per Trust Unit. Proceeds were used to fund the Caroline/Ells
acquisitions announced in October of 2002 and to reduce outstanding
indebtedness.
EXCHANGEABLE SHARES
Exchangeable shares were issued in connection with both the Venator acquisition
in April 2000 and the Cypress acquisition in March 2001. These shares were
issued to provide a tax-deferred rollover of the adjusted cost base from the
shares being exchanged to the exchangeable shares of PrimeWest. A tax deferral
is not permitted by Canadian tax law when shares are exchanged for Trust Units.
A further 1,363,714 exchangeable shares were issued in 2002 in connection with
the management internalization transaction previously discussed.
The exchangeable shares do not receive cash distributions. In lieu of receiving
cash distributions, the number of Trust Units that the exchangeable shareholder
will receive upon exchange increases each month based on the distribution amount
divided by the market price of the Trust Units on the 15th day of each month.
At December 31, 2002, there were 5.2 million exchangeable shares outstanding.
The exchange ratio on these shares was 0.37454 Trust Units for each exchangeable
share as at year-end.
For purposes of calculating basic per Trust Unit amounts, these exchangeable
shares have been assumed to be exchanged into Trust Units at the current
exchange ratio.
CASH DISTRIBUTIONS
Cash distributions in 2002 totaled $158.0 million, or $4.80 per Trust Unit,
compared to $234.5 million, or $9.24 per Trust Unit in 2001. Commencing in 2003,
PrimeWest pays distributions to registered U.S. unitholders in U.S. funds upon
request. Payments to U.S. unitholders are subject to 15% Canadian withholding
tax, which applies to the taxable portion of the distribution under Canadian tax
law, estimated at 55% for 2003.
Since inception in October of 1996 to December 31, 2002, PrimeWest has
distributed $35.92 per Trust Unit (through December 31, 2001 - $31.12 per Trust
Unit).
UNITS OUTSTANDING AT YEAR END (MILLIONS)
- ----------------------------------------
1998 - 8
1999 - 9
2000 - 13
2001 - 33
2002 - 37
ACCESS TO CAPITAL: EQUITY FINANCING FOR ACQUISITIONS AND DEVELOPMENT
OUTLOOK FOR CASH DISTRIBUTIONS
PrimeWest distributed $0.40 per unit per month for January and February of 2003
and has committed to distributing $0.40 per Trust Unit per month for March and
April of 2003, subject to revision should there be a material change to expected
cash flows during this period. Beyond this time frame, the Board of Directors
will establish a distribution level commensurate with cash flow expectations and
any foreseen internal requirements.
CASH FLOW SENSITIVITIES
Impact on 2003 annual cash available for distribution per unit
(increase/decrease):
- --------------------------------------------------------------------------------
Crude oil price ($US 1.00/bbl WTI increase) 0.10(1)
Natural gas price ($0.10/mcf increase) 0.09(1)
Interest rate (1% increase) (0.04)
Exchange rate ($US 0.01 increase) (0.14)
Production (1,000 BOE/day increase) 0.20
================================================================================
(1) Without the effect of price protection
BUSINESS RISKS
PrimeWest's operations are affected by a number of underlying risks, both
internal and external to the Trust. These risks are similar to those affecting
others in both the conventional oil and gas royalty trust sector and the
conventional oil and gas producers sector. The Trust's financial position,
results of operations, and cash available for distribution to unitholders are
directly impacted by these factors. These factors are discussed under two broad
categories - Commodity Price, Foreign Exchange and Interest Rate Risk; and
Operational and Other Business Risks.
COMMODITY PRICE, FOREIGN EXCHANGE AND INTEREST RATE RISK
The two most important factors affecting the level of cash distributions
available to unitholders are the level of production achieved by PrimeWest, and
the price received for its products. These prices are influenced in varying
degrees by factors outside the Trust's control. Some of these factors include:
o world market forces, specifically the actions of OPEC and other large
crude oil producing countries including Russia, and their implications
on the supply of crude oil;
o world and North American economic conditions which influence the demand
for both crude oil and natural gas and the level of interest rates set
by the governments of Canada and the U.S.;
o weather conditions that influence the demand for natural gas and
heating oil;
o the Canadian/U.S. exchange rate that affects the price received for
crude oil as the price of crude oil is referenced in U.S. dollars;
o transportation availability and costs; and
o price differentials among world and North American markets based on
transportation costs to major markets and quality of production.
To mitigate these risks, PrimeWest has an active hedging program in place based
on an established set of criteria that has been approved by the Board of
Directors. The results of the hedging program are reviewed against these
criteria and the results actively monitored by the Board.
