As filed with the Securities and Exchange Commission on
May 7, 2004.
Registration No. 333-
================================================================================
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM F-10
REGISTRATION STATEMENT UNDER
THE SECURITIES ACT OF 1933
Petrofund Energy Trust
(Exact name of Registrant as specified in its charter)
Ontario, Canada 1311 Not Applicable
(Province or other jurisdiction (Primary Standard Industrial (I.R.S. Employer Identification
of incorporation or organization) Classification Number
Code Number (if applicable)) (if applicable))
444-7th Avenue S.W., Suite 600, Calgary, Alberta, Canada T2P 0X8
(403) 218-8625
(Address and telephone number of Registrant's principal executive offices)
CT CORPORATION SYSTEM
111 Eighth Avenue, 13th Floor, New York, NY 10011
(212) 894-8700
(Name, address (including zip code) and telephone number (including area code)
of agent for service in the United States)
---------------------------
Copies to:
Brice T. Voran Keith A. Greenfield
Shearman & Sterling LLP Burnet, Duckworth & Palmer LLP
Commerce Court West 1400, 350-7th Avenue S.W.
199 Bay Street, Suite 4405 Calgary, Alberta, Canada
Toronto, Ontario, Canada M5L 1E8 T2P 3N9
Telephone (416) 360-8484 Telephone (403) 260-0100
Approximate date of commencement of proposed sale of the securities
to the public: As soon as practicable after this Registration Statement is
declared effective.
Province of Alberta, Canada
(Principal jurisdiction regulating this offering)
It is proposed that this filing shall become effective (check appropriate box):
A. |X| Upon filing with the Commission, pursuant to Rule 467(a) (if
in connection with an offering being made contemporaneously in
the United States and Canada).
B. |_| At some future date (check the appropriate box below):
1. |_| pursuant to Rule 467(b) on ( ) at ( ) (designate a
time not sooner than 7 calendar days after filing).
2. |_| pursuant to Rule 467(b) on ( ) at ( ) (designate a
time 7 calendar days or sooner after filing) because
the securities regulatory authority in the review
jurisdiction has issued a receipt or notification of
clearance on ( ).
3. |_| pursuant to Rule 467(b) as soon as practicable after
notification of the Commission by the Registrant or
the Canadian securities regulatory authority of the
review jurisdiction that a receipt or notification of
clearance has been issued with respect hereto.
4. |_| after the filing of the next amendment to this Form
(if preliminary material is being filed).
If any of the securities being registered on this Form are to be
offered on a delayed or continuous basis pursuant to the home jurisdiction's
shelf prospectus offering procedures, check the following box. |_|
CALCULATION OF REGISTRATION FEE
-------------------------------------------------------------------------------------------------------
Title of each class Amount to be Proposed maximum Proposed maximum Amount of
of securities to be registered(1) offering price per trust aggregate offering registration
registered unit price(2) fee(2)
-------------------------------------------------------------------------------------------------------
Trust Units 5,866,475 N/A U.S.$68,487,810 U.S.$8,677.41
-------------------------------------------------------------------------------------------------------
(1) Consists of up to 5,866,475 trust units of the Registrant issuable to
United States residents upon a business combination.
(2) Estimated solely for the purpose of calculating the registration fee, and
based upon the product of Cdn.$7.09 (the average of the high and low prices
of Ultima Energy Trust units on May 3, 2004, on the Toronto Stock Exchange)
times 13,272,569 (the approximate number of Ultima Energy Trust units
outstanding and held by United States residents), divided by 1.374, the
noon buying rate in New York City on May 3, 2004 for cable transfers in
Canadian dollars as certified by the Federal Reserve Bank of New York.
================================================================================
If, as a result of stock splits, stock dividends or similar transactions, the
number of securities purported to be registered on this registration statement
changes, the provisions of Rule 416 shall apply to this Registration Statement.
PART I
INFORMATION REQUIRED TO BE DELIVERED TO OFFEREES OR PURCHASERS
Item 1. Home Jurisdiction Documents
Letter to Unitholders of Ultima Energy Trust
Notice of Meeting of Unitholders and Proxy Statement and
Information Circular dated April 30, 2004 together with the
documents included in Appendices "A" through "E" thereto (the
"Information Circular")
Item 2. Additional Information-- Reconciliation of Financial Statements to
U.S. GAAP
See Comparative Audited Annual Financial Statements as at and
for the years ended December 31, 2003 and 2002, included in
Appendix C to the Information Circular.
Item 3. Informational Legends
See the cover page of the Information Circular.
Item 4. Incorporation of Certain Information by Reference
Not applicable.
Item 5. List of Documents Filed with the Commission
See "Documents Filed as Part of Petrofund's U.S. Registration
Statement" in Part "II" of the Information Circular.
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ULTIMA ENERGY TRUST
NOTICE OF ANNUAL AND SPECIAL
MEETING OF UNITHOLDERS
to be held on
June 4, 2004
- and -
PROXY STATEMENT AND INFORMATION CIRCULAR
with respect to a
BUSINESS COMBINATION
involving
ULTIMA ENERGY TRUST
- and -
PETROFUND ENERGY TRUST
April 30, 2004
NOTICE TO UNITED STATES HOLDERS
The proposed Merger is in respect of the securities of a foreign issuer
that is permitted, under a multijurisdictional disclosure system adopted by the
United States, to prepare the Information Circular in accordance with the
disclosure requirements of applicable Canadian law. Holders of Ultima Units
should be aware that these requirements are different from those of the United
States. The financial statements included herein have been prepared in
accordance with Canadian generally accepted accounting principles and are
subject to Canadian auditing and auditor independence standards. They may not be
comparable to financial statements of United States companies.
Acquisition of Petrofund Units pursuant to the Merger may subject
holders of Ultima Units to tax consequences both in the United States and
Canada. Such consequences for holders of Ultima Units who are resident in, or
citizens of, the United States may not be described fully herein.
Information concerning oil and gas properties, reserves and operations
of Ultima and Petrofund have been prepared in accordance with Canadian
disclosure standards and are not comparable in all respects to similar
information for United States companies. For example, the SEC permits oil and
gas companies, in their filings with the SEC, to disclose only proved reserves
(as defined in SEC rules). Canadian securities laws permit oil and gas
companies, in their filings with Canadian securities regulators, to disclose
proved reserves (defined differently from SEC rules) and probable reserves.
Probable reserves are of higher risk and are generally believed to be less
likely to be recovered than proved reserves. Moreover, "proved reserves," are
calculated in accordance with Canadian practices using forecasted and constant
prices and costs, whereas the SEC requires that the prices and costs be held
constant at prices in effect on the date of the reserve report. In addition,
under Canadian practice, reserves and production are reported using gross
volumes, which are volumes prior to deduction of royalty and similar payments.
The practice in the Unites States is to report reserves and production using net
volumes, after deduction of applicable royalties and similar payments. As a
consequence, the production volumes and reserve estimates in this Information
Circular may not be comparable to those of U.S. domestic companies subject to
SEC reporting and disclosure requirements.
The enforcement by investors of civil liabilities under the United
States federal securities laws may be affected adversely by the fact that Ultima
was created under the laws of the Province of Alberta, Canada and Petrofund was
created under the laws of the Province of Ontario, Canada, that some or all of
the officers, directors and trustees of Ultima, Petrofund and their respective
management companies may be residents of Canada, that some or all of the experts
named in the Information Circular may be residents of Canada and that all or a
substantial portion of the assets of Ultima and Petrofund and of such persons
may be located outside the United States.
No broker, dealer, salesperson or other person has been authorized to
give any information or make any representation other than those contained in
this document and, if given or made, such information or representation must not
be relied upon as having been authorized by Ultima or Petrofund.
THE SECURITIES OFFERED BY PETROFUND PURSUANT TO THE MERGER HAVE NOT
BEEN APPROVED OR DISAPPROVED BY THE UNITED STATES SECURITIES AND EXCHANGE
COMMISSION OR ANY OTHER SECURITIES REGULATORY AUTHORITY NOR HAS THE UNITED
STATES SECURITIES AND EXCHANGE COMMISSION OR ANY OTHER SECURITIES REGULATORY
AUTHORITY PASSED UPON THE ACCURACY OR ADEQUACY OF THIS DOCUMENT. ANY
REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE.
This Information Circular includes financial statements audited by
Arthur Andersen LLP for which neither Ultima nor Petrofund obtained the consent
of Arthur Andersen LLP to the use of their auditors' report. The consent of
Arthur Andersen LLP was not obtained because, on June 3, 2002, Arthur Andersen
LLP ceased to practice public accounting in Canada. See "Additional Information
Regarding Petrofund Energy Trust - Information Relating to Arthur Andersen LLP".
[LOGO] [GRAPHIC OMITTED]
ULTIMA VENTURES CORP.
April 30, 2004
Dear Fellow Unitholder:
You are invited to attend the annual and special meeting (the "Meeting") of the
holders ("Ultima Unitholders") of Trust Units ("Ultima Units") of Ultima Energy
Trust ("Ultima") to be held in the Chambers Room located on the conference level
at 350 - 7th Avenue S.W., Calgary, Alberta on Friday, June 4, 2004 at 10:30 a.m.
(Calgary time) for the purposes set forth in the accompanying Notice of Annual
and Special Meeting. At the Meeting, among other things, Ultima Unitholders will
be asked to consider and vote upon a merger involving Ultima and Petrofund
Energy Trust ("Petrofund"). As a result of the merger, Petrofund will acquire
all of the assets and liabilities of Ultima, and Ultima Unitholders will
receive, in exchange for each Ultima Unit held, 0.442 of a trust unit
("Petrofund Units") of Petrofund (the "Merger"). The merged trust will continue
to be known as Petrofund Energy Trust. Ultima Unitholders will also receive, on
the business day prior to completion of the Merger, an aggregate of $10 million
in the form of a one-time special distribution, estimated to be $0.17 per Ultima
Unit (the "Special Distribution"). Former Ultima Unitholders who are holders of
record of Petrofund Units on June 16, 2004 (and any subsequent record date for
distributions to Petrofund Unitholders) will also be entitled to receive
distributions from Petrofund following the closing date of the Merger.
For the Special Distribution and Merger to proceed, it must be approved by at
least 66 2/3% of the votes cast by Ultima Unitholders attending the Meeting and
voting on the proposal in person or by proxy. If such approval is obtained and
if other conditions to the Special Distribution and Merger becoming effective
are satisfied or waived, it is expected that the Special Distribution and Merger
will be completed on or about June 16, 2004.
The board of directors of Ultima Ventures Corp., based upon, among other things,
a fairness opinion delivered by its financial advisor, CIBC World Markets Inc.,
that the consideration to be received by Ultima Unitholders pursuant to the
Special Distribution and Merger is fair, from a financial point of view, to the
Ultima Unitholders, has determined unanimously that the Special Distribution and
Merger is in the best interests of Ultima and the Ultima Unitholders and has
unanimously resolved to recommend that Ultima Unitholders vote in favour of the
Special Distribution and Merger.
All of the directors and senior officers of Ultima Ventures Corp. have entered
into Support Agreements with Petrofund agreeing to vote the Ultima Units held by
them in favour of the Special Distribution and Merger.
The accompanying Information Circular provides a detailed description of the
Special Distribution and Merger and certain information about Petrofund and
Ultima, as well as the other matters to come before the Meeting. Please give
this material your careful consideration, and, if you require assistance,
consult your financial, income tax or other professional advisor.
To be represented at the Meeting, you must either be a registered Ultima
Unitholder and attend the Meeting in person or complete and sign the enclosed
form of proxy and forward it so that the form of proxy is received and deposited
with Computershare Trust Company of Canada, by mail or facsimile to
Computershare Trust Company of Canada, 100 University Avenue, 9th Floor,
Toronto, Ontario M5J 2Y1, fax number: 905-771-4414, at least 24 hours (excluding
Saturdays, Sundays and holidays) prior to the time of the Meeting or any
adjournment thereof.
Yours very truly,
(signed) Brian Gieni
S. BRIAN GIENI
President and Chief Executive Officer
of Ultima Ventures Corp.
| Suite 1000,350 - 7th Avenue SW
| Calgary, AB Canada T2P 3N9
| ph: 403 264.5709 fx: 403 264.6103
|
| ultimatrust.com
[LOGO] [GRAPHIC OMITTED]
ULTIMA ENERGY TRUST
NOTICE OF ANNUAL AND SPECIAL MEETING OF THE UNITHOLDERS
TAKE NOTICE THAT the annual and special meeting (the "Meeting") of
unitholders (the "Ultima Unitholders") of Ultima Energy Trust ("Ultima") will be
held in the Chambers Room located on the conference level at 350 - 7th Avenue
S.W., Calgary, Alberta on Friday, June 4, 2004 at 10:30 a.m. (Calgary time) for
the following purposes:
1. to receive and consider the consolidated audited comparative financial
statements of Ultima for the year ended December 31, 2003 and the
report of the auditors thereon;
2. to elect the directors of Ultima Ventures Corp. ("Ultima Co") for the
ensuing year;
3. to elect the directors of Ultima Acquisitions Corp. ("AcquireCo") for
the ensuing year;
4. to appoint the auditors of Ultima, Ultima Ventures Trust, Ultima Co and
AcquireCo for the ensuing year;
5. to consider, and if thought fit, to pass a special resolution in the
form set forth in Appendix "A" to the accompanying Proxy Statement and
Information Circular (the "Information Circular") to approve the merger
of Ultima with Petrofund Energy Trust ("Petrofund"), on the basis that
each Ultima Unitholder would receive 0.442 of a trust unit of Petrofund
in exchange for each trust unit ("Ultima Units") of Ultima (the
"Merger") on the terms and conditions described in the Information
Circular, and to effect all other transactions ancillary to or which
are necessary to implement the Merger as described in the Information
Circular, including, without limitation, the payment of a one-time
special distribution by Ultima in the aggregate amount of $10 million;
and
6. to transact such other business as may properly come before the
Meeting.
Information relating to items 1 through 5 above is set forth in the
accompanying Information Circular.
An Ultima Unitholder may attend the Meeting in person or may be
represented thereat by proxy. A form of proxy for use at the Meeting or any
adjournment thereof is enclosed with this Notice. Ultima Unitholders who are
unable to attend the Meeting are requested to date, sign and return the enclosed
form of proxy to the transfer agent of Ultima, Computershare Trust Company of
Canada ("Computershare"), by mail or facsimile to Computershare, 100 University
Avenue, 9th Floor, Toronto, Ontario, M5J 2Y1 (a self-addressed envelope is
enclosed), fax number: 905-771-4414. In order to be valid, proxies must be
received by Computershare at least 24 hours, excluding Saturdays, Sundays and
holidays, prior to the time of the Meeting or any adjournment thereof.
Ultima Unitholders of record as of April 19, 2004, the record date, are
entitled to notice of the Meeting. Holders of Ultima Units issued subsequent to
the date of this Information Circular and prior to the date of the Meeting are
also entitled to attend and vote at the Meeting. If an Ultima Unitholder has
transferred the ownership of any of his, her or its Ultima Units after the
record date and the transferee of those Ultima Units produces properly endorsed
certificates or otherwise establishes that he, she or it owns the Ultima Units
and demands, not later than 10 days before the Meeting, that his or her name be
included in the list before the Meeting, then the transferee shall be entitled
to vote such Ultima Units at the Meeting.
DATED at Calgary, Alberta the 30th day of April, 2004.
By Order of COMPUTERSHARE TRUST COMPANY OF CANADA,
As Trustee of ULTIMA ENERGY TRUST
"Karen Biscope"
KAREN BISCOPE
Account Manager
TABLE OF CONTENTS
Notice of Meeting..............................................................i
Forward-Looking Statements.....................................................1
Exchange Rate of Canadian Dollar...............................................2
Summary........................................................................3
Glossary of Terms.............................................................12
Abbreviations.................................................................17
Conversion....................................................................17
PART I - General Proxy Materials
and Annual and Special Meeting Matters 18
Solicitation of Proxies.......................................................18
Appointment of Proxies........................................................18
Revocation of Proxies.........................................................19
Exercise of Discretion with Respect to Proxies................................19
Advice to Beneficial Holders of Ultima Units..................................19
Voting Securities and Principal Holders of Voting Securities..................20
Annual Meeting Matters........................................................21
Consideration of Financial Statements.....................................21
Election of Directors Until Completion to the Merger......................21
Appointment of Auditors Until Completion of the Merger....................22
PART II - The Merger 22
The Merger....................................................................22
Background to the Merger..................................................22
Reasons for the Merger....................................................24
Recommendation of the Ultima Board of Directors...........................25
Effect of the Merger upon Ultima Unitholders..................................26
General...................................................................26
Special Distribution......................................................26
Treatment of Ultima Rights................................................27
Effect on Distributions...................................................27
Exchange of Ultima Certificates...........................................27
Details of the Merger.........................................................28
Special Distribution and Unitholder Indemnity Agreement...................29
The Combination Agreement.................................................29
Fairness Opinion..............................................................37
Interests of Insiders in the Merger and
Intentions of Certain Insiders................................................37
Canadian Federal Income Tax Considerations....................................38
United States Federal Income Tax Considerations...............................44
Selected Pro Forma Information Relating to Petrofund..........................50
Selected Pro Forma Combined Financial Information.........................50
Selected Combined Operational Information.................................51
Pro Forma Combined Capitalization.........................................52
Risk Factors..................................................................52
Stock Exchange Listings.......................................................52
Timing........................................................................53
Expenses of the Merger........................................................53
Interests Of Experts..........................................................53
Other Legal Matters...........................................................53
Resale of Petrofund Securities............................................53
Information for United States Holders.....................................54
Documents Filed as Part of Petrofund's U.S.
Registration Statement........................................................54
Availability of Disclosure Documents..........................................54
PART III - Additional Information
Regarding Ultima Energy Trust 55
General...................................................................55
Distributions.............................................................55
Trust Unit Price Range and Trading Volumes................................55
Executive Compensation....................................................56
Statement of Corporate Governance Practices...............................62
PART IV - Additional Information
Regarding Petrofund Energy Trust 67
General...................................................................67
Distributions.............................................................67
Trust Unit Price Range and Trading Volumes................................68
Information Relating to Arthur Andersen LLP...............................69
Consents......................................................................70
Consent of Bennett Jones LLP..............................................70
Consent of Gilbert Laustsen Jung Associates Ltd...........................70
Consent of McDaniel & Associates Consultants Ltd..........................70
Consent of Collins Barrow Calgary LLP.....................................71
Consent of CIBC World Markets Inc.........................................71
Consent of Deloitte & Touche LLP..........................................72
Disclosure in Lieu of Consent of Arthur
Andersen LLP..............................................................73
Interest of Insiders in Material Transactions.................................73
Indebtedness of Directors, Executive Officers
and Senior Officers...........................................................73
Other Matters.................................................................73
Questions and Other Assistance................................................73
Approval and Certification....................................................74
Appendix "A" Text of Special Resolution of
Unitholders of Ultima Energy Trust...........................A-1
Appendix "B" Information Relating to Petrofund
Energy Trust.................................................B-1
Appendix "C" Information Relating to Ultima
Energy Trust.................................................C-1
Appendix "D" Unaudited Pro Forma Combined
Financial Statements of Petrofund
Energy Trust.................................................D-1
Appendix "E" Fairness Opinion of CIBC World
Markets Inc..................................................E-1
-i-
FORWARD-LOOKING STATEMENTS
Certain statements contained in the accompanying Information Circular
under the headings "Background to the Merger", "Reasons for the Merger",
"Recommendation of the Ultima Board of Directors" and "Selected Pro Forma
Information Relating to Petrofund", in addition to certain statements contained
elsewhere in this document, are "forward-looking statements", are prospective in
nature and may be indicated by words such as "anticipate", "continue",
"estimate", "expect", "may", "will", "project", "should", "believe" and similar
expressions. 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 such forward-looking statements. Ultima, Ultima Co,
Ventures Trust, AcquireCo, the Manager and Ultima Energy believe the
expectations reflected in these forward-looking statements are reasonable, but
no assurance can be given that these expectations will prove to be correct and
such forward-looking statements included in this Information Circular should not
be unduly relied upon. These statements speak only as of the date of this
Information Circular or as of the date specified in this Information Circular,
as the case may be.
In particular, this Information Circular contains forward-looking
statements pertaining to, among other things, the following:
o oil and natural gas production levels;
o the size of the oil and natural gas reserves in which Ultima,
Ventures Trust and Ultima Energy hold working interests and/or
royalty interests;
o the size of the oil and natural gas reserves in which Petrofund
and Petrofund Co hold working interests and/or royalty interests;
o projections of market prices, production costs and development
capital;
o future currency exchange rates;
o supply and demand for oil and natural gas; and
o treatment under applicable tax laws and other governmental
regulatory regimes.
Also, the 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 Information Circular:
o volatility in market prices for oil and natural gas;
o liabilities inherent in oil and natural gas operations;
o uncertainties associated with estimating reserves volumes and
values;
o competition for, among other things, capital, acquisitions of
reserves and skilled personnel;
o incorrect assessments of the value of acquisitions;
o geological, technical, drilling and processing problems;
o fluctuations in foreign exchange and interest rates and stock
market volatility;
o changes in income tax laws or changes in tax laws and incentive
programs relating to the oil and gas industry and income trusts;
and
o the other factors discussed under "Competitive Conditions and Risk
Factors" in the Renewal Annual Information Form of Ultima dated
April 30, 2004 attached as part of
-1-
Appendix "C" of this Information Circular and under "Risk Factors"
in the Renewal Annual Information Form of Petrofund dated March
15, 2004 attached as part of Appendix "B" of this Information
Circular.
These factors should not be construed as exhaustive. None of Ultima,
Ventures Co, Ventures Trust, AcquireCo, the Manager and Ultima Energy undertakes
any obligation to publicly update or revise any forward-looking statements.
EXCHANGE RATE OF CANADIAN DOLLAR
Except as otherwise indicated, all dollar amounts set forth in this
Information Circular are in Canadian dollars. The following table sets forth:
(i) the rates of exchange for Canadian dollars, expressed in United States
dollars, in effect at the end of each of the periods indicated; (ii) the average
of exchange rates in effect on the last day of each month during such periods;
and (iii) the high and low exchange rates during each such periods, in each case
based on the noon buying rate in New York City for cable transfers in Canadian
dollars as certified for customs purposes by the Federal Reserve Bank of New
York.
Year ended December 31,
---------------------------------
2003 2002 2001
---------------------------------
Rate at end of period 0.7710 0.6362 0.6277
Average rate during period 0.7146 0.6369 0.6457
High 0.6382 0.6198 0.6234
Low 0.7733 0.6616 0.6697
On April 29, 2004 the noon buying rate for $1.00 Canadian was $0.7301
United States.
-2-
SUMMARY
This Summary is qualified in its entirety by the more detailed
information appearing elsewhere in this Information Circular, including the
Appendices hereto. Capitalized terms not otherwise defined herein have the
meaning assigned thereto in the Glossary of Terms.
The Meeting
The Meeting will be held on Friday, June 4, 2004 at 10:30 a.m. (Calgary
time) in the Chambers Room located on the conference level at 350 - 7th Avenue
S.W., Calgary, Alberta, for the purposes set forth in the accompanying Notice of
Annual and Special Meeting. The business of the Meeting will be to elect the
directors of each of Ultima Co and AcquireCo (to serve only until such time as
the Merger is completed), to appoint the auditors of Ultima, Ventures Trust,
Ultima Co and AcquireCo (to serve only until such time as the Merger is
completed), to consider and vote upon the Special Distribution and Merger
(including certain ancillary matters related to the Merger) and to attend to
other related business. The Merger will result in the merger of Petrofund and
Ultima on the terms described herein.
Petrofund
Petrofund is a royalty trust created under the laws of the Province of
Ontario in 1988. Petrofund's primary source of income is from a 99% net royalty
interest granted by Petrofund Co. Petrofund Co acquires, manages, and disposes
of petroleum and natural gas rights and royalties and related property rights
and interests located primarily in western Canada. Petrofund makes monthly cash
distributions to the Petrofund Unitholders, which are derived from Petrofund's
cash flow from its properties. Certain additional information in respect of
Petrofund is set forth under the heading "Additional Information Regarding
Petrofund Energy Trust" and in Appendix "B" to this Information Circular.
Ultima
Ultima is an open-end investment trust formed under the laws of the
Province of Alberta in 1996. Ultima's primary source of income is from petroleum
and natural gas working interests and related assets which Ultima Co, on behalf
of Ventures Trust, and Ultima Energy hold and from distributions from Ventures
Trust in respect of cash flow attributable to the 11.7136% net royalty interest
held by Ventures Trust in the Weyburn Unit located in southeastern Saskatchewan.
Ultima makes monthly cash distributions to the Ultima Unitholders, which are
derived from its assets. Certain additional information in respect of Ultima is
set forth under the heading "Additional Information Regarding Ultima Energy
Trust" and in Appendix "C" to this Information Circular.
Effect of the Merger Upon Ultima Unitholders
General
After giving effect to the Merger, Petrofund will have acquired all of
the Ultima Assets and assumed all of the Assumed Liabilities, and former Ultima
Unitholders will become holders of Petrofund Units on the basis of 0.442 of a
Petrofund Unit for each issued and outstanding Ultima Unit. The Merger is
structured to be a tax deferred event such that the exchange of Ultima Units for
Petrofund Units will not result in a taxable event to Ultima Unitholders for
Canadian tax purposes. See "Canadian Income Tax Considerations".
-3-
Assuming completion of the Merger whereby all Ultima Unitholders
receive Petrofund Units for their Ultima Units, there will be approximately
99,233,252 Petrofund Units issued and outstanding, subject to changes due to the
exercise of outstanding Ultima Rights and the rounding to the nearest whole
number of fractional Petrofund Units and assuming that all outstanding
exchangeable shares of Petrofund Co are exchanged for Petrofund Units.
Immediately following the Merger and assuming that all of the outstanding
exchangeable shares of Petrofund Co are exchanged for Petrofund Units, current
Petrofund Unitholders will hold approximately 73,682,400 Petrofund Units,
representing approximately 74% of the issued and outstanding Petrofund Units,
and former holders of Ultima Units will hold approximately 25,550,852 Petrofund
Units, representing approximately 26% of the issued and outstanding Petrofund
Units. As of April 19, 2004, a total of approximately 2,028,639 Ultima Rights
were outstanding which, based on the adjustment provisions, the Ultima
Employment Agreements and the Exchange Ratio, could result in an additional
896,658 Petrofund Units being issued to former securityholders of Ultima in
connection with the Merger.
See "Effect of the Merger Upon Ultima Unitholders -- General".
Special Distribution
If the Ultima Special Resolution is approved at the Meeting, a record
date will be announced for the Special Distribution. Ultima Unitholders of
record on the record date set for the Special Distribution will be entitled to a
distribution from Ultima in the amount of $10 million divided by the number of
Ultima Units outstanding on such record date (or approximately $0.17 per Ultima
Unit assuming 59,835,996 Ultima Units are outstanding). The record date will be
the date which is at least seven business days following approval of the Ultima
Special Resolution, but which will be not later than the business day
immediately prior to the Closing Date of the Merger. Therefore, if the Meeting
is held as currently proposed on June 4, 2004 and the Closing Date is held as
currently proposed on June 16, 2004, the record date for the Special
Distribution will be June 15, 2004. Ultima will issue a press release announcing
the actual record date for the Special Distribution at least seven business days
prior to the record date. It is possible that the Special Distribution is
approved by the Ultima Unitholders and paid by Ultima on the business day prior
to the Closing Date and that the Merger is not completed.
See "Effect of the Merger Upon Ultima Unitholders --
Special Distribution".
Effect on Distributions
Distributions paid to Ultima Unitholders for the months of April and
May 2004 will not be affected by the proposed Merger and will be paid in the
usual manner. Therefore, Ultima Unitholders of record on April 30, 2004 and May
31, 2004 will receive their regular monthly cash distribution from Ultima on May
17, 2004 and June 15, 2004, respectively. Assuming the Merger becomes effective
on June 16, 2004, Petrofund Unitholders of record on June 16, 2004, including
former Ultima Unitholders, will receive a cash distribution from Petrofund on
June 30, 2004, and will receive monthly distributions from Petrofund in a
similar manner in the future. Former Ultima Unitholders who are Petrofund
Unitholders of record on June 16, 2004 (and any subsequent record date for
distributions to Petrofund Unitholders) will be entitled to receive
distributions from Petrofund following the Closing Date of the Merger without
any further action required on their part provided they have exchanged their
certificates representing Ultima Units for Petrofund Units on or prior to the
sixth anniversary of the Closing Date.
See "Effect of the Merger Upon Ultima Unitholders -- Effect on
Distributions" and "Effect of the Merger Upon Ultima Unitholders -- Exchange of
Ultima Certificates".
-4-
Exchange of Ultima Certificates
After the Closing Date, certificates formerly representing Ultima Units
shall only represent the right to receive Petrofund Units which a former Ultima
Unitholder is, except as set forth below, entitled to receive pursuant to the
Merger.
A form of letter of transmittal (printed on yellow paper) containing
instructions with respect to the surrender of certificates representing Ultima
Units has been forwarded to registered Ultima Unitholders for use in exchanging
their certificates. Upon surrender of properly completed letters of transmittal
together with certificates representing Ultima Units to Computershare Trust
Company of Canada, certificates for the appropriate number of Petrofund Units
will be issued, subject to any withholdings as required by law.
No fractional Petrofund Units shall be issued to former Ultima
Unitholders pursuant to the Merger. In the event that the Exchange Ratio would
otherwise result in an Ultima Unitholder being entitled to a fractional
Petrofund Unit, an adjustment will be made to the nearest whole number of
Petrofund Units and a certificate representing the resulting whole number of
Petrofund Units will be issued. In calculating such fractional interests, all
Ultima Units held by a registered holder of Ultima Units immediately prior to
the Closing Date shall be aggregated.
The Combination Agreement provides that any certificate representing
Ultima Units that is not validly deposited with Computershare Trust Company of
Canada within six years of the Closing Date shall cease to represent a claim or
interest of any kind or nature in Petrofund, and the Petrofund Units to which
the holder of such certificate would have otherwise been entitled shall be
deemed to have been surrendered to Petrofund, together with all entitlements to
distributions and interest thereon held for such holder.
See "Effect of the Merger Upon Ultima Unitholders -- Exchange of Ultima
Certificates".
Recommendation of the Ultima Board of Directors
The Ultima Board of Directors has determined unanimously that the
Special Distribution and Merger are in the best interests of Ultima and the
Ultima Unitholders and unanimously recommends that Ultima Unitholders vote in
favour of the Ultima Special Resolution. In coming to its conclusion and
recommendation, the Ultima Board of Directors considered a number of factors
including the following:
(a) the expectation that the Merger will result in a mutual fund trust
that is financially and operationally stronger than Ultima,
enabling it to more effectively participate and compete in the
acquisition and development of oil and natural gas and the
production and marketing of oil and natural gas under a variety of
economic conditions;
(b) the improved liquidity of the investment anticipated for Ultima
Unitholders and the improved access to capital for the combined
entity that is expected to result from the increase in the market
capitalization of the combined entity;
(c) the Fairness Opinion from CIBC World Markets;
(d) the Special Distribution;
(e) the timing of the record dates for monthly distributions of each
of Ultima and Petrofund and the Closing Date;
-5-
(f) the increased efficiencies that are expected to result in reduced
general and administrative costs on a per BOE basis;
(g) that the Merger will enable Ultima Unitholders to continue to
participate in a larger oil and gas royalty trust with a proven
management team;
(h) increased diversification and property synergies that are
anticipated to result from the combination of the high quality
asset bases of each of Ultima and Petrofund;
(i) the increased exposure to a broader suite of internal growth
opportunities through Petrofund's large undeveloped land base and
prospect inventory;
(j) information concerning the financial condition, results of
operations, business, plans and prospects of the Petrofund Parties
and the Ultima Parties and the resulting potential for enhanced
business efficiency, management, effectiveness and financial
results of the combined entity; and
(k) the historical and current trading prices of the Petrofund Units
and Ultima Units.
--------------------------------------------------------------------------------
The Ultima Board of Directors believes the Special Distribution and
Merger is in the best interests of Ultima and Ultima Unitholders and
therefore unanimously recommends that Ultima Unitholders vote FOR the
Ultima Special Resolution.
--------------------------------------------------------------------------------
The Merger
The Combination Agreement provides for the implementation, subject to
the satisfaction of certain conditions, of the Merger. See "Details of the
Merger - The Combination Agreement".
On the Closing Date, each of the events set out below will occur and be
deemed to occur immediately at the Effective Time in the sequence set out below:
1. the Ultima Trust Indenture and any other constating documents of the
Ultima Parties will be amended to the extent necessary to facilitate
the Merger;
2. Ultima will sell, transfer, convey, assign and deliver to Petrofund,
and Petrofund will purchase and accept from Ultima, all of the Ultima
Assets, as the same exist at the Effective Time;
3. Petrofund will (i) assume and become liable to pay, satisfy, discharge
and observe, perform and fulfill the Assumed Liabilities, in accordance
with their terms, and (ii) issue to Ultima an aggregate number of
Petrofund Payment Units equal in number to the product of the number of
Ultima Units outstanding as of the close of business on the day
immediately prior to the Closing Date multiplied by the Exchange Ratio;
4. Petrofund will subscribe for the Ultima Remaining Unit for $10.00 and
Ultima will issue to Petrofund the Ultima Remaining Unit;
5. the Ultima Units (other than the Ultima Remaining Unit) will be
redeemed in exchange for the Petrofund Payment Units which shall be
distributed to the Ultima Unitholders in accordance with the Exchange
Ratio;
-6-
6. the directors of the Ultima Parties, where applicable, will resign in
favour of the nominees for election as directors of Petrofund Co; and
7. all officers of the Ultima Parties, where applicable, will resign from
their offices with such Ultima Parties.
The Combination Agreement also provides that upon the occurrence or
non-occurrence of certain events which result in the Merger not being completed,
the party to the Combination Agreement responsible for or subject to such events
will be required to pay compensation to the other party. See "Details of the
Merger - The Combination Agreement -- Termination Fees".
Procedure for the Merger to Become Effective
The following procedural steps must occur in order for the Merger to
become effective:
(a) the Ultima Special Resolution must be approved by at least
66 2/3% of the votes cast by the Ultima Unitholders present in
person or by proxy at the Meeting;
(b) all conditions precedent to the Merger, as set forth below under "
Details of the Merger - The Combination Agreement - Conditions of
the Special Distribution and Merger", must be satisfied or waived
by the appropriate party; and
(c) all agreements which are required in order to implement the Merger
must be executed by the appropriate parties at Closing.
Fairness Opinion
To assist in determining whether to recommend the Special Distribution
and Merger to Ultima Unitholders, CIBC World Markets provided the Ultima Board
of Directors with the Fairness Opinion, which concluded that the consideration
to be received by Ultima Unitholders pursuant to the Special Distribution and
Merger is fair, from a financial point of view, to the Ultima Unitholders. A
copy of the Fairness Opinion is attached as Appendix "E" to this Information
Circular. See "Fairness Opinion".
Intention of Certain Insiders
Members of the Ultima Board of Directors and senior officers of Ultima
Co, who collectively own, directly or indirectly, or exercise control or
direction over, an aggregate of 535,921 Ultima Units, representing approximately
1.0% of the Ultima Units outstanding on April 19, 2004, have indicated their
intention to vote their Ultima Units in favour of the Ultima Special Resolution
approving the Special Distribution and Merger and have entered into Support
Agreements with Petrofund agreeing to vote their Ultima Units in favour of the
Ultima Special Resolution.
See "Interests of Insiders in the Merger and Intentions of Certain
Insiders".
Timing
The Merger will become effective at Closing. If the Ultima Special
Resolution is approved at the Meeting and all other conditions specified in the
Combination Agreement are satisfied or waived, Petrofund and Ultima expect the
Closing Date will be on or about June 16, 2004.
See "Timing".
-7-
Canadian Income Tax Considerations
For Canadian tax purposes, Ultima Unitholders who hold their Ultima
Units as capital property within the meaning of the Tax Act will not realize a
capital gain (or capital loss) on the disposition of Ultima Units for Petrofund
Units pursuant to the terms of the Merger.
Ultima Unitholders (other than Exempt Plans) who are resident in Canada
for the purposes of the Tax Act will generally be required to include in income
their proportionate share of the Special Distribution which represents a
distribution of Ultima's income in the taxation year in which the Special
Distribution is paid. Exempt Plans will not generally be liable for tax with
respect to the Special Distribution.
Ultima Unitholders who are not resident, or deemed to be resident, in
Canada, will generally be subject to a 25% Canadian withholding tax on their
proportionate share of Ultima's income which is distributed pursuant to the
Special Distribution at the time such distribution is paid unless such rate is
reduced under the provisions of a tax treaty between Canada and the respective
Ultima Unitholder's jurisdiction of residence.
See "Canadian Federal Income Tax Considerations".
All Ultima Unitholders should consult their own legal and tax advisors
as to the tax consequences of the Special Distribution and Merger.
United States Federal Income Tax Considerations
Subject to the PFIC, FIC and FPHC rules (discussed under "United States
Federal Income Tax Considerations"), the gross amount of the Special
Distribution (before reduction for Canadian withholding taxes) will be taxable
to U.S. holders of Ultima Units as a dividend to the extent of Ultima's current
and accumulated earnings and profits, as determined under U.S. federal income
tax principles. Ultima stated in 2003 that it believed that it would qualify as
a PFIC for the year ended December 31, 2003. If this is the case, U.S. Holders
of Ultima Units would not be eligible for the reduced rate of taxation on the
Special Distribution that is applicable to dividends paid by certain qualified
foreign corporations.
For U.S. federal income tax purposes, the exchange of Ultima Units for
Petrofund Units has been structured to qualify as a reorganization under the
provisions of Section 368(a) of the U.S. Internal Revenue Code of 1986, as
amended. The U.S. federal income tax treatment of the exchange to a U.S. Holder
of Ultima Units, however, will depend on whether Ultima has been a PFIC at any
time during which the U.S. Holder has held the Ultima Units. As discussed under
"United States Federal Income Tax Considerations", Ultima believes that it
should not be a PFIC for 2004. Because this conclusion is a factual
determination that is made annually and is subject to change, there can be no
assurances that Ultima will not be a PFIC for the current or any future taxable
year.
If Ultima has been a PFIC at any time during the time during which a
U.S. Holder has held Ultima Units, the exchange of Ultima Units for Petrofund
Units in the Merger should be a taxable transaction to the U.S. Holder. If
Ultima has not been a PFIC at any time during the time during which a U.S.
Holder has held Ultima Units, the U.S. Holder of Ultima Units should not be
required to recognize gain on the exchange of its Ultima Units for Petrofund
Units. If, contrary to Petrofund's current belief (discussed under "United
States Federal Income Tax Considerations"), Petrofund is determined to be a PFIC
for 2004, and Ultima has also been a PFIC at any time during which a U.S. Holder
has held Ultima Units, such a U.S. Holder of Ultima Units should not be required
to recognize gain on the exchange of its Ultima Units for Petrofund Units.
-8-
U.S. holders of Ultima Units are urged to consult their own tax
advisors regarding the U.S. federal income tax consequences of the Special
Distribution, the Merger, and ownership of Petrofund Units, as well as any
applicable state or foreign tax consequences.
See "United States Federal Income Tax Considerations".
Stock Exchange Listings
The currently outstanding Ultima Units are listed and posted for
trading on the TSX and the Petrofund Units are listed and posted for trading on
the TSX and the AMEX. On March 26, 2004, the last trading day prior to the date
of the announcement of the Merger, the closing price of the Petrofund Units on
the TSX was $17.14 per Petrofund Unit and on the AMEX was U.S.$12.97 per
Petrofund Unit. On March 26, 2004, the closing price of the Ultima Units on the
TSX was $7.47 per Ultima Unit. On April 29, 2004, the closing price of the
Petrofund Units on the TSX was $16.42 per Petrofund Unit and on the AMEX was
U.S.$11.95 per Petrofund Unit. On April 29, 2004, the closing price of the
Ultima Units was $7.07 per Ultima Unit. Following the Closing Date of the
Merger, the Ultima Units will be delisted from the TSX. See "Stock Exchange
Listings", "Additional Information Regarding Ultima Energy Trust - Trust Unit
Price Range and Trading Volumes" and "Additional Information Regarding Petrofund
Energy Trust - Trust Unit Price Range and Trading Volumes"
Selected Pro Forma Information
The pro forma combined financial information set forth below and the
Unaudited Pro Forma Combined Financial Statements set forth in Appendix "D"
hereto are not necessarily indicative either of results of operations that would
have occurred in the year ended December 31, 2003 had the proposed Merger and
certain other adjustments been effected on January 1, 2003, or of the results of
operations expected in 2004 and future years. In preparing the pro forma
statements, no adjustments have been made to reflect the operating synergies and
the resulting cost savings expected to result from combining the operations of
Petrofund and Ultima.
Selected Pro Forma Combined Financial Information
The following table sets out certain financial information for
Petrofund and Ultima as at and for the year ended December 31, 2003 and for
Petrofund on a pro forma basis as at and for the year ended December 31, 2003
after giving effect to the Special Distribution and Merger and certain other
adjustments. The following is a summary only and must be read in conjunction
with the Unaudited Pro Forma Combined Financial Statements of Petrofund set
forth in Appendix "D" to this Information Circular.
As at and for the year ended December 31, 2003
--------------------------------------------------
Pro Forma
After Giving
Effect
Petrofund Ultima to the Merger
----------------- ------------ ---------------
($ millions)
Revenues........................... 393.1 111.1 504.2
Cash flow(1)....................... 187.6 54.9 245.8
Net income......................... 85.8 12.3 62.0
Total assets....................... 943.9 326.5 1,522.2
Working capital (deficiency)....... (30.0) (8.2) (42.1)
Long term debt..................... 110.3 73.1 193.7
Unitholders' equity................ 649.2 208.4 1,102.0
-9-
Note:
(1) Management of Ultima Co uses cash flow (before changes in non-cash
working capital) to analyze financial performance, as one measure to
benchmark performance against peers, and as one measure to determine
distribution levels. Cash flow is calculated as net income for the
period plus charges to income not requiring an outlay of funds less
credits to net income not involving a source of funds. Cash flow as
presented does not have any standardized meaning prescribed by
Generally Accepted Accounting Principles in Canada ("GAAP") and
therefore it may not be comparable with the calculation of similar
measures by other entities. Cash flow as presented is not intended to
represent operating cash flows or operating profits for the period nor
should it be viewed as an alternative to cash flow from operating
activities, net income or other measures of financial performance
calculated in accordance with GAAP. All references to cash flow
throughout this report are based on cash flow before changes in
non-cash working capital.
Selected Combined Operational Information
The following table sets out certain operational information for
Petrofund and Ultima on a pro forma combined basis after giving effect to the
Merger. Further operational information concerning Petrofund and Ultima is set
forth in their respective annual information forms which are attached as
Appendices "B" and "C" to this Information Circular.
Combined
After Giving Effect
Petrofund Ultima to the Merger
------------------ ----------------- --------------------------
Production(1)
Natural gas (MMcf/d) ................ 79.4 13.7 93.1
Oil and NGLs (Bbls/d) ............... 13,448 8,065 21,513
Total (BOE/d)(3)..................... 26,681 10,348 37,029
Reserves(2)(3)
Proved (MBOE)........................ 81,762 30,725 112,487
Proved plus Probable (MBOE) ......... 102,030 41,377 143,407
Reserve Life Index(4)
Proved............................... 8.4 years 8.1 years 8.3 years
Proved plus Probable................. 10.5 years 11.0 years 10.6 years
Undeveloped land (thousands of net acres)... 250,509 35,270 285,779
Notes:
(1) Based on the 2004 forecast of proved plus probable production of each
of Petrofund and Ultima as estimated by the independent engineers of
each of Petrofund and Ultima in their respective reports of oil and gas
reserves as at December 31, 2003.
(2) Calculated on a gross basis before deducting royalties, without
including royalty interests, and based on the evaluations of the
independent engineers of each of Petrofund and Ultima as at December
31, 2003. The 11.7136% net royalty interest held by Ventures Trust in
the Weyburn Unit is treated as a working interest as Ultima is
responsible for its share of capital costs, operating costs, royalties
and abandonment costs.
(3) BOEs may be misleading, particularly if used in isolation. A BOE
conversion of 6 mcf:1 bbl is based on an energy equivalency conversion
method primarily applicable at the burner tip and does not represent a
value equivalency at the wellhead.
(4) Calculated as proved reserves or proved plus probable reserves, as the
case may be, divided by 2004 forecast of proved plus probable
production.
Pro Forma Combined Capitalization
The following table sets out the capitalization of Petrofund and Ultima
as at December 31, 2003, together with the pro forma combined capitalization of
Petrofund as at December 31, 2003 after giving effect to the Merger and certain
other adjustments. The following is a summary only and, where applicable, must
be read in conjunction with the Unaudited Pro Forma Combined Financial
Statements of Petrofund set forth in Appendix "D" to this Information Circular.
-10-
As at December 31, 2003
-----------------------------------------------------------------
Pro Forma
After Giving Effect
Petrofund Ultima to the Merger
-------------------- -------------------- ----------------------
Net debt ($ millions)(1)..................... $140.3 $81.4 $235.8
Units outstanding ($ millions) (2) .......... $1,031.2 $324.8 $1,102.0
(73.6 million units) (57.6 million units) (100.1 million units)
Notes:
(1) Long term debt plus working capital deficiency as at December 31, 2003.
Ultima net debt also includes its deferred capital obligation relating
to the 11.7136% net royalty interest held by Ventures Trust in the
Weyburn Unit. Pro forma net debt reflects the payment of the Special
Distribution and excludes transaction costs.
(2) Units outstanding for Petrofund includes those issuable upon conversion
of outstanding exchangeable shares. Pro forma units outstanding
reflects exercise of all outstanding Ultima Rights.
-11-
GLOSSARY OF TERMS
The following is a glossary of certain terms used in this Information
Circular including the Summary hereof and the Appendices hereto; however, terms
and abbreviations used in the Appendices to this Information Circular, to the
extent that they are defined in an Appendix, shall have the meanings set forth
therein.
"AcquireCo" means Ultima Acquisitions Corp., a corporation incorporated under
the laws of the Province of Alberta;
"AcquireCo USA" means the amended and restated unanimous shareholder agreement
dated as of June 23, 1999, and among AcquireCo, Maximize, and TCBM, for and on
behalf of Ultima, as amended;
"Acquisition Proposal" has the meaning ascribed thereto in "Details of the
Merger - The Combination Agreement - Acquisition Proposal and Take-Over
Proposal";
"Assumed Liabilities" means the liabilities and obligations of Ultima, whether
or not reflected on the books of Ultima;
"AMEX" means the American Stock Exchange;
"CIBC World Markets" means CIBC World Markets Inc., financial advisor to Ultima
and Ultima Co;
"Closing" means closing of the transactions contemplated by the Combination
Agreement, anticipated to be on or about June 16, 2004;
"Closing Date" means the date upon which the Merger becomes effective,
anticipated to be on or about June 16, 2004, provided that, in the event any of
the conditions of closing contained in the Combination Agreement in favour of
Ultima or Petrofund have not been fulfilled or waived by such date, the Closing
Date shall be extended to a date mutually agreed by Ultima and Petrofund,
provided (i) the Merger shall become effective on a date which follows a record
date for the payment of a regular monthly cash distribution by Ultima to the
Ultima Unitholders and which precedes the next following record date for the
payment of a regular monthly cash distribution by Petrofund to the Petrofund
Unitholders and (ii) the date is no later than July 16, 2004, unless otherwise
agreed to by Ultima and Petrofund;
"Combination Agreement" means the combination agreement dated March 29, 2004, as
amended April 30, 2004, including any subsequent amendments thereto, between
Ultima, Ultima Co, Petrofund and Petrofund Co;
"Commissioner" means the Commissioner of Competition appointed pursuant to the
provisions of the Competition Act;
"Competition Act" means the Competition Act (Canada), as amended;
"Effective Time" means the effective time of the Merger;
"Exchange Ratio" means the ratio of 0.442 Petrofund Units for each Ultima Unit;
"Exempt Plans" means trusts governed by registered retirement savings plans,
registered retirement income funds, registered education savings plans and
deferred profit sharing plans as defined in the Tax Act;
-12-
"Fairness Opinion" means the opinion of CIBC World Markets dated April 30, 2004
that the consideration to be received by Ultima Unitholders in connection with
the Special Distribution and Merger is fair, from a financial point of view, to
the Ultima Unitholders. A copy of the Fairness Opinion is attached to this
Information Circular as Appendix "E";
"Information Circular" means this proxy statement and information circular dated
April 30, 2004, together with all Appendices hereto and including the Summary
hereof, distributed by Ultima in connection with the Meeting;
"Management Agreement" means the amended and restated management agreement dated
as of August 31, 1997 among Maximize, Ultima Co, on its own behalf and on behalf
of Ventures Trust, AcquireCo, TCBM, for and on behalf of Ultima, and Maximum
Energy Corp. (as it existed at the time), as amended;
"Manager" means Ultima Management Inc., a corporation incorporated under the
laws of the Province of Alberta, which is the manager of Ultima, Ultima Co,
Ventures Trust and AcquireCo;
"Material Adverse Change" or "Material Adverse Effect" means, with respect to
any person, any matter or action that has an effect or change that is, or would
reasonably be expected to be, material and adverse to the business, operations,
assets, capitalization, financial condition or prospects of such person and its
subsidiaries, taken as a whole, other than any matter, action, effect or change
relating to or resulting from: (i) general economic, financial, currency
exchange, securities or commodity prices in Canada or elsewhere, (ii) conditions
affecting the oil and gas exploration, exploitation, development and production
industry as a whole, and not specifically relating to any person and/or its
subsidiaries or (iii) any decline in crude oil or natural gas prices on a
current or forward basis;
"Maximize" means Maximize Management Corp., a corporation incorporated under the
laws of the Province of Alberta, and the former manager of Ultima, Ultima Co,
Ventures Trust and AcquireCo;
"Meeting" means the special meeting of Ultima Unitholders to be held on June 4,
2004, and any adjournment thereof, at which, among other things, the Ultima
Unitholders will consider the Ultima Special Resolution;
"Merger" means the business combination of Ultima and Petrofund which will
provide for, inter alia, the transfer of all the Ultima Assets to Petrofund in
consideration of the Petrofund Payment Units and the assumption of the Assumed
Liabilities by Petrofund and the distribution of all Petrofund Payment Units to
the Ultima Unitholders as of the Effective Time upon, and as consideration for,
the redemption of all of the Ultima Units (other than the Ultima Remaining
Unit), all as contemplated in Section 132.2 of the Tax Act;
"person" includes any individual, firm, partnership, joint venture, venture
capital fund, association, trust, trustee, executor, administrator, legal
personal representative, estate group, body corporate, corporation,
unincorporated association or organization, governmental entity, syndicate or
other entity, whether or not having legal status;
"Petrofund" means Petrofund Energy Trust, a trust created under the laws of the
Province of Ontario;
"Petrofund Board of Directors" means the board of directors of Petrofund Co as
it may be comprised from time to time;
-13-
"Petrofund Co" means Petrofund Corp., a corporation incorporated under the laws
of the Province of Alberta;
"Petrofund Parties" means Petrofund, Petrofund Co, 1518274 Ontario Limited, NCE
Petrofund Management Corp. and NCE Management Services Inc. and "Petrofund
Party" means any of them unless the context otherwise requires;
"Petrofund Payment Units" means the Petrofund Units issued to Ultima in
consideration of the sale and transfer of the Ultima Assets and the assumption
of the Assumed Liabilities by Petrofund;
"Petrofund Royalty" means the royalty granted by Petrofund Co to Petrofund
pursuant to the terms of the amended and restated royalty agreement dated as of
April 16, 2003 between Petrofund Co and Petrofund;
"Petrofund Unit" means a trust unit issued by Petrofund;
"Petrofund Unitholders" means, at the relevant time, the holders of Petrofund
Units;
"Record Date" means the record date set for the Meeting, being the close of
business on April 19, 2004;
"SEC" means the United States Securities and Exchange Commission;
"Special Distribution" means the one-time special cash distribution to Ultima
Unitholders in the aggregate amount of $10 million payable to holders of record
of Ultima Units on the business day immediately preceding the Closing Date;
"Support Agreements" means the agreements entered into between Petrofund and
each member of the Ultima Board of Directors and the senior officers of Ultima
Co, pursuant to which such directors and officers have agreed to vote the Ultima
Units held by them in favour of the Ultima Special Resolution;
"Take-Over Proposal" has the meaning ascribed thereto in "Details of the Merger
- The Combination Agreement - Acquisition Proposal and Take-Over Proposal";
"Tax Act" means the Income Tax Act (Canada) and the Income Tax Regulations, all
as amended from time to time;
"TCBM" means The Trust Company of Bank of Montreal;
"TSX" means the Toronto Stock Exchange;
"Ultima" means Ultima Energy Trust, a trust created under the laws of the
Province of Alberta;
"Ultima Assets" means all the property, assets and undertaking of Ultima of
whatsoever nature or kind, present and future, and wheresoever located,
including the shares, units, royalties, notes or other interests in the capital
of or granted by Ultima's direct subsidiaries and any rights to purchase assets,
properties or undertakings of third parties under agreements to purchase that
have not yet closed, if any, and whether or not reflected on the books of Ultima
(other than $10.00);
"Ultima Board of Directors" means the board of directors of Ultima Co as it may
be comprised from time to time;
-14-
"Ultima Co" means Ultima Ventures Corp., a corporation incorporated under the
laws of the Province of Alberta;
"Ultima Co USA" means the unanimous shareholder agreement dated as of August 31,
1997 among Ultima Co, on its own behalf and for and on behalf of Ventures Trust,
Maximize, and TCBM, for and on behalf of Ultima, as amended;
"Ultima Employment Agreements" means the employment agreements, as amended,
between Ultima, Ultima Management Inc. and each of S. Brian Gieni, Ken G. Pinsky
and Michael P. Wihak;
"Ultima Energy" means Ultima Energy Inc., a corporation incorporated under the
laws of the Province of Alberta;
"Ultima Parties" means Ultima, Ultima Co, Ventures Trust, Ultima Energy,
AcquireCo and the Manager and "Ultima Party" means any of them unless the
context otherwise requires;
"Ultima Remaining Unit" means one Ultima Unit issued to Petrofund immediately
prior to the Effective Time of the Merger;
"Ultima Rights" means the rights to acquire Ultima Units granted under the
Ultima TURIP and pursuant to the Ultima Employment Agreements;
"Ultima Royalties" means the royalty granted by Ventures Trust to Ultima
pursuant to the terms of the amended and restated royalty agreement dated June
23, 1999, between Ultima Co and The Trust Company of Bank of Montreal in its
capacity as trustee of Ultima, as amended, and the royalty granted by Ultima
Energy to Ultima pursuant to the terms of the royalty agreement dated June 26,
2003, between Ultima Energy and Ultima Co on behalf of Ultima;
"Ultima Special Resolution" means the special resolution of Ultima Unitholders
to approve the Special Distribution and Merger;
"Ultima Trustee" means Computershare Trust Company of Canada, in its capacity as
the trustee under the Ultima Trust Indenture;
"Ultima Trust Indenture" means the amended and restated trust indenture
governing Ultima dated as of August 31, 1997, between Ultima Co, AcquireCo, The
Trust Company of Bank of Montreal, Maximum Energy Corp. and Glenn C.
Proudfoot, as amended;
"Ultima Unit" means a trust unit issued by Ultima;
"Ultima TURIP" means the Trust Unit Rights Incentive Plan of Ultima;
"Ultima Unitholders" means, at the relevant time, the holders of Ultima Units
other than Petrofund;
"Unitholder Indemnity Agreement" means the agreement between Ultima and
Petrofund to be entered into on the date of the payment of the Special
Distribution by Ultima pursuant to which Petrofund shall indemnify and save
Ultima Unitholders and annuitants under a plan of which a unitholder acts as a
trustee or carrier harmless from all and any costs, damages or expenses that may
be paid or incurred following any claim, suit or action taken by any other party
because of the failure of Petrofund to discharge and perform all or any of the
obligations, covenants, agreements and obligations forming part of the Assumed
Liabilities;
-15-
"Ventures Trust" means Ultima Ventures Trust, a trust formed under the laws of
the Province of Alberta;
"Ventures Trust Indenture" means the trust indenture governing Ventures Trust
dated as of August 31, 1997 between Ultima Co in its capacity as trustee of
Ventures Trust and TCBM in its capacity as trustee of Ultima, as amended; and
"1933 Act" means the United States Securities Act of 1933, as amended.
-16-
ABBREVIATIONS
The following abbreviations are used in this Information Circular to
represent the following terms:
"API" means American Petroleum Institute;
"Bbl" means barrel and "Bbls" means barrels;
"Bbls/d" means barrels per day;
"Bcf" means 1,000,000,000 cubic feet;
"BOE" means barrels of oil equivalent, with natural gas converted at 6 Mcf of
natural gas per Bbl of oil, unless otherwise stated;
"BOE/d" means barrels of oil equivalent per day, with natural gas converted at 6
Mcf of gas per Bbl of oil, unless otherwise stated;
"GJ" means gigajoule;
"m3" means cubic metre;
"Mbbls" means 1,000 barrels;
"MBOE" means 1,000 barrels of oil equivalent, with natural gas converted at 6
Mcf of gas per Bbl of oil, unless otherwise stated;
"Mcf" means 1,000 cubic feet;
"Mcf/d" means 1,000 cubic feet per day;
"Mlt" means one thousand long tons or 2,240,000 pounds;
"MMbbls" means, 1,000,000 barrels;
"MMBTU" means 1,000,000 British Thermal Units;
"MMcf" means 1,000,000 cubic feet;
"MMcf/d" means 1,000,000 cubic feet per day;
"NGLs" or "liquids" means natural gas liquids;
"WI" means working interest;
"WTI" means West Texas Intermediate, the benchmark crude for pricing purposes;
and
"000s" means thousands of dollars;
BOE's may be misleading, particularly if used in isolation. A BOE
conversion ratio of 6 Mcf: 1 Bbl is based on an energy equivalency conversion
method primarily applicable at the burner tip and does not represent a value
equivalency at the wellhead.
CONVERSION
The following table sets forth certain standard conversions between
Standard Imperial Units and the International System of Units (or metric units).
To Convert From To Multiply By
------------------- ----------------- -------------------
Mcf cubic metres 28.174
cubic metres cubic feet 35.494
Bbls cubic metres 0.159
cubic metres Bbls 6.289
feet metres 0.305
metres feet 3.281
miles kilometers 1.609
kilometers miles 0.621
acres hectares 0.405
hectares acres 2.471
-17-
PART I - GENERAL PROXY MATERIALS
AND ANNUAL AND SPECIAL MEETING MATTERS
SOLICITATION OF PROXIES
This Information Circular is furnished in connection with the
solicitation of proxies on behalf of Ultima by the management of the Manager for
use at the Meeting. The Meeting will be held in the Chambers Room located on the
conference level at 350 - 7th Avenue S.W., Calgary, Alberta on Friday, June 4,
2004 at 10:30 a.m. (Calgary time) for the purposes set forth in the Notice of
Annual and Special Meeting of the Ultima Unitholders accompanying this
Information Circular. It is expected that such solicitation will be primarily by
mail. Proxies may also be solicited personally by officers of the Manager at
nominal cost. The cost of solicitation on behalf of Ultima will be borne by the
Manager and reimbursed by Ultima. The information contained in this Information
Circular is given as of April 30, 2004 except where otherwise indicated.
In addition, Ultima has retained Georgeson Shareholder Communications
Canada Inc. ("Georgeson Shareholder"), 66 Wellington Street West, TD Tower,
Suite 5210, Toronto Dominion Centre, P.O. Box 240, Toronto, Ontario, M5K 1J3 at
a fee of approximately $40,000 plus out-of-pocket expenses to aid in the
solicitation of proxies from individual and institutional investors in Canada
and the United States. If you have questions about the information contained in
this Information Circular or require assistance in completing your form of proxy
(printed on blue paper) or letter of transmittal (printed on yellow paper),
please call Georgeson Shareholder at 1-866-800-4722.
APPOINTMENT OF PROXIES
Those Ultima Unitholders who wish to be represented at the Meeting by
proxy must complete and deliver a proper form of proxy to Computershare Trust
Company of Canada by mail or facsimile to Computershare Trust Company of Canada,
100 University Avenue, 9th Floor, Toronto, Ontario, M5J 2Y1 (a self-addressed
envelope is enclosed), fax number: 905-771-4414. In order to be valid, proxies
must be received by the Ultima Trustee at least 24 hours, excluding Saturdays,
Sundays and holidays, prior to the time of the Meeting or any adjournment
thereof.
The document appointing a proxy must be in writing and completed and
signed by the Ultima Unitholder or his or her attorney authorized in writing or,
if the Unitholder is a corporation, under its corporate seal or by an officer or
attorney thereof duly authorized. Persons signing as officers, attorneys,
executors, administrators, trustees, etc. should so indicate and provide
satisfactory evidence of such authority.
The persons named as proxyholders in the enclosed form of proxy, S.
Brian Gieni and Gary Lee, are directors of Ultima Co, Ultima Energy, AcquireCo
and the Manager. Mr. Gieni is also the President and Chief Executive Officer of
Ultima Co, Ultima Energy, AcquireCo and the Manager. An Ultima Unitholder
desiring to appoint some other person as his or her representative at the
Meeting may do so by either: (i) crossing out the names of the management
nominees AND legibly printing the other person's name (who need not be an Ultima
Unitholder) in the blank space provided in the enclosed form of proxy; or (ii)
completing another valid form of proxy. In either case, the completed proxy must
be delivered to the Ultima Trustee at the place and within the time specified
above for the deposit of proxies.
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REVOCATION OF PROXIES
An Ultima Unitholder who has given a proxy has the power to revoke it
before the proxy is exercised. In addition to revocation in any other manner
permitted by law, an Ultima Unitholder may revoke the proxy with an instrument
in writing signed and delivered to the Ultima Trustee at any time up to and
including the last business day preceding the date of the Meeting or any
adjournment thereof or deposited with the Chairman of the Meeting on the day of
the Meeting or any adjournment thereof prior to the commencement of the Meeting.
The document used to revoke a proxy must be in writing and completed and signed
by the Ultima Unitholder or his or her attorney authorized in writing or, if the
Ultima Unitholder is a corporation, under its corporate seal or by an officer or
duly authorized attorney thereof. As well, an Ultima Unitholder who has given a
proxy may attend the Meeting in person (or where the Ultima Unitholder is a
corporation, its authorized representative may attend), revoke the proxy (by
indicating such intention to the Chairman of the Meeting before the proxy is
exercised) and vote in person (or abstain from voting).
EXERCISE OF DISCRETION WITH RESPECT TO PROXIES
The Ultima Units represented by the enclosed proxy will be voted or
withheld from voting on any motion, by ballot or otherwise, in accordance with
any indicated instructions. In the absence of such direction, such Ultima Units
will be voted FOR the resolutions referred to in the proxy. If any amendment or
variation to the matters identified in the Notice is proposed at the Meeting or
any adjournment thereof, or if any other matters properly come before the
Meeting or any adjournment thereof, the enclosed proxy confers discretionary
authority to vote on such amendments or variations or such other matters
according to the best judgment of the appointed proxyholder. As at the date of
this Information Circular, none of the Ultima Trustee, in its capacity as
trustee of Ultima, Ultima Co, Ultima Energy, AcquireCo or the Manager is aware
of any other amendments or variations or other matters to come before the
Meeting.
ADVICE TO BENEFICIAL HOLDERS OF ULTIMA UNITS
The information set forth in this section is of significant importance
to many holders of Ultima Units, as a substantial number of Ultima Unitholders
do not hold their Ultima Units in their own name. Ultima Unitholders who do not
hold their Ultima Units in their own name (referred to herein as "Beneficial
Unitholders") should note that only proxies deposited by Ultima Unitholders
whose names appear on the records of Ultima as the registered holders of Ultima
Units can be recognized and acted upon at the Meeting. If Ultima Units are
listed in an account statement provided to an Ultima Unitholder by a broker,
then, in almost all cases, those Ultima Units will not be registered in the
Ultima Unitholder's name on the records of the Ultima. Such Ultima Units will
more likely be registered under the name of the Ultima Unitholder's broker or an
agent of that broker. In Canada, the vast majority of such Ultima Units are
registered under the name of CDS & Co. (the registration name for The Canadian
Depository for Securities, which acts as nominee for many Canadian brokerage
firms). Ultima Units held by brokers or their agents or nominees can only be
voted (for or against resolutions) upon the instructions of the Beneficial
Unitholder. Without specific instructions, a broker and its agents and nominees
are prohibited from voting Ultima Units for the broker's clients. Therefore,
Beneficial Unitholders should ensure that instructions respecting the voting of
their Ultima Units are communicated to the appropriate person or that the Ultima
Units are duly registered in their name.
-19-
Applicable Canadian regulatory policy requires intermediaries/brokers
to seek voting instructions from Beneficial Unitholders in advance of meetings.
Every intermediary/broker has its own mailing procedures and provides its own
return instructions to clients, which should be carefully followed by Beneficial
Unitholders in order to ensure that their Ultima Units are voted at the Meeting.
Often, the form of proxy supplied to a Beneficial Unitholder by its broker (or
the agent of the broker) is identical to the form of proxy provided to
registered Ultima Unitholders. However, its purpose is limited to instructing
the registered Ultima Unitholder (the broker or agent of the broker) how to vote
on behalf of the Beneficial Unitholder. In Canada, the majority of brokers now
delegate responsibility for obtaining instructions from clients to the ADP
Investor Communications Corporation ("ADP"). In most cases, ADP mails a
scannable voting instruction form in lieu of the form of proxy provided by
Ultima, and asks Beneficial Unitholders to return the voting instruction form to
ADP. Alternatively, Beneficial Unitholders can either call their toll-free
telephone number to vote their Ultima Units, or access ADP's dedicated voting
website at www.proxyvotecanada.com to deliver their voting instructions. ADP
then tabulates the results of all instructions received and provides appropriate
instructions respecting the voting of Ultima Units to be represented at the
Meeting. A Beneficial Unitholder receiving a voting instruction form from ADP
cannot use that form to vote Ultima Units directly at the Meeting - the voting
instruction form must be returned to ADP or, alternatively, instructions must be
received by ADP well in advance of the Meeting in order to have such Ultima
Units voted.
Although a Beneficial Unitholder may not be recognized directly at the
Meeting for the purposes of voting Ultima Units registered in the name of his
broker (or an agent of the broker), a Beneficial Unitholder may attend the
Meeting as proxyholder for the registered Ultima Unitholder and vote the Ultima
Units in that capacity. A Beneficial Unitholder who wishes to attend the Meeting
and indirectly vote his Ultima Units as proxyholder for the registered Ultima
Unitholder, should enter his own name in the blank space on the form of proxy
provided to him and return the same to his broker (or broker's agent) in
accordance with the instructions provided by such broker (or agent), well in
advance of the Meeting.
VOTING SECURITIES AND PRINCIPAL HOLDERS OF VOTING SECURITIES
The Ultima Unitholders are the sole beneficiaries of Ultima. On a show
of hands, every Ultima Unitholder present in person or represented by proxy (and
entitled to vote) has one vote. On a poll or ballot, every Ultima Unitholder
present in person or by proxy has one vote for each Ultima Unit held. All votes
on special resolutions will be conducted by a poll and no demand for a poll is
required. As at April 19, 2004 (the "Record Date"), Ultima had 57,807,357 issued
and outstanding Ultima Units. Ultima Unitholders of record as of the Record Date
are entitled to receive the Notice and attend and vote at the Meeting.
Holders of Ultima Units issued subsequent to the date of this
Information Circular and prior to the date of the Meeting are also entitled to
attend and vote at the Meeting. If an Ultima Unitholder has transferred the
ownership of any of his, her or its Ultima Units after the Record Date and the
transferee of those Ultima Units produces properly endorsed certificates or
otherwise establishes that he, she or it owns the Ultima Units and demands, not
later than 10 days before the Meeting, that his or her name be included in the
list before the Meeting, then the transferee shall be entitled to vote such
Ultima Units at the Meeting.
As at the date of this Information Circular and to the best of the
knowledge of the directors and senior officers of Ultima Co, AcquireCo and the
Manager, no person or company beneficially owns, directly or indirectly, or
exercises control or direction over, more than 10% of the issued and outstanding
Ultima Units.
-20-
ANNUAL MEETING MATTERS
The election of the directors of each of Ultima Co and AcquireCo in
this "Annual Meeting Matters" section will be effective until such time as the
Merger is approved and completed, after which time the nominees of Petrofund
shall form the board of directors of each of Ultima Co and AcquireCo. If the
Merger is not completed, the matters acted upon in this "Annual Meeting Matters"
section shall be effective until the next annual meeting of Ultima Unitholders
or otherwise as described below.
Consideration of Financial Statements
The consolidated financial statements of Ultima for the year ended
December 31, 2003, together with the auditors' report thereon, have been mailed
to Ultima Unitholders as part of this Information Circular. See "Comparative
Audited Consolidated Financial Statements as at and for the years ended December
31, 2003 and 2002, together with the auditors' report thereon" in Appendix "C"
of this Information Circular.
Election of Directors Until Completion to the Merger
The persons named as proxyholders in the enclosed form of proxy intend
to vote FOR the election of the persons listed in the following table as
directors of each of Ultima Co and AcquireCo. Each such director will hold
office until the next annual meeting of the Ultima Unitholders or until his
successor is duly elected or appointed in accordance with: (i) in the case of
Ultima Co, the by-laws of Ultima Co and the Ultima Co USA; or (ii) in the case
of AcquireCo, the by-laws of AcquireCo and the AcquireCo USA. If the proposed
Merger is completed in accordance with its terms, the directors of Ultima Co and
AcquireCo named below will resign and cease to hold office on the Closing Date.
The following table and notes thereto state the names of the persons to
be nominated for election by the Ultima Unitholders as directors of each of
Ultima Co and AcquireCo, their current principal occupations, the periods during
which they have served as directors, and the number of Ultima Units owned
beneficially or subject to each of their control or direction as at April 19,
2004.
Name and Municipality Trust Units Controlled
of Residence Principal Occupation Director Since or Beneficially Owned
------------ -------------------- -------------- ---------------------
Marshall M. Williams(1) Businessman; Chairman of the Boards of August 1997(2) 60,876
Calgary, Alberta directors of Ultima Co and AcquireCo
Arthur E. Dumont(3) Chairman and Chief Executive Officer of June 2001 6,000
Calgary, Alberta Technicoil Corporation
S. Brian Gieni(4) President and Chief Executive Officer December 2000 192,396
Calgary, Alberta of the Manager, Ultima Co, Ultima
Energy and AcquireCo
John M. Gunn(5) Chief Executive Officer and Chief November 1999 153,000
Calgary, Alberta Financial Officer of Tango Energy Inc.
Henry R. Lawrie(6) Businessman May 2003 2,000
Calgary, Alberta
Gary Lee(7) Director of North West Capital Inc. December 2000 27,325(8)
Calgary, Alberta
David Tuer(9) Chairman and Chief Executive Officer of May 2003 Nil
Calgary, Alberta Hawker Resources Inc.
-21-
Notes:
(1) Mr. Williams is a former Chairman of Alberta Treasury Branches. He has
also served as Chairman of the Board and as a director of TransAlta
Corporation, and as a director of Stelco Inc. from 1984 to 1996 and Sun
Life Assurance from 1978 to 1995.
(2) Mr. Williams was appointed to the Boards of directors of Ultima Co and
AcquireCo in August 1997 in connection with a reorganization of Ultima.
Prior thereto, Mr. Williams had been elected as a director of Maximum
Energy Corp., the corporate entity which held the initial properties
presently held by Ventures Trust.
(3) Mr. Dumont has been the President and Chief Executive Officer of
Technicoil Corporation since October 2000. Prior thereto, Mr. Dumont
was President and Chief Executive Officer of CenAlta Energy Services
and its predecessor companies from November 1998 until October 2000. He
has also worked in senior roles at Western Rock Bit Company, Precision
Drilling Corporation, Kenting Energy Services Inc. and Trimac Limited.
(4) Mr. Gieni is a finance and accounting professional who was employed in
various senior management capacities at PanCanadian Petroleum Limited
between 1997 and 2000. Prior to that, he was President and Chief
Executive Officer and a director of Grantham Resources Inc., a junior
resource company listed on the Alberta Stock Exchange.
(5) Mr. Gunn has been the Chief Executive Officer and Chief Financial
Officer of Tango Energy Inc. (a TSX-listed oil and gas company) since
March 2002. Prior thereto, Mr. Gunn was the Chairman of Renata
Resources Inc., formerly a TSX-listed oil and gas company, from 1996
until it was acquired in 2000. Prior thereto, Mr. Gunn was President
and Chief Executive Officer of Ballistic Energy Corporation (formerly a
TSX-listed oil and gas company).
(6) Mr. Lawrie is a Chartered Accountant - FCA. From July 1997 to February
2001 Mr. Lawrie was the Chief Accountant of the Alberta Securities
Commission. Prior to that, Mr. Lawrie spent 35 years as a Chartered
Accountant with PricewaterhouseCoopers and acted as managing partner of
the Calgary office before retiring in 1997.
(7) Mr. Lee is a director and officer of North West Capital Inc. Prior to
that, he was a partner with Hoar, Lee, Boers, Barristers and
Solicitors, until December 1998.
(8) The Ultima Units are held by a company of which Mr. Lee is the sole
director and a shareholder.
(9) Mr. Tuer has been Chairman and Chief Executive Officer of Hawker
Resources Inc. since January 2003 and Chairman of the Calgary Health
Region since October 2001. From December 1994 until October 2001, Mr.
Tuer was President and Chief Executive Officer of PanCanadian Energy
Corporation. Prior thereto, he worked in various senior roles at
PanCanadian Petroleum Limited and for the Alberta Government.
Each of the Ultima Board of Directors and the board of directors of
AcquireCo has appointed a compensation committee, reserves committee, audit
committee and corporate governance committee. See "Additional Information
Regarding Ultima Energy Trust - Statement of Corporate Governance Practices -
Committees of the Boards" for a description of such committees. Neither board of
directors has appointed an executive committee.
Appointment of Auditors Until Completion of the Merger
The Ultima Trust Indenture provides that the Ultima Unitholders shall
appoint the auditors of Ultima at each annual meeting of Ultima Unitholders.
Both the Ultima Co USA and the AcquireCo USA provide that the Unitholders shall
likewise appoint the auditors of Ultima Co and AcquireCo, respectively, at each
annual meeting of Unitholders. The Ventures Trust Indenture provides that the
Ultima Unitholders shall also appoint auditors of Ventures Trust at each annual
meeting of Ultima Unitholders. Deloitte & Touche LLP was appointed as auditors
of Ultima, Ventures Trust, Ultima Co and AcquireCo on May 27, 2002.
The persons named in the enclosed form of proxy intend to vote FOR the
re-appointment of Deloitte & Touche LLP as auditors of Ultima, Ventures Trust,
Ultima Co and AcquireCo, respectively, to hold such office until the next annual
meeting of the Ultima Unitholders and at a remuneration to be fixed by the
directors of Ultima Co and AcquireCo.
PART II - THE MERGER
Background to the Merger
In the normal course, Ultima continually examines opportunities to
advance the interests of its unitholders and to advance unitholder value. In
January 2004, the Ultima Board of Directors, after
-22-
considering the business and operations of Ultima, on both a historical and
prospective basis, the current industry, economic and market conditions,
including an anticipated consolidation in the oil and gas trust market,
commenced a strategic analysis of Ultima's position and the alternatives
available to Ultima.
In assessing the alternatives available to Ultima, Ultima retained CIBC
World Markets effective January 19, 2004. CIBC World Markets presented the
Ultima Board of Directors with a list of industry participants which, by virtue
of their objectives, goals, valuation, market trading levels and corporate
governance policies were most likely to have the ability and interest to enter
into a favourable strategic transaction with Ultima. The Ultima Board of
Directors and CIBC World Markets reviewed, discussed and agreed upon the list of
likely industry participants. A number of these industry participants were
approached and were provided with access to certain non-public information
relating to Ultima and its business and affairs under the terms of a
confidentiality agreement.
Discussions took place with the potential candidates during late
February and early March. Certain of the potential candidates, including
Petrofund, were provided with access to a confidential data room established by
Ultima. As a result of this process, a written, non-binding proposal was
received from Petrofund. On March 18, 2004, the Ultima Board of Directors met
with CIBC World Markets and its legal advisors, Bennett Jones LLP, and reviewed
Petrofund's proposal in detail. Up to this date, the Ultima Board of Directors
had met on numerous occasions, both formally and informally, to receive updates
from Bennett Jones LLP and CIBC World Markets, and to review the process.
The Ultima Board of Directors received financial advice from CIBC World
Markets on the proposal by Petrofund and reviewed with them and Bennett Jones
LLP the structure and terms of the proposal. The Ultima Board of Directors
authorized management to continue to negotiate the terms of the non-binding
proposal with Petrofund and, subject to certain terms and provisions being
included in the proposal, authorized the entering into of the proposal on behalf
of Ultima. The proposal was entered into on March 19, 2004. The proposal
provided for a period of exclusivity to March 30, 2004, indicated preliminary
terms of a combination and outlined certain outstanding due diligence
procedures. The terms of any combination were subject to completion of due
diligence by Ultima and Petrofund, final negotiations and the approval of each
of the Ultima Board of Directors and Petrofund Board of Directors.
Between March 22, 2004 and March 28, 2004, discussions and negotiations
continued between representatives of Ultima and representatives of Petrofund
with respect to price, conditions to the Merger and the terms of the Combination
Agreement.
The Ultima Board of Directors met during the afternoon of March 28,
2004. CIBC World Markets provided the Ultima Board of Directors with financial
advice regarding the proposed Merger and the Special Distribution, including its
view as to the fairness, from a financial point of view, of the consideration to
be received by the Ultima Unitholders under the proposal. Bennett Jones LLP
provided advice on the structure of the transaction and the terms of the draft
Combination Agreement. The Ultima Board of Directors reviewed the terms of the
draft Combination Agreement, discussed with its counsel a number of issues
arising in respect of the Combination Agreement and fully considered its duties
and responsibilities to holders of Ultima Units. The Ultima Board of Directors
approved the Combination Agreement and unanimously determined that the Special
Distribution and Merger are in the best interest of Ultima and Ultima
Unitholders and resolved to unanimously recommend that the Ultima Unitholders
vote in favour of the Special Distribution and Merger.
The Combination Agreement was executed in the morning of March 29,
2004, and the transaction was publicly announced before markets opened on March
29, 2004. Thereafter, the Support Agreements were executed by each member of the
Ultima Board of Directors and each senior officer of Ultima.
-23-
On April 30, 2004, the Ultima Board of Directors met again, approved an
amending agreement to the Combination Agreement, reconfirmed its recommendation
respecting the Special Distribution and Merger and approved the contents of this
Information Circular.
Reasons for the Merger
The Ultima Board of Directors believes that the principal advantages of
the Merger to Ultima Unitholders are as follows:
1. the Merger will improve access of the combined entity to capital
markets in both Canada and the United States due to the increased size
and liquidity of the combined entity which should provide the combined
entity a more competitive cost of capital and an improved ability to
compete for and finance future acquisitions;
2. after giving effect to the Merger, former holders of Ultima Units will
hold interests in a much broader and more diversified group of
properties and product mix;
3. the Merger will permit Ultima Unitholders to benefit from Petrofund's
broader suite of internal growth opportunities through Petrofund's
large undeveloped land base and prospect inventory;
4. the Merger will create a trust with larger market capitalization on two
stock exchanges that should result in increased market liquidity for
Ultima Unitholders; and
5. the Merger is expected to eliminate the duplication of costs and
services which arises from administering two separate trusts.
The Merger will result in a combined entity with a larger market
capitalization (approximately four times the current market capitalization of
Ultima) which is expected to improve access of the combined entity to capital
markets at a more competitive cost of capital. As a result, it is anticipated
that the ability to compete for and finance future acquisitions will be
strengthened.
As a result of the Merger, Ultima Unitholders will hold Petrofund Units
with a market capitalization, based on current prices, of an aggregate of
approximately $1.64 billion. Proved plus probable reserves (calculated on a
gross basis before deducting royalties and without including royalty interests)
attributable to Petrofund following the Merger will be approximately 143,400
MBOE. Total production attributable to Petrofund following the Merger is
expected to be approximately 21,500 Bbls/d of crude oil and NGLs and 93.1 MMcf/d
of natural gas, for total gross production of approximately 37,000 BOE/d.
Management of Ultima also anticipates that a larger and more diversified group
of properties will reduce the production risk to which Ultima, as a smaller
producer, is currently exposed.
The Merger, if approved, is expected to enhance the liquidity to the
former holders of Ultima Units as the Merger will result in approximately
100,129,910 Petrofund Units (assuming that all outstanding exchangeable shares
of Petrofund Co are exchanged for Petrofund Units) being issued and outstanding
and listed for trading on the TSX and the AMEX with a larger investor base,
which management of Ultima anticipates will result in a more efficient market
for the former holders of Ultima Units.
Administrative cost savings will be realized by eliminating the
duplication of certain third party costs, as well as internal administrative
costs, arising from managing and reporting for two separate trusts. Costs such
as trustee and transfer agency fees, audit fees, mailing and reporting costs and
exchange listing fees are higher for the two separate entities than are expected
for one consolidated entity. The Merger
-24-
will eliminate the internal costs associated with segregating and maintaining
separate books and records, bank accounts and property interests for the two
separate entities.
Recommendation of the Ultima Board of Directors
The Ultima Board of Directors has determined unanimously that the
Special Distribution and Merger are in the best interests of Ultima and the
Ultima Unitholders and unanimously recommends that Ultima Unitholders vote in
favour of the Ultima Special Resolution. In coming to its conclusion and
recommendation, the Ultima Board of Directors considered a number of factors
including the following:
(a) the expectation that the Merger will result in a mutual fund trust
that is financially and operationally stronger than Ultima,
enabling it to more effectively participate and compete in the
acquisition and development of oil and natural gas properties and
the production and marketing of oil and natural gas under a
variety of economic conditions;
(b) the improved liquidity of the investment anticipated for Ultima
Unitholders and the improved access to capital for the combined
entity that is expected to result from the increase in the market
capitalization of the combined entity;
(c) the Fairness Opinion from CIBC World Markets;
(d) the Special Distribution;
(e) the timing of the record dates for monthly distributions of each
of Ultima and Petrofund and the Closing Date;
(f) the increased efficiencies that are expected to result in reduced
general and administrative costs on a per BOE basis;
(g) that the Merger will enable Ultima Unitholders to continue to
participate in a larger oil and gas royalty trust with a proven
management team;
(h) increased diversification and property synergies that are
anticipated to result from the combination of the high quality
asset bases of each of Ultima and Petrofund;
(i) the increased exposure to a broader suite of internal growth
opportunities through Petrofund's large undeveloped land base and
prospect inventory;
(j) information concerning the financial condition, results of
operations, business, plans and prospects of the Petrofund Parties
and the Ultima Parties and the resulting potential for enhanced
business efficiency, management, effectiveness and financial
results of the combined entity; and
(k) the historical and current trading prices of the Petrofund Units
and Ultima Units.
--------------------------------------------------------------------------------
The Ultima Board of Directors believes the Special Distribution and Merger is
in the best interests of Ultima and Ultima Unitholders and therefore
unanimously recommends that Ultima Unitholders vote FOR the Ultima Special
Resolution.
--------------------------------------------------------------------------------
-25-
The Ultima Special Resolution requires the approval of holders of not
less than 66 2/3% of the Ultima Units represented at the Meeting which are voted
in respect of the resolution in person or by proxy. See "Interests of Insiders
in the Merger and Intentions of Certain Insiders".
It is the intention of the persons named in the enclosed Form of Proxy,
if not expressly directed to the contrary in such Form of Proxy, to vote such
proxy in favour of the Ultima Special Resolution set forth in the attached
Appendix "A".
EFFECT OF THE MERGER UPON ULTIMA UNITHOLDERS
General
After giving effect to the Merger, Petrofund will have acquired all of
the Ultima Assets and assumed all of the Assumed Liabilities, and former Ultima
Unitholders will become holders of Petrofund Units on the basis of 0.442 of a
Petrofund Unit for each issued and outstanding Ultima Unit. The Merger is
structured to be a tax deferred event such that the exchange of Ultima Units for
Petrofund Units will not result in a taxable event to Ultima Unitholders for
Canadian tax purposes. See "Canadian Income Tax Considerations".
Assuming completion of the Merger whereby all Ultima Unitholders
receive Petrofund Units for their Ultima Units, there will be approximately
99,233,252 Petrofund Units issued and outstanding, subject to changes due to the
exercise of outstanding Ultima Rights and the rounding to the nearest whole
number of fractional Petrofund Units and assuming that all outstanding
exchangeable shares of Petrofund Co are exchanged for Petrofund Units.
Immediately following the Merger and assuming that all of the outstanding
exchangeable shares of Petrofund Co are exchanged for Petrofund Units, current
Petrofund Unitholders will hold approximately 73,682,400 Petrofund Units,
representing approximately 74% of the issued and outstanding Petrofund Units,
and former holders of Ultima Units will hold approximately 25,550,852 Petrofund
Units, representing approximately 26% of the issued and outstanding Petrofund
Units. As of April 19, 2004, a total of approximately 2,028,639 Ultima Rights
were outstanding which, based on the adjustment provisions, the Ultima
Employment Agreements and the Exchange Ratio, could result in an additional
896,658 Petrofund Units being issued to former securityholders of Ultima in
connection with the Merger.
Special Distribution
If the Ultima Special Resolution is approved at the Meeting, a record
date will be announced for the Special Distribution. Ultima Unitholders of
record on the record date set for the Special Distribution will be entitled to a
distribution from Ultima in the amount of $10 million divided by the number of
Ultima Units outstanding on such record date (or approximately $0.17 per Ultima
Unit assuming 59,835,996 Ultima Units are outstanding). The record date will be
the date which is at least seven business days following approval of the Ultima
Special Resolution, but which will be not later than the business day
immediately prior to the Closing Date of the Merger. Therefore, if the Meeting
is held as currently proposed on June 4, 2004 and the Closing Date is held as
currently proposed on June 16, 2004, the record date for the Special
Distribution will be June 15, 2004. Ultima will issue a press release announcing
the actual record date for the Special Distribution at least seven business days
prior to the record date. It is possible that the Special Distribution is
approved by the Ultima Unitholders and paid by Ultima on the business day prior
to the Closing Date and that the Merger is not completed.
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Treatment of Ultima Rights
In connection with the Merger, the Ultima Board of Directors, on behalf
of Ultima, resolved to accelerate the vesting of the Ultima Rights immediately
prior to the record date of the Special Distribution so that Ultima Rights may
be exercised prior to the payment of the Special Distribution. Subject to the
pre-existing rights of certain executive officers of Ultima Co as set forth in
their respective Ultima Employment Agreements, Ultima has agreed to use its
reasonable commercial efforts to ensure that any Ultima Rights that are not
exercised on or prior to the Effective Time are terminated or surrendered
without the payment of any consideration therefor unless consented to by
Petrofund, acting reasonably. In order to facilitate the exercise of Ultima
Rights prior to the Effective Time, Ultima and Petrofund have agreed to
implement such policies and procedures (including the lending of sufficient
funds for an agreed upon limited period to the holders of Ultima Rights to allow
for the exercise of the Ultima Rights by such holders prior to the Effective
Time provided the person providing the funds required to exercise such Ultima
Rights is granted sufficient security in exchange therefor) to allow for the due
exercise of Ultima Rights on or prior to the record date of the Special
Distribution.
Effect on Distributions
Distributions paid to Ultima Unitholders for the months of April and
May 2004 will not be affected by the proposed Merger and will be paid in the
usual manner. Therefore, Ultima Unitholders of record on April 30, 2004 and May
31, 2004 will receive their regular monthly cash distribution from Ultima on May
17, 2004 and June 15, 2004, respectively. Assuming the Merger becomes effective
on June 16, 2004, Petrofund Unitholders of record on June 16, 2004, including
former Ultima Unitholders, will receive a cash distribution from Petrofund on
June 30, 2004, and will receive monthly distributions from Petrofund in a
similar manner in the future. Former Ultima Unitholders who are Petrofund
Unitholders of record on June 16, 2004 (and any subsequent record date for
distributions to Petrofund Unitholders) will be entitled to receive
distributions from Petrofund following the Closing Date of the Merger without
any further action required on their part provided they have exchanged their
certificates representing Ultima Units for Petrofund Units on or prior to the
sixth anniversary of the Closing Date. See "Exchange of Ultima Certificates"
below.
Exchange of Ultima Certificates
After the Closing Date, certificates formerly representing Ultima Units
shall only represent the right to receive Petrofund Units which a former Ultima
Unitholder is, except as set forth below, entitled to receive pursuant to the
Merger.
A form of letter of transmittal (printed on yellow paper) containing
instructions with respect to the surrender of certificates representing Ultima
Units has been forwarded to registered Ultima Unitholders for use in exchanging
their certificates. Upon surrender of properly completed letters of transmittal
together with certificates representing Ultima Units to Computershare Trust
Company of Canada, certificates for the appropriate number of Petrofund Units
will be issued, subject to any withholdings as required by law.
No fractional Petrofund Units shall be issued to former Ultima
Unitholders pursuant to the Merger. In the event that the Exchange Ratio would
otherwise result in an Ultima Unitholder being entitled to a fractional
Petrofund Unit, an adjustment will be made to the nearest whole number of
Petrofund Units and a certificate representing the resulting whole number of
Petrofund Units will be issued. In calculating such fractional interests, all
Ultima Units held by a registered holder of Ultima Units immediately prior to
the Closing Date shall be aggregated.
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The Combination Agreement provides that any certificate representing
Ultima Units that is not validly deposited with Computershare Trust Company of
Canada within six years of the Closing Date shall cease to represent a claim or
interest of any kind or nature in Petrofund, and the Petrofund Units to which
the holder of such certificate would have otherwise been entitled shall be
deemed to have been surrendered to Petrofund, together with all entitlements to
distributions and interest thereon held for such holder.
DETAILS OF THE MERGER
On March 29, 2004, Ultima, Ultima Co, Petrofund and Petrofund Co,
entered into the Combination Agreement whereby they agreed to combine the
operations of Ultima and Petrofund. See "The Combination Agreement". The Merger
will become effective on the Closing Date which is expected to be on or about
June 16, 2004. The following procedural steps must occur in order for the Merger
to become effective:
(a) the Merger must be approved by the Ultima Unitholders in the
manner described below under "The Combination Agreement -
Unitholder Approval";
(b) all conditions precedent to the Merger, as set forth below under
"The Combination Agreement - Conditions of the Special
Distribution and Merger", must be satisfied or waived by the
appropriate party; and
(c) all agreements which are required in order to implement the Merger
must be executed by the appropriate parties at Closing.
On the Closing Date, each of the events set out below shall occur and
be deemed to occur immediately at the Effective Time in the sequence set out
below:
1. the Ultima Trust Indenture and any other constating documents of the
Ultima Parties will be amended to the extent necessary to facilitate
the Merger;
2. Ultima will sell, transfer, convey, assign and deliver to Petrofund,
and Petrofund will purchase and accept from Ultima, all of the Ultima
Assets, as the same exist at the Effective Time;
3. Petrofund will (i) assume and become liable to pay, satisfy, discharge
and observe, perform and fulfill the Assumed Liabilities, in accordance
with their terms, and (ii) issue to Ultima an aggregate number of
Petrofund Payment Units equal in number to the product of the number of
Ultima Units outstanding as of the close of business on the day
immediately prior to the Closing Date multiplied by the Exchange Ratio;
4. Petrofund will subscribe for the Ultima Remaining Unit for $10.00 and
Ultima will issue to Petrofund the Ultima Remaining Unit;
5. the Ultima Units (other than the Ultima Remaining Unit) will be
redeemed in exchange for the Petrofund Payment Units which shall be
distributed to the Ultima Unitholders in accordance with the Exchange
Ratio;
6. the directors of the Ultima Parties, where applicable, will resign in
favour of the nominees for election as directors of Petrofund Co; and
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7. all officers of the Ultima Parties, where applicable, will resign from
their offices with such Ultima Parties.
No fractional Petrofund Units shall be issued to former Ultima
Unitholders pursuant to the Merger and no distribution, dividend or other change
in the structure of Petrofund shall relate to any such fractional security and
such fractional interest shall not entitle the owner thereof to exercise any
rights as a securityholder of Petrofund. In the event that the Merger would
otherwise result in an Ultima Unitholder being entitled to a fractional
Petrofund Unit, an adjustment will be made to the nearest whole number of
Petrofund Units and a certificate representing the resulting whole number of
Petrofund Units will be issued. In calculating such fractional interests, all
Ultima Units held by a registered holder of Ultima Units immediately prior to
the Effective Time will be aggregated.
Special Distribution and Unitholder Indemnity Agreement
In connection with the Merger and conditional on approval of the Ultima
Special Resolution (i) Ultima will declare the Special Distribution payable to
Ultima Unitholders of record on the business day immediately preceding the
Closing Date, payable on the business day immediately preceding the Closing
Date, and (ii) Ultima and Petrofund will execute the Unitholder Indemnity
Agreement. The amount of the Special Distribution payable to each Ultima
Unitholder will be equal to such unitholder's pro rata share, on the basis of
their holdings of Ultima Units, of $10 million (expected to be approximately
$0.17 per Ultima Unit) and all rights Ultima Unitholders are entitled to under
the Unitholder Indemnity Agreement. It is possible that the Special Distribution
is approved by the Ultima Unitholders and paid by Ultima on the business day
prior to the Closing Date and that the Merger is not completed.
The Combination Agreement
On March 29, 2004, Ultima, Ultima Co, Petrofund and Petrofund Co,
entered into the Combination Agreement whereby they agreed to combine the
operations of Ultima and Petrofund. The Combination Agreement sets forth a
number of conditions to be satisfied or waived in order for the Special
Distribution and Merger to become effective (see "Conditions of the Special
Distribution and Merger") and provides the right of the parties thereto to
terminate the Combination Agreement on the occurrence or non-occurrence of
certain events within specific time frames (see "Termination"). The Combination
Agreement also sets forth a number of covenants on behalf of the parties
thereto, including prescribing the manner of operation of the business and
operations of the parties and precluding the parties from entering into certain
new agreements or commitments with respect to their capitalization or assets
during the term of the Combination Agreement (see "Covenants").
Unitholder Approval
The Ultima Special Resolution must be approved by at least 66 2/3%
of the votes cast by the Ultima Unitholders present in person or by proxy at the
Meeting. In order for the Meeting to be duly constituted for the transaction of
business, at least two Ultima Unitholders (represented in person or by proxy)
must be present at the Meeting, representing not less than 5% of the outstanding
Ultima Units entitled to vote at the Meeting.
Conditions of the Special Distribution and Merger
The obligations of the parties to the Combination Agreement to complete
the Merger are subject to the fulfillment or waiver of a number of significant
conditions which must be satisfied on or before the Closing Date or be waived to
the extent they are capable of being waived by the party benefiting from such
condition. There is no assurance that the conditions will be satisfied or waived
on a timely basis, if
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at all. The following is a summary of the material conditions other than those
which have been satisfied as at the date hereof:
(a) the Ultima Special Resolution shall have been passed by the Ultima
Unitholders at the Meeting by the level of approval set forth
under "Unitholder Approval";
(b) the documents by which the Special Distribution and Merger are to
be effected shall be in form and substance satisfactory to the
parties, acting reasonably;
(c) all approvals and consents, regulatory or otherwise, including
those summarized under "Regulatory and Third Party Approvals"
shall have been obtained;
(d) Ultima shall have received an opinion of counsel to Petrofund, in
form and substance satisfactory to Ultima, as to such matters as
Ultima and Ultima Co, acting reasonably, may require, including
with respect to the status of Petrofund as a "mutual fund trust"
under Section 132 of the Tax Act, the application of the federal
budget of March 23, 2004 to such status as a mutual fund trust and
that the Petrofund Units to be distributed to Ultima Unitholders
pursuant to the Merger will not constitute "foreign property" for
the purposes of Part XI of the Tax Act;
(e) Petrofund shall have received an opinion of counsel to Ultima, in
form and substance satisfactory to Petrofund, as to such matters
as Petrofund, acting reasonably, may require;
(f) no act, action, suit or proceeding shall have been threatened or
taken before or by any domestic or foreign court or tribunal or
governmental entity or person in Canada or elsewhere, whether or
not having the force of law, and no law, regulation or policy
shall have been proposed, enacted, promulgated or applied which
has the effect to cease trade or enjoin, prohibit or impose
material limitations on the Special Distribution and Merger or
which would have a Material Adverse Effect with respect to
Petrofund or Ultima;
(g) there shall not exist any prohibition at law against Ultima making
the Special Distribution or against Petrofund and Ultima
completing the Merger;
(h) the representations, warranties and covenants of each of the
parties to the Combination Agreement shall be true and correct or
complied with, as applicable, in all material respects as of the
Effective Time;
(i) all outstanding Ultima Rights shall have been exercised,
terminated or surrendered for cancellation; and
(j) there shall not have occurred or arisen after March 29, 2004, any
change (or any condition, event or development involving a
prospective change) which involves a Material Adverse Effect with
respect to either Ultima or Petrofund.
In the event that the Merger does not become effective on or before
July 16, 2004, or such other date as Petrofund and Ultima may agree, Ultima or
Petrofund may terminate its obligations under the Combination Agreement.
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Regulatory and Third Party Approvals
The Combination Agreement provides that receipt of all required
regulatory and third party approvals is a condition precedent to the Special
Distribution and Merger becoming effective, including:
(a) any rulings required under the securities regulatory authorities
in Canada to permit the issuance of the Petrofund Payment Units on
a prospectus and registration exempt basis to residents of the
provinces of Canada and to permit such Petrofund Payment Units to
be issued as freely tradable subject to restrictions imposed upon
trades by control persons;
(b) a registration statement on Form F-10, which includes the
Information Circular as a prospectus, and an appointment of agent
for service of process and undertaking on Form F-X, each of which
complies in all material respects with the requirements of the
1933 Act at the time it became effective and at the Closing Date,
shall have been filed by Petrofund with the SEC and declared
effective by the SEC under the 1933 Act, and no stop order
suspending the effectiveness of the registration statement shall
have been issued by the SEC and no proceeding for that purpose
shall have been initiated by the SEC;
(c) the Commissioner or any person authorized to exercise the powers
and perform the duties of the Commissioner shall have issued an
advance ruling certificate under Section 102 of the Competition
Act to the effect that he is satisfied that he would not have
sufficient ground on which to apply to the Competition Tribunal
under Section 92 of the Competition Act in respect of the Merger,
or the appropriate time period specified in Section 123 of the
Competition Act shall have expired and neither the Commissioner,
nor the Competition Tribunal as authorized under the Competition
Act shall have taken, or have indicated their intention to take,
any action under such Act, whether before or after the completion
of the Merger, which could have a materially adverse effect on the
Merger;
(d) the Minister under the Investment Canada Act (Canada) is satisfied
or deemed to be satisfied that the consummation of the Special
Distribution and Merger are likely to be of net benefit to Canada;
(e) the Petrofund Units issuable pursuant to the Merger shall have
been conditionally approved for listing on the TSX and the AMEX,
subject to the filing of required documentation;
(f) the lenders to each of Ultima Co and Petrofund Co, to the extent
required, shall have consented to the Special Distribution and
Merger, or shall continue to make financing available to Ultima Co
and Petrofund Co subsequent to the Special Distribution and Merger
on conditions acceptable to Ultima Co and Petrofund Co, acting
reasonably; and
(g) such other sanctions, rulings, consents, orders, exemptions,
permits and other approvals as may be necessary for the Merger and
the other transactions contemplated by the Combination Agreement
to be effected in compliance with applicable laws.
Representations and Warranties
The Combination Agreement includes a number of representations and
warranties on behalf of the Ultima Parties and the Petrofund Parties, including
representations and warranties as to:
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(a) the existence of those entities, their power and authority to
enter into the Combination Agreement, the due execution and
delivery of the Combination Agreement and the enforceability of
the Combination Agreement;
(b) the capitalization of the respective parties;
(c) the accuracy of certain financial statements of Ultima and
Petrofund;
(d) the absence of any Material Adverse Changes since specified dates
in the business or affairs of the respective parties;
(e) the absence of any violation of governing documents and agreements
to which the respective parties are subject; and
(f) various other matters intended to establish the condition of the
respective parties in connection with the Special Distribution and
Merger;
which representations and warranties are required to be true and correct at the
Effective Time in all material respects.
Covenants
The Combination Agreement includes a number of covenants given by the
Ultima Parties and the Petrofund Parties. The following is a summary of some of
the material covenants:
(a) each of the Ultima Parties and the Petrofund Parties, prior to
termination of the Combination Agreement, shall conduct its
undertaking and businesses only in, and not take any action except
in, the usual, ordinary and regular course of business and
consistent with past practice except as necessary to comply with
applicable laws or to complete the transactions contemplated by
the Combination Agreement or any transactions entered into prior
to the date of the Combination Agreement;
(b) each of Ultima and Petrofund have agreed to restrictions on
certain interim operations including the issuance of securities,
the sale of assets exceeding certain threshold amounts and the
acquisition of assets exceeding certain threshold amounts;
(c) each of the Ultima Parties and Petrofund Parties shall use their
reasonable best efforts to take, or cause to be taken, all
appropriate action, and to do or cause to be done all things
necessary, proper or advisable under applicable laws and
regulations to consummate and give effect to the transactions
contemplated by the Combination Agreement;
(d) within the prescribed time period and in the prescribed form
provided for in section 132.2 of the Tax Act, Petrofund and Ultima
shall jointly elect to have section 132.2 of the Tax Act apply
with respect to the Merger; and
(e) if the Merger is completed, Petrofund has agreed to arrange for
and/or maintain directors' and officers' insurance coverage for
the directors and officers of Ultima's subsidiaries substantially
equivalent in scope and coverage as the directors' and officers'
coverage in place for the benefit of the directors and officers of
Petrofund's subsidiaries on a "trailing" or "run-off" basis
covering claims made prior to or within five years of the Closing
Date.
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Composition of Board of Directors of Petrofund Co
Pursuant to the Combination Agreement, Petrofund has agreed to use its
reasonable commercial efforts such that, effective as at the Effective Time, the
Petrofund Board of Directors shall be varied to be comprised of two members
mutually agreed to by Ultima and Petrofund, acting reasonably, from among the
individuals presently serving on the Ultima Board of Directors.
Acquisition Proposal and Take-Over Proposal
The Combination Agreement defines "Acquisition Proposal" to mean any
take-over bid, tender offer or exchange offer, merger, amalgamation, plan of
arrangement, reorganization, consolidation, business combination, reverse
take-over, sale of material assets, issuance or sale of securities without the
consent of the other party (other than, in the case of Ultima, pursuant to the
exercise of securities outstanding on the date of execution of the Combination
Agreement and, in the case of Petrofund, pursuant to the exercise of securities
outstanding on the date of execution of the Combination Agreement and securities
issuable pursuant to compensation arrangements of Petrofund to be considered at
the Annual and Special Meeting of Petrofund Unitholders on April 14, 2004),
re-capitalization, liquidation, dissolution, winding-up or similar transaction,
other than the Merger and the other transactions contemplated by the Combination
Agreement.
The Combination Agreement defines "Take-Over Proposal" to mean a bid,
proposal or offer, whether or not subject to conditions, to acquire in any
manner, directly or indirectly, beneficial ownership or control or direction
over 20% or more of the outstanding Ultima Units or Petrofund Units, as the case
may be, whether by way of an arrangement, amalgamation, merger, consolidation,
recapitalization, liquidation, dissolution, reorganization or similar
transaction or other business combination involving Ultima or Petrofund or any
of their respective subsidiaries, as the case may be (and whether in a single or
multi-step transaction or a series of related transactions) or any proposal,
offer or agreement to acquire 20% or more of the assets of Ultima or its
subsidiaries (taken as a whole) or Petrofund or its subsidiaries (taken as a
whole) as the case may be.
Cease Negotiations
Pursuant to the Combination Agreement and subject to the matters set
forth under "Non-Solicitation", each of Ultima and Ultima Co and Petrofund and
Petrofund Co have agreed to, and to direct and use reasonable efforts to cause
their respective trustees, directors, officers, employees, representatives and
agents to, immediately cease and cause to be terminated any discussions or
negotiations with any person, other than the Ultima Parties and the Petrofund
Parties, as the case may be, with respect to any actual, future or potential
Acquisition Proposal. The parties to the Combination Agreement have also agreed
not to release any third party from or forebear in the enforcement of any
confidentiality or standstill agreement to which the Ultima Parties or the
Petrofund Parties and any such third party is a party.
Non-Solicitation
The Combination Agreement also provides that Ultima and Ultima Co and
Petrofund and Petrofund Co shall not, directly or indirectly, through any
trustee, officer, director, employee, financial advisor or other representative
or agent of the Ultima Parties or the Petrofund Parties, as the case may be, (i)
solicit, initiate or encourage (including by way of furnishing information or
entering into any form of agreement, arrangement or understanding) any inquiries
or proposals regarding any Acquisition Proposal involving it or its subsidiaries
or unitholders or participate in or take any other action to facilitate any
inquiries or the making of any proposal which constitutes or may reasonably be
expected to lead to such
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an Acquisition Proposal, or (ii) provide any confidential information to,
participate in any discussions or negotiations relating to any such transactions
with, or otherwise cooperate with or assist or participate in any effort to take
such action by, any person; provided that nothing shall prevent the Ultima Board
of Directors or the Petrofund Board of Directors, as the case may be, from
responding or acting in any manner (including considering, negotiating,
approving and recommending to their respective unitholders (provided that prior
to furnishing information or entering into negotiations with any person, Ultima
and Ultima Co or Petrofund and Petrofund Co, as applicable, shall have complied
with the matters set forth under "Notice of Request for Information", prior to
providing any non-public information to any such person, Ultima and Ultima Co or
Petrofund and Petrofund Co, as applicable, shall have complied with the matters
set forth under "Provision of Information to Requesting Party" and prior to
entering into any Proposed Agreement, Ultima and Ultima Co. shall have complied
with the matters set forth under "Right to Match")) to an unsolicited bona fide
written Acquisition Proposal (i) in respect of which any funds or other
consideration necessary for such Acquisition Proposal has been demonstrated to
the satisfaction of the Ultima Board of Directors or the Petrofund Board of
Directors, as the case may be, to be reasonably likely to be obtained, and (ii)
in respect of which the Ultima Board of Directors or the Petrofund Board of
Directors, as the case may be, determines in good faith would, if consummated in
accordance with its terms, result in a transaction financially more favourable
to Ultima or the Ultima Unitholders or a transaction financially more favourable
to Petrofund or the Petrofund Unitholders, as the case may be, than the
transactions contemplated by the Combination Agreement (any such Acquisition
Proposal being referred to herein as a "Superior Proposal"). Any good faith
determination as aforesaid shall only be made by duly passed resolutions of the
Ultima Board of Directors or the Petrofund Board of Directors, as the case may
be, after consultation with its financial advisors and receipt by such Board of
the advice of counsel reflected in the minutes of its board of directors to the
effect that entertaining or negotiating such Acquisition Proposal or the
furnishing of information concerning the Ultima Parties or the Petrofund
Parties, as applicable, is necessary for such board to satisfy its fiduciary
duties under applicable laws.
Notice of Request for Information
Prior to furnishing any information to, or entering into any
negotiations with, any person in respect of an Acquisition Proposal, each of
Ultima and Ultima Co and Petrofund and Petrofund Co, as the case may be, shall
notify the other party of any Acquisition Proposal received by it or any request
received by it following March 29, 2004 for non-public information relating to
the Ultima Parties or the Petrofund Parties in connection with an Acquisition
Proposal or for access to the properties, books or records of the Ultima Parties
or the Petrofund Parties by any person that informs the Ultima Parties or the
Petrofund Parties that it is considering making, or has made, an Acquisition
Proposal. Such notice shall be made, from time to time, orally and in writing
and shall indicate such details of the proposal, inquiry or contact known to the
Ultima Parties or the Petrofund Parties as the other party may reasonably
request, having regard to the fiduciary obligations of the Ultima Board of
Directors or the Petrofund Board of Directors, as the case may be, and the
identity of the person making such proposal, inquiry or contact.
Provision of Information to Requesting Party
Subject to the matters set forth under "Non-Solicitation", if any of
the Ultima Parties or the Petrofund Parties receives a request for material
non-public information from a person who proposes to the Ultima Parties or the
Petrofund Parties a bona fide Acquisition Proposal and the Ultima Board of
Directors or the Petrofund Board of Directors, as the case may be, determines
that such proposal is a Superior Proposal pursuant to the matters set forth
under "Non-Solicitation", the Ultima Party or the Petrofund Party, as the case
may be, may, subject to the execution of a confidentiality agreement containing
customary terms, conditions and restrictions substantially similar to the
confidentiality agreement entered into between Ultima and Petrofund, provide
such person with access to information regarding the Ultima Party or the
Petrofund Party, as the case may be. To the extent not previously done,
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the party receiving the request from a third party shall provide to the other
party a copy of all information provided to the third party forthwith after the
information is provided to the third party.
Right to Match
Ultima and Ultima Co have agreed not to enter into any agreement (other
than any confidentiality agreement contemplated under "Provision of Information
to Requesting Party") to propose, pursue, support or recommend any Acquisition
Proposal (a "Proposed Agreement") or change their recommendation of the
transactions contemplated by the Combination Agreement except in compliance with
the Combination Agreement and only after providing Petrofund with an opportunity
to amend the Combination Agreement to provide for at least equivalent financial
terms to those included in the Proposed Agreement as determined by the Ultima
Board of Directors, acting reasonably and in good faith and in accordance with
its fiduciary duties, after consultation with Ultima's financial advisors and
Ultima and Ultima Co have agreed to negotiate in good faith with Petrofund in
respect of any such amendment. In particular, in such circumstance Ultima Co has
agreed to provide Petrofund Co with a copy of any Proposed Agreement as executed
or submitted by the party making such Acquisition Proposal, not less than two
business days prior to its proposed execution. In the event that Petrofund and
Petrofund Co agree to amend the Combination Agreement as provided above and
within the two business day period, neither Ultima nor Ultima Co shall enter
into the Proposed Agreement.
Termination Fees
The Combination Agreement provides that if at any time after the
execution of the Combination Agreement and prior to the termination thereof:
(a) the Ultima Board of Directors or the Petrofund Board of Directors
(in such case the Ultima Parties or the Petrofund Parties,
respectively, being the "Non-Completing Party") has withdrawn,
changed or modified in a manner adverse to the other party, or
failed to reaffirm upon request (other than as a result of and in
direct response to a material breach by the other party of their
obligations under the Combination Agreement that would or
reasonably could result in the non-satisfaction of the conditions
precedent to the closing of the transactions contemplated by the
Combination Agreement or a material misrepresentation by the other
party or a Material Adverse Change to the other party) any of (i)
its determination or its recommendations to Ultima Unitholders or
Petrofund Unitholders, as the case may be, to vote in favour of
the Special Distribution and/or the Merger, as applicable, or (ii)
its authorization to complete the Merger as contemplated by its
representation and warranties in the Combination Agreement, or
resolved to take any of the foregoing actions prior to the
completion of the Merger; or
(b) the Ultima Board of Directors or the Petrofund Board of Directors
(in such case the Ultima Parties or the Petrofund Parties,
respectively, being the "Non-Completing Party") has recommended
that, in the case of the Ultima Board of Directors, the Ultima
Unitholders deposit their Ultima Units under, vote in favour of,
or otherwise accept a Take-Over Proposal and, in the case of the
Petrofund Board of Directors, the Petrofund Unitholders deposit
their Petrofund Units under, vote in favour of, or otherwise
accept a Take-Over Proposal; or
(c) prior to the date of the Meeting, a bona fide Take-Over Proposal
is publicly announced, proposed, offered or made to any of the
Ultima Parties or the Petrofund Parties (in such case the Ultima
Parties or the Petrofund Parties, respectively, being the
"Non-Completing Party") or their respective unitholders, the
Merger is not completed and the
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transactions contemplated by any Take-Over Proposal is completed
within 180 days of July 16, 2004; or
(d) any of the Ultima Parties enters into a Proposed Agreement or any
of the Petrofund Parties enters into any agreement to propose,
pursue, support or recommend any Take-Over Proposal (other than a
confidentiality agreement contemplated under "Provision of
Information to Requesting Party") (in such case the Ultima Parties
or the Petrofund Parties, respectively being the "Non-Completing
Party"); or
(e) any of the Ultima Parties or the Petrofund Parties (in such case
the Ultima Parties or the Petrofund Parties, respectively, being
the "Non-Completing Party") breaches any of its representations or
warranties or covenants contained in the Combination Agreement
which breach individually or in the aggregate would or would
reasonably be expected to have a Material Adverse Effect upon the
Non-Completing Party, or would materially impede completion of the
transactions contemplated by the Combination Agreement, and which
the Non-Completing Party fails to cure within five business days
after receipt of written notice thereof from the other party
(except that no cure period shall be provided for a breach by a
Non-Completing Party which by its nature cannot be cured and in no
event shall any cure period extend beyond the Effective Time);
then if the Ultima Parties are the Non-Completing Party, Ultima shall pay to
Petrofund, or if the Petrofund Parties are the Non-Completing Party, Petrofund
shall pay to Ultima, within three business days, an aggregate of $10 million as
liquidated damages in immediately available funds.
Notwithstanding the foregoing, in the event there is a breach in a
representation or warranty or covenant as contemplated in (e) above, and whether
or not the $10 million termination fee is also payable pursuant to any of (a)
through (d) above, the party (not being the Non-Completing Party) shall have the
right at its sole option to either be paid the $10 million termination fee as
liquidated damages or to be paid $1 million and retain the right to pursue any
rights or remedies available to such party as a result of any breach of the
Combination Agreement.
Termination
The Combination Agreement may be terminated prior to the completion of
the Merger:
(a) by mutual written consent of the parties to the Combination
Agreement;
(b) by Ultima and Ultima Co or Petrofund and Petrofund Co if the
closing date of the Merger shall not have occurred on or before
July 16, 2004;
(c) by Ultima and Ultima Co or Petrofund and Petrofund Co if certain
conditions to the Special Distribution and Merger (including those
described above under (a), (b), (c), (f) and (g) under "Conditions
of the Special Distribution and Merger") have not been satisfied
or waived on or before the date required for the performance
thereof unless the failure of any such condition shall be due to
the failure of the party seeking to terminate the Combination
Agreement to perform the obligations required to be performed by
it under the Combination Agreement;
(d) by Ultima and Ultima Co or Petrofund and Petrofund Co if any of
the conditions (other than those described under (c) above) which
are for the benefit of such parties and which
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are contained in the Combination Agreement have not been satisfied
or waived on or before the date required for the performance
thereof; or
(e) by any of Ultima and Ultima Co or Petrofund and Petrofund Co, as
the case may be, if the other party becomes a Non-Completing Party
(as defined under "Termination Fees").
FAIRNESS OPINION
The following summary of the Fairness Opinion is qualified in its
entirety by reference to the full text of the Fairness Opinion, which is
attached and contained herein in Appendix "E" - Fairness Opinion of CIBC World
Markets Inc. Ultima Unitholders are urged to read the Fairness Opinion in its
entirety.
CIBC World Markets was retained by the Ultima Board of Directors, on
its behalf and on behalf of Ultima, effective January 19, 2004 as financial
advisor in connection with the Ultima Board of Directors' consideration and
evaluation of a number of potential strategic transactions involving Ultima. As
discussions and negotiations between Ultima and Petrofund progressed, CIBC World
Markets was, among other things, requested to consider the Special Distribution
and Merger and related matters and make such recommendations relating to
financial matters as it considered appropriate, including the preparation and
delivery to the Ultima Board of Directors of the Fairness Opinion.
In preparing the Fairness Opinion, CIBC World Markets has assumed and
relied on the accuracy and completeness of all information supplied or otherwise
made available to CIBC World Markets, discussed with or reviewed by or for CIBC
World Markets, or publicly available, and CIBC World Markets has not assumed any
responsibility for independently verifying such information nor undertaken an
independent formal valuation or appraisal of any of the Ultima Parties or the
Petrofund Parties or their assets or securities or been furnished with any such
formal valuation or appraisal. The Fairness Opinion is based upon securities
market, economic and general business and financial conditions as they existed
on, and on the information made available to CIBC World Markets as of, April 30,
2004.
Based upon the assumptions and its review of the information described
in the Fairness Opinion, and subject to the limitations contained in the
Fairness Opinion, it is the opinion of CIBC World Markets that the consideration
to be received by Ultima Unitholders pursuant to the Special Distribution and
Merger is fair, from a financial point of view, to the Ultima Unitholders. The
Fairness Opinion was prepared at the request of and for the information of the
Ultima Board of Directors and does not constitute a recommendation to any Ultima
Unitholder as to how any such unitholder should vote with respect to the Merger.
CIBC World Markets will receive fees for its services in connection
with the Merger, some of which are contingent upon the consummation of the
Merger. In addition, Ultima has agreed to reimburse CIBC World Markets for its
reasonable expenses incurred in performance of such services and to indemnify it
in respect of certain liabilities as may be incurred by it in connection with
its engagement.
INTERESTS OF INSIDERS IN THE MERGER AND
INTENTIONS OF CERTAIN INSIDERS
Members of the Ultima Board of Directors and senior officers of Ultima
Co, who collectively own, directly or indirectly, or exercise control or
direction over, an aggregate of 535,921 Ultima Units, representing approximately
1.0% of the Ultima Units outstanding on April 19, 2004, have indicated their
intention to vote their Ultima Units in favour of the Ultima Special Resolution
approving the Special
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Distribution and Merger and have entered into Support Agreements with Petrofund
agreeing to vote their Ultima Units in favour of the Ultima Special Resolution.
Neither the Manager, nor any person who has been a director or senior
officer of Ultima Co, AcquireCo or the Manager at any time since January 1,
2003, the beginning of the most recently completed financial year of Ultima, nor
any proposed nominee for election as a director, nor any associate or affiliate
of any one of them, has any material interest, direct or indirect, by way of
beneficial ownership of securities or otherwise, in any matter to be acted on at
the Meeting except as disclosed in this Information Circular.
CANADIAN FEDERAL INCOME TAX CONSIDERATIONS
In the opinion of Bennett Jones LLP ("counsel"), the following summary
describes the principal Canadian federal income tax considerations pursuant to
the Tax Act generally applicable to an Ultima Unitholder who is entitled to
receive a proportionate amount of the Special Distribution and acquires
Petrofund Units pursuant to the Merger and who, for purposes of the Tax Act,
holds the Ultima Units disposed of and the Petrofund Units acquired as capital
property and deals at arm's length with each of Ultima and Petrofund. Generally,
the Ultima Units or Petrofund Units, as the case may be, will be considered to
be capital property to an Ultima Unitholder provided such Ultima Unitholder does
not hold such Ultima Units in the course of carrying on a business and has not
acquired them in one or more transactions considered to be an adventure or
concern in the nature of trade. Certain Ultima Unitholders who are resident in
Canada and who might not otherwise be considered to hold their Ultima Units or
Petrofund Units as capital property may, in certain circumstances, be entitled
to have them treated as capital property by making the irrevocable election
permitted by subsection 39(4) of the Tax Act. This summary is not applicable to
an Ultima Unitholder that is a "financial institution", as defined in the Tax
Act, for purposes of the mark-to-market rules or an interest in which would be a
"tax shelter investment" as defined in the Tax Act. Any such Ultima Unitholder
should consult its own tax advisor with respect to the Merger.
This summary is based upon the provisions of the Tax Act in force as of
the date hereof, all specific proposals to amend the Tax Act that have been
publicly announced by or on behalf of the Minister of Finance (Canada) prior to
the date hereof (the "Proposed Amendments") including the March 23, 2004
Canadian federal budget (the "budget"), counsel's understanding of the current
published administrative and assessing policies of the Canada Revenue Agency
(the "CRA") and representations of Ultima and Petrofund as to certain factual
matters.
This summary is not exhaustive of all possible Canadian federal income
tax considerations and, except for the Proposed Amendments and the budget, does
not take into account any changes in the law, whether by legislative, regulatory
or judicial action, nor does it take into account provincial, territorial or
foreign tax considerations, which may differ significantly from those discussed
herein.
This summary is of a general nature only and is not intended to be
legal or tax advice to any particular Ultima Unitholder. Consequently, Ultima
Unitholders should consult their own tax advisors having regard to their own
particular circumstances.
Special Distribution
On the last business day immediately prior to the Closing Date of the
Merger, Ultima Unitholders of record will, subject to approving the Ultima
Special Resolution, receive the Special Distribution consisting of an aggregate
cash payment of $10 million and the rights under the Unitholder Indemnity
Agreement which management of Ultima believes has a nominal value. For the
purposes of the Tax Act,
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the Special Distribution will be treated like all other Ultima distributions and
is not conditional on the closing of the Merger.
An Ultima Unitholder resident in Canada for the purposes of the Tax Act
(other than an Exempt Plan) will be required to include in income such
proportionate share of the Special Distribution which represents a distribution
of Ultima's income to the Ultima Unitholder in the taxation year in which the
Special Distribution is paid. Exempt Plans will not generally be liable for any
tax with respect to the Special Distribution. The proportionate share of the
Special Distribution distributed to an Ultima Unitholder in excess of such
Unitholder's share of Ultima's income will generally not be included in the
Ultima Unitholder's income but will reduce the adjusted cost base of the Ultima
Units held by the Ultima Unitholder. To the extent that the adjusted cost base
of Ultima Units would be less than nil, an Ultima Unitholder will be deemed to
have realized a capital gain equal to such negative amount. The taxation of
capital gains is discussed below under "Taxation of Unitholders who are
Residents of Canada".
An Ultima Unitholder who is not resident, or deemed to be resident, in
Canada, will be subject to a 25% Canadian withholding tax on the proportionate
share of Ultima's income which is distributed pursuant to the Special
Distribution at the time the Special Distribution is paid unless such rate is
reduced under the provisions of a tax treaty between Canada and the Ultima
Unitholder's jurisdiction of residence. For example, an Ultima Unitholder
resident in the United States for purposes of the Canada-United States Income
Tax Convention, 1980 (the "Canada-U.S. Treaty") will be entitled to have the
rate of withholding reduced to 15% of the amount of any income distributed. The
proposals under the budget to apply a new 15% Canadian withholding tax on the
non-taxable portion of a distribution should not apply to any non-taxable
portion of the Special Distribution.
The Merger
The Merger will be structured as a "qualifying exchange" pursuant to
section 132.2 of the Tax Act. Accordingly, the disposition by Ultima Unitholders
of Ultima Units in exchange for Petrofund Units pursuant to the terms of the
Merger will not result in a capital gain or capital loss to Ultima Unitholders.
The year end of each of Petrofund and Ultima will be deemed to end in the course
of the Merger and any income of Petrofund or Ultima for such year will be paid
or payable to their respective Unitholders in accordance with the terms of their
respective trust indentures. Ultima and Petrofund have advised counsel that they
will file an election with the CRA in respect of the Merger with the result that
no taxable income will arise in Ultima as a result of the Merger. The aggregate
initial cost of Petrofund Units received by each Ultima Unitholder in exchange
for Ultima Units pursuant to the Merger will be equal to the aggregate adjusted
cost base to such holder of the Ultima Units which are cancelled on the Merger.
This cost will be averaged with the cost of all other Petrofund Units held by
Ultima Unitholders to determine the adjusted cost base of each Petrofund Unit
held.
Status of Combined Trust
Counsel has been advised that Ultima and Petrofund each qualify as a
"unit trust" and a "mutual fund trust" as defined by the Tax Act at all relevant
times. The trust remaining after the Merger will be Petrofund (referred to
hereinafter on or after the Merger as the "Combined Trust") and this summary
assumes that the Combined Trust will also qualify as a mutual fund trust on the
date of the Merger, and will continue to so qualify thereafter for the duration
of its existence. In order to so qualify, there must be at least 150 unitholders
of the Combined Trust ("Unitholders") each of whom owns not less than one
"block" of units of the Combined Trust ("Units") having an aggregate fair market
value of not less than $500. A "block" of Units means 100 Units if the fair
market value of one Unit is less than $25 and 25 Units if the fair market value
of one Unit is greater than $25 and less than $100. In order to qualify as a
mutual fund trust, the Combined Trust cannot, and may not at any time,
reasonably be considered to be
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established or maintained primarily for the benefit of non-resident persons
unless at all times since February 21, 1990, all or substantially all of its
property has consisted of property other than "taxable Canadian property" (as
defined in the Tax Act) (the "property exception"). In addition, the undertaking
of the Combined Trust must be restricted to the investing of its funds in
property (other than real property or an interest in real property), the
acquiring, holding, maintaining, improving, leasing or managing of any real
property (or interest in real property) that is capital property of the Combined
Trust, or a combination of these activities.
Subject to certain transitional relief available until December 31,
2006, the budget proposes that Canadian resource property (which includes the
Ultima Royalties and the Petrofund Royalty) be considered taxable Canadian
property for the purposes of the property exception after March 22, 2004. The
transitional relief contained in the budget is available to those trusts that on
March 23, 2004 (i) were maintained primarily for the benefit of non-resident
persons and (ii) satisfied the property exception. Counsel has been advised by
Petrofund Co that Petrofund satisfied the forgoing requirements on March 23,
2004 and is entitled to rely on the transitional relief contained in the budget.
Accordingly, subsequent to the Merger, the Combined Trust will have until
December 31, 2006 to ensure that it is not maintained primarily for the benefit
of non-resident persons. If the Combined Trust is maintained primarily for the
benefit of non-resident persons on or after January 1, 2007, the Combined Trust
would permanently lose its status as a mutual fund trust.
It is intended, and this summary assumes, that all the forgoing
requirements, including the transitional relief set out in the budget, will be
satisfied so that Ultima, Petrofund and the Combined Trust will each qualify as
a mutual fund trust at all relevant times. In the event that Ultima, Petrofund
or the Combined Trust were not to qualify as a mutual fund trust at the relevant
times, the income tax considerations would in some respects be materially
different from those described herein.
The budget proposes to restrict direct and indirect holdings by
registered pension plans and tax exempt registered pension plan corporations
(together referred to as "pension funds") in certain "business income trusts"
after 2004 through the imposition of certain taxes which are similar to the tax
on foreign property held by pension plans. A "business income trust" does not
include certain "exempt trusts" which includes most real estate investment
trusts and royalty trusts. It is expected that the Combined Trust will be an
exempt trust and that these proposed amendments contained in the budget should
not apply to pension funds investing in units of the Combined Trust.
Taxation of the Combined Trust
The Combined Trust is subject to taxation in each taxation year on its
income for the year, including net realized taxable capital gains, less the
portion thereof that is paid or payable in the year to its Unitholders and which
is deducted by the Combined Trust in computing its income for purposes of the
Tax Act. An amount will be considered to be payable to a Unitholder in a
taxation year if it is paid in the year by the Combined Trust or the Unitholder
is entitled in that year to enforce payment of the amount. Losses incurred by
the Combined Trust cannot be allocated to Unitholders but may be deducted by the
Combined Trust in future years in accordance with the Tax Act. The taxation year
of the Combined Trust is the calendar year.
The Combined Trust will be required to include in its income amounts
computed in accordance with the Ultima Royalties and the Petrofund Royalty held
by the Combined Trust on an accrual basis. The Combined Trust will also be
required to include in its income interest on its investments that accrues to
the Combined Trust to the end of the year, or becomes receivable or is received
by the Combined Trust before the end of the year, except to the extent that such
interest was included in computing its income for
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a preceding taxation year, and any dividends received or deemed to be
received on shares owned by the Combined Trust. Provided that appropriate
designations are made by the Combined Trust, all dividends which would otherwise
be included in its income as dividends received on shares held by the Combined
Trust will be deemed to have been received by Unitholders and not to have been
received by the Combined Trust.
Generally, the Combined Trust may deduct, in computing its income from
all sources for a taxation year, an amount not exceeding 10% of its cumulative
Canadian oil and gas property expense ("COGPE") account at the end of that year,
on a declining balance basis, pro-rated for short taxation years. In addition to
annual deductions in respect of its cumulative COGPE account, the Combined Trust
will be entitled to deduct in computing its income on an annual basis reasonable
administrative expenses incurred for the purpose of earning income from the
Ultima Royalties, the Petrofund Royalty and its other investments, 20% of the
total costs related to the issuance of Petrofund Units on the Merger and on the
issuance of Petrofund Units on prior offerings (pro-rated for short taxation
years) to the extent such issue expenses were not deductible in a previous
taxation year and amounts in respect of a resource allowance and/or deductible
Crown charges computed in accordance with the rules contained in the Tax Act.
The terms of the Combined Trust's trust indenture generally provide
that all income of the Combined Trust for each taxation year be paid or be made
payable to its Unitholders in the taxation year. Counsel has been advised that
the Combined Trust intends to deduct the amount of its income paid or payable to
its Unitholders in computing its income for each taxation year and, therefore,
the Combined Trust should not be liable for any material income tax for each
taxation year.
Taxation of Unitholders who are Residents of Canada
A Unitholder will generally be required to include in computing income
for a particular taxation year of such Unitholder the portion of the net income
of the Combined Trust for a taxation year, including taxable dividends and net
realized taxable capital gains determined for the purposes of the Tax Act, that
is paid or becomes payable to such Unitholder in that particular taxation year
whether paid in cash or property of the Combined Trust. An amount will be
considered payable to a Unitholder in a taxation year if such Unitholder is
entitled in the year to enforce payment of the amount. For the purposes of the
Tax Act, income of a Unitholder from the Combined Trust Units will generally be
considered to be income from property and not resource income. Any deduction or
loss of the Combined Trust for purposes of the Tax Act cannot be allocated to,
or treated as a deduction or loss, of a Unitholder.
Provided that appropriate designations are made by the Combined Trust,
such portions of its net taxable capital gains and taxable dividends as are paid
or payable to a Unitholder will effectively retain their character as taxable
capital gains and taxable dividends, respectively, and shall be treated as such
in the hands of the Unitholder for purposes of the Tax Act. Such dividends will
be subject, among other things, to the gross-up and dividend tax credit
provisions in respect of Unitholders who are individuals, the refundable tax
under Part IV of the Tax Act in respect of certain Unitholders who are
corporations, and the deduction in computing taxable income in respect of
dividends received by taxable Canadian corporations for Unitholders who are
corporations.
Any amount paid or payable by the Combined Trust to a Unitholder in
excess of the net income of the Combined Trust that is paid or payable to such
Unitholder in a taxation year should not generally be included in such
Unitholder's income for the year. However, the proportionate amount of such
excess will reduce the adjusted cost base of each Unit held by the Unitholder.
To the extent that the adjusted cost base of a Unit to a Unitholder would
otherwise be less than nil, the negative amount will be deemed to be a capital
gain realized by the Unitholder from the disposition of the Unit in the year in
which the negative amount arises.
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Upon the disposition or deemed disposition of a Unit by a Unitholder,
whether on redemption or otherwise, the Unitholder will generally realize a
capital gain (or a capital loss) equal to the amount by which the proceeds of
disposition (excluding any amount payable by the Combined Trust which represents
an amount that must otherwise be included in income) are greater (or less) than
the aggregate of the Unitholder's adjusted cost base of the Unit and any
reasonable costs of the disposition. Where, in accordance with the trust
indenture of the Combined Trust, a Unitholder redeems Units and notes held by
the Combined Trust (the "notes") are distributed or debt securities are issued
by the Combined Trust (the "Repurchase Notes"), as the case may be, in
satisfaction of the aggregate redemption price, the proceeds of disposition to
the Unitholder will generally be equal to the fair market value of the notes
distributed or the Repurchase Notes so issued, as the case may be.
One-half of any capital gain realized by a Unitholder on a disposition
or deemed disposition of Units, and the amount of any net taxable capital gains
designated by the Combined Trust in respect of the Unitholder, will be included
in the Unitholder's income under the Tax Act in the year of disposition or
designation, as the case may be, as a taxable capital gain. One-half of any
capital loss (an "allowable capital loss") realized by a Unitholder upon a
disposition of Units may be deducted against any taxable capital gains realized
by the Unitholder in the year of disposition, in any of the three preceding
taxation years or in any subsequent taxation year, to the extent and under the
circumstances described in the Tax Act.
The cost of any note distributed by the Combined Trust to a Unitholder
or Repurchase Note issued to a Unitholder by the Combined Trust upon a
redemption of Units will generally be equal to the fair market value of the note
or Repurchase Note, as the case may be, at the time of distribution or issuance,
respectively, less any accrued interest thereon. Such a Unitholder will be
required to include in income interest paid or accrued on the note or Repurchase
Note, as the case may be, in accordance with the provisions of the Tax Act. To
the extent that a Unitholder is required to include in income any interest that
had accrued to the date of the acquisition of the note, an offsetting deduction
may be available. For purposes of computing the adjusted cost base to a holder
of notes or Repurchase Notes, the respective costs must be averaged with the
adjusted cost base to the holder of all notes or Repurchase Notes, as the case
may be, held at that time by the holder as capital property. Unitholders who
receive a note or a Repurchase Note should consult their own tax advisors,
having regard to their own particular circumstances.
Taxable capital gains realized by a Unitholder that is an individual
may give rise to alternative minimum tax depending on such Unitholder's
circumstances. A Unitholder that is a "Canadian-controlled private corporation"
as defined in the Tax Act may be liable to pay additional refundable tax on
certain investment income, including taxable capital gains, but excluding
certain income distributed from the Combined Trust which is deemed to be income
from property.
Taxation of Tax Exempt Unitholders
Subject to the specific provisions of any particular plan, the Units
will be qualified investments for Exempt Plans. Such Exempt Plans will generally
not be liable for tax in respect of any distributions received from the Combined
Trust or any capital gain realized on the disposition of any Units of the
Combined Trust.
Exempt Plans should contact their own tax advisors with regard to the
acquisition of notes or Repurchase Notes on the redemption of Units to determine
whether such indebtedness constitutes a qualified investment for such Exempt
Plan, having regard to their own particular circumstances. Certain negative tax
consequences may arise where an Exempt Plan acquires or holds a non-qualified
investment.
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The manager to the Combined Trust has advised counsel that, at all
relevant times, the cost amount of foreign property of the Combined Trust, if
any, was, or will be, less than 30% of the cost amount of all property of the
Combined Trust and, accordingly, the Units will not constitute foreign property
for registered retirement savings plans, registered retirement income funds,
deferred profit sharing plans, registered pension plans or other persons subject
to tax under Part XI of the Tax Act.
Taxation of Unitholders who are Non-Residents of Canada
Where the Combined Trust makes distributions to a Unitholder who is not
resident in Canada for purposes of the Tax Act, the same general considerations
as those discussed above with respect to a Unitholder who is resident in Canada
will apply, except that any distribution of income of the Combined Trust to a
Unitholder not resident in Canada will be subject to Canadian withholding tax at
the rate of 25% unless such rate is reduced under the provisions of a tax treaty
between Canada and the Unitholder's jurisdiction of residence. For example,
Unitholders resident in the United States for purposes of the Canada-U.S. Treaty
will generally be entitled to have the rate of withholding reduced to 15% of the
amount of any income distributed.
The budget proposes a new 15% Canadian withholding tax on the
non-taxable portion of the Combined Trust's distributions, which, under the
current provisions of the Tax Act, are not subject to any Canadian withholding
tax. The budget proposes that the new 15% Canadian withholding tax be applicable
to distributions made by the Combined Trust after 2004. The new 15% Canadian
withholding tax will only apply if, at the time of the distribution, Units of
the Combined Trust are listed on a prescribed stock exchange (which includes the
TSX) and the value of the Combined Trust's Units is primarily attributable to
real property situated in Canada, Canadian resource property (which includes the
Ultima Royalties and the Petrofund Royalty) or a timber resource property. If a
subsequent disposition of a Unit results in a capital loss to a non-resident
Unitholder, a refund of the new 15% Canadian withholding tax is available in
limited circumstances, subject to the filing of a special Canadian tax return.
The budget also proposes a 25% withholding tax on distributions made to
non-residents of Canada which are attributable to capital gains realized by the
Combined Trust after March 22, 2004 on the disposition of taxable Canadian
property where the Combined Trust has made certain designations on such capital
gains with respect to its Unitholders. The 25% rate of Canadian withholding tax
may be reduced pursuant to the terms of an applicable income tax treaty between
Canada and the Unitholder's jurisdiction of residence.
A disposition or deemed disposition of Units of the Combined Trust,
whether on redemption, by virtue of capital distributions in excess of a
Unitholder's adjusted cost base or otherwise, will not give rise to any capital
gains subject to tax under the Tax Act to a Unitholder who is not resident nor
deemed to be a resident in Canada provided that the Units of the Combined Trust
held by the Unitholder are not "taxable Canadian property" for the purposes of
the Tax Act. Units of the Combined Trust will not constitute taxable Canadian
property to a non-resident Unitholder unless: (i) the Unitholder holds or uses,
or is deemed to hold or use the Units in the course of carrying on business in
Canada; (ii) the Units are "designated insurance property" of the Unitholder as
defined for purposes of the Tax Act; (iii) at any time during the period of five
years immediately preceding the disposition of the Units the Unitholder or
persons with whom the Unitholder did not deal at arm's length or any combination
thereof, held more than 25% of the issued Units of the Combined Trust or, either
alone or together persons with whom the Unitholder did not deal at arm's length,
held options or rights to acquire more than 25% of the issued Units of the
Combined Trust; or (iv), the Combined Trust is not a mutual fund trust on the
date of disposition.
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Subject to proposals to amend the Tax Act contained in the budget, a
Unitholder who is not resident in Canada will generally compute the adjusted
cost base of a Unit pursuant to the same rules as apply to residents of Canada.
For the purposes of computing a non-resident Unitholder's adjusted cost base of
a Unit after 2004, the budget proposes that a distribution paid in respect of a
Unit which is subject to the new 15% Canadian withholding tax will not reduce
the adjusted cost base of such Unit to a non-resident Unitholder.
Non-resident Unitholders are urged to consult their own tax advisors on
the application of the budget to the ownership of Units of the Combined Trust,
having regard to their own particular circumstances.
UNITED STATES FEDERAL INCOME TAX CONSIDERATIONS
The following summary describes the U.S. federal income tax
considerations generally applicable to U.S. Holders (as defined below) of Ultima
Units who receive a proportionate amount of the Special Distribution and who
exchange their Ultima Units for Petrofund Units in the Merger. This summary is
based upon the Internal Revenue Code of 1986, as amended (the "Code"), proposed,
temporary and final U.S. Treasury regulations under the Code, administrative
rulings and judicial decisions, all as in effect as of the date of this document
and all of which are subject to change (possibly with retroactive effect) or to
differing interpretations. This summary applies only to holders of Ultima Units
that hold their Ultima Units, and will hold the Petrofund Units that they
receive in the Merger, as capital assets within the meaning of Section 1221 of
the Code. This summary does not discuss all aspects of U.S. federal income
taxation that may be relevant to a particular holder of Ultima Units in light of
its particular circumstances or to holders of Ultima Units subject to special
treatment under the U.S. federal income tax laws, including:
o banks, insurance companies, trusts and financial institutions;
o tax-exempt organizations;
o mutual funds;
o persons that have a functional currency other than the U.S.
dollar;
o traders in securities who elect to apply a mark-to-market method
of accounting;
o dealers in securities or foreign currency;
o holders of Ultima Units who received their units in compensatory
transactions; and
o holders of Ultima Units who hold their units as part of a hedge,
straddle, constructive sale, conversion transaction or other
integrated investment
For purposes of this summary, a U.S. Holder is:
o an individual who is a U.S. citizen or resident alien for U.S.
federal income tax purposes;
o a corporation, or entity taxable as a corporation, created or
organized under the laws of the United States, any state thereof,
or the District of Columbia;
o an estate that is subject to U.S. federal income tax on its
worldwide income; or
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o a trust if (i) a U.S. court is able to exercise supervision over
the administration of the trust and one or more U.S. persons have
the authority to control all substantial decisions of the trust or
(ii) the trust has a valid election in effect to be treated as a
U.S. person for U.S. federal income tax purposes.
If a partnership holds Ultima Units, the U.S. federal income tax
treatment of a partner in the partnership generally will depend upon the status
of the partner and the activities of the partnership. Partners of partnerships
that hold Ultima Units should consult their tax advisors regarding the U.S.
federal income tax consequences to them of the Merger.
Classification of Ultima and Petrofund as Non-U.S. Corporations
Although Ultima and Petrofund are organized as trusts under Canadian
law, this summary is based on the assumption that both Ultima and Petrofund are
classified as non-U.S. corporations for U.S. federal income tax purposes under
current U.S. Treasury regulations. Accordingly, Ultima and Petrofund Units are
treated as shares of stock of non-U.S. corporations for U.S. federal income tax
purposes. This summary reflects this classification and uses terminology
consistent with this classification, including references to "dividends" and
"earnings and profits".
The Special Distribution
Subject to the passive foreign investment company ("PFIC"), foreign
investment company ("FIC"), and foreign personal holding company ("FPHC") rules
discussed below, the gross amount of the Special Distribution (before reduction
for Canadian withholding taxes) will be taxable to holders of Ultima Units as a
dividend to the extent of Ultima's current and accumulated earnings and profits,
as determined under U.S. federal income tax principles. To the extent that the
amount of the Special Distribution exceeds Ultima's current and accumulated
earnings and profits, as determined under U.S. federal income tax principles,
the Special Distribution will be treated as a tax-free return of capital,
causing a reduction in the adjusted basis of the Ultima Units. Any balance in
excess of adjusted basis will be subject to tax as capital gain.
Subject to certain limitations, dividends paid to noncorporate U.S.
Holders, including individuals, may be eligible for a reduced rate of taxation
if Ultima is deemed to be a "qualified foreign corporation" for U.S. federal
income tax purposes. A qualified foreign corporation includes a non-U.S.
corporation that is eligible for the benefits of a comprehensive income tax
treaty with the United States that includes an exchange of information program
and that the U.S. Treasury Department has determined to be satisfactory for
purposes of the qualified dividend provisions of the Code. The U.S. Treasury
Department has determined that the income tax treaty between the United States
and Canada is satisfactory for purposes of the qualified dividend provisions of
the Code. A qualified foreign corporation does not include a non-U.S.
corporation that is a PFIC, a FIC, or a FPHC for the taxable year in which a
dividend is paid or for the preceding taxable year. Ultima stated in 2003 that
it believed that it would qualify as a PFIC for the year ended December 31,
2003. If this is the case, U.S. Holders of Ultima Units would not be eligible
for the reduced rate of taxation on the Special Distribution. U.S. Holders are
urged to consult their tax advisors regarding the application of the reduced
rate of taxation to the Special Distribution.
Exchange of Ultima Units for Petrofund Units
For U.S. federal income tax purposes, the exchange of Ultima Units for
Petrofund Units in the Merger has been structured to qualify as a reorganization
under the provisions of Section 368(a) of the Code. The U.S. federal income tax
treatment of the exchange to a U.S. Holder of Ultima Units, however,
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generally will depend on whether Ultima has been a PFIC at any time during which
the U.S. Holder has held the Ultima Units.
Passive Foreign Investment Company Rules
Special U.S. federal income tax rules apply to U.S. Holders if Ultima
currently is or has been a PFIC at any time during which the U.S. Holder has
held Ultima Units. A non-U.S. corporation generally is classified as a PFIC for
U.S. federal income tax purposes in any taxable year if, either (i) at least 75%
of its gross income is "passive" income (the "income test"), or (ii) on average
at least 50% of the gross value of its assets is attributable to assets that
produce passive income or are held for the production of passive income (the
"asset test"). For purposes of the income test and the asset test, if a non-U.S.
corporation owns directly or indirectly at least 25% (by value) of the stock of
another corporation, the non-U.S. corporation will be treated as if it held its
proportionate share of the assets of the latter corporation and received
directly its proportionate share of the income of that latter corporation.
Passive income generally includes dividends, interest, royalties, rents
(other than rents and royalties derived in the active conduct of a trade or
business and not derived from a related person), certain net gains from the
sales of commodities such as oil and natural gas, annuities and gains from
assets that produce passive income. Passive income does not include, however,
any income that is interest, a dividend or a rent or royalty received or accrued
from a related person to the extent that the amount is properly allocable to
income of the related person that is not passive income. For these purposes, a
related person includes a subsidiary controlled by the non-U.S. corporation,
where control means ownership, directly or indirectly, of stock possessing more
than 50% of the total voting power of all classes of stock entitled to vote or
of the total value of the stock of a corporation.
The Code and applicable U.S. Treasury regulations exclude gains from
transactions in commodities from the definition of passive income if (i) the
gains arise from the sale of the commodity in the active conduct of a
commodities business as a producer, processor, merchant or handler of the
commodity and (ii) substantially all of the non-U.S. corporation's business is
as an active producer, processor, merchant or handler of the commodity.
Ultima believes that it should be considered to be engaged in the
active conduct of a commodities business, and thus should not be a PFIC for
2004. Because this conclusion is a factual determination that is made annually
and is subject to change, there can be no assurances that Ultima will not be a
PFIC for the current or any future taxable year. Ultima stated in 2003 that it
had qualified as a PFIC for taxable years prior to 2003 and that it believed
that it would qualify as a PFIC for the year ended December 31, 2003.
Treatment if Ultima is a PFIC with respect to a U.S. Holder
If Ultima has been a PFIC at any time during the time during which a
U.S. Holder has held Ultima Units, the exchange of Ultima Units for Petrofund
Units in the Merger should be a taxable transaction to the U.S. Holder. In such
case, a U.S. Holder should recognize gain upon exchanging its Ultima Units for
Petrofund Units. Such gain should be equal to the difference between the fair
market value of the Petrofund Units received and the U.S. Holder's adjusted tax
basis in the Ultima Units exchanged. Such gain should be recognized on a
share-by-share basis and should be taxable as an "excess distribution" under the
PFIC rules. An excess distribution should be allocated ratably to each day that
the U.S. Holder held Ultima Units. Amounts allocated to the current taxable year
and to years before Ultima became a PFIC should be treated as ordinary income.
In addition, amounts allocated to each taxable year beginning with the year
Ultima first became a PFIC should be taxed at the highest rate in
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effect for that year on ordinary income. The tax should be subject to an
interest charge at the rate applicable to deficiencies for income tax.
A U.S. Holder generally should not be permitted to recognize a loss on
the exchange of Ultima Units for Petrofund Units. The U.S. Holder's basis in the
Petrofund Units received should be adjusted to reflect the gain realized. The
U.S. Holder's holding period in the Petrofund Units received should begin on the
day after the Merger.
Treatment if Ultima is not a PFIC with respect to a U.S. Holder
If Ultima has not been a PFIC at any time during the time during which
a U.S. Holder has held Ultima Units, the U.S. Holder of Ultima Units should not
be required to recognize gain on the exchange of its Ultima Units for Petrofund
Units. The aggregate adjusted tax basis of the Petrofund Units received in the
Merger should be equal to the aggregate adjusted tax basis of the Ultima Units
surrendered for the Petrofund Units. The holding period of the Petrofund Units
received should include the period during which the U.S. Holder held the Ultima
Units.
Treatment if Ultima is a PFIC with respect to a U.S.
Holder and Petrofund is a PFIC
If, contrary to Petrofund's current belief (discussed below), Petrofund
is determined to be a PFIC for 2004, and Ultima has also been a PFIC at any time
during which a U.S. Holder has held Ultima Units, such a U.S. Holder of Ultima
Units should not be required to recognize gain on the exchange of its Ultima
Units for Petrofund Units. The aggregate adjusted tax basis of the Petrofund
Units received in the Merger should be equal to the aggregate adjusted tax basis
of the Ultima Units surrendered for the Petrofund Units. The holding period of
the Petrofund Units received should include the period during which the U.S.
Holder held the Ultima Units.
Recordkeeping Requirements
Each U.S. Holder of Ultima Units that receives Petrofund Units in the
Merger will be required to file a statement with its U.S. federal income tax
return providing its basis in the Ultima Units surrendered and the fair market
value of the Petrofund Units received, and to retain permanent records of this
information relating to the Merger.
Ownership of Petrofund Units
Distributions on Petrofund Units
Subject to the PFIC, FIC, and FPHC rules discussed below, the gross
amount of any cash distributions on the Petrofund Units (before reduction for
Canadian withholding taxes) will be taxable to a U.S. Holder as dividends to the
extent of Petrofund's current and accumulated earnings and profits, as
determined under U.S. federal income tax principles. As discussed above under
"The Special Distribution", dividends paid to noncorporate U.S. Holders,
including individuals, by a qualified foreign corporation may be eligible for a
reduced rate of taxation. Distributions on the Petrofund Units should be
eligible for this reduced rate of taxation as long as Petrofund is not a PFIC, a
FIC, or