Beyond our hedging strategy, PrimeWest also mitigates risk by having a
well-diversified marketing portfolio and by transacting with a number of
counter-parties and limiting exposure to each counter-party. In 2002,
approximately 30% of natural gas production was sold to aggregators and 70% into
the Alberta short-term or export long-term markets.
The contracts that PrimeWest has with aggregators vary in length. They represent
a blend of domestic and U.S. markets and fixed and floating prices designed to
provide price diversification to our revenue stream.
The primary objective of our commodity risk management program is to reduce the
volatility of our cash distributions, to lock in the economics on major
acquisitions and to protect our capital structure when commodity prices cycle
downwards. In 2002, PrimeWest added $28.1 million ($0.82 per Trust Unit) to our
cash flow through
various physical and financial hedging transactions. In total, PrimeWest hedged
69% of full year crude oil production and 71% of full year natural gas
production net of royalties.
OPERATIONAL AND OTHER BUSINESS RISKS
PrimeWest is also exposed to a number of risks related to its activities within
the oil and gas industry that also have an impact on the amount of cash
available to unitholders. These risks, and the ways in which PrimeWest seeks to
mitigate these risks include, but are not limited to:
RISK:
PRODUCTION
Risk associated with the production of oil and gas - includes well operations,
processing and the physical delivery of commodities to market.
WE MITIGATE BY:
Performing regular and proactive protective well, facility and pipeline
maintenance supported by telemetry, physical inspection and diagnostic tools.
COMMODITY PRICE
Fluctuations in natural gas, crude oil and natural gas liquid prices
WE MITIGATE BY:
Hedging. See page 21 of this MD&A.
TRANSPORTATION
Market risk related to the availability of transportation to market and
potential disruption in delivery systems.
WE MITIGATE BY:
Diversifying the transportation systems on which we rely to get our product to
market.
NATURAL DECLINE
Development risk associated with capital enhancement activities undertaken - the
risk that capital spending on activities such as drilling, well completions,
well workovers and other capital activities will not result in reserve additions
or in quantities sufficient to replace annual production declines.
WE MITIGATE BY:
Diversifying our capital spending program over a large number of projects so
that too much capital is not risked on any one activity. We also have a highly
skilled technical team of geologists, geophysicists and engineers working to
apply the latest technology in planning and executing capital programs. Capital
is spent only after strict economic criteria for production and reserve
additions are assessed.
ACQUISITIONS
Acquisition risk associated with acquiring producing properties at low cost to
renew our inventory of assets.
WE MITIGATE BY:
Continually scanning the marketplace for opportunities to acquire assets. Our
technical acquisition specialists evaluate potential corporate or property
acquisitions and identify areas for value enhancement through operational
efficiencies or capital investment. All prospects are subjected to rigorous
economic review against established acquisition and economic hurdle rates.
RESERVES
Reserve risk in respect of the quantity and quality of recoverable reserves.
WE MITIGATE BY:
Contracting our reserves evaluation to a reputable third party consultant,
Gilbert Laustsen Jung Associates Ltd. (GLJ). The work and independence of GLJ is
reviewed by the Audit and Reserves Committee of the Board of
Directors of PrimeWest. Our strategy is to invest in mature, longer life
properties having a higher proved producing component where the reserve risk is
generally lower and cash flows are more stable and predictable.
ENVIRONMENTAL HEALTH AND SAFETY (EH&S)
Environmental, health and safety risks associated with oil and gas properties
and facilities.
WE MITIGATE BY:
Establishing and adhering to strict guidelines for EH&S including training,
proper reporting of incidents, supervision and awareness. PrimeWest has active
community involvement in field locations including regular meetings with
stakeholders in the area. PrimeWest carries adequate insurance to cover property
losses, liability and business interruption.
These risks are reviewed regularly by the Corporate Governance and Nominating
Committee of the Board, which acts as PrimeWest's Environmental, Health and
Safety Committee.
REGULATION, TAX, ROYALTIES
Changes in government regulations including reporting requirements, income tax
laws, operating practices and environmental protection requirements and royalty
rates.
WE MITIGATE BY:
Keeping informed of proposed changes in regulations and laws to properly respond
to and plan for the effects that these changes may have on our operations.
LIABILITY TO UNITHOLDERS
There is no statutory protection for unitholders from liabilities of the Trust.
WE MITIGATE BY:
Limiting the business of the Trust to the right to receive the net cash flow of
PrimeWest Energy Inc. All of the oil and gas business operations of PrimeWest
are conducted by PrimeWest Energy Inc. PrimeWest Energy Inc. has a vigorous EH&S
program as well as significant insurance protection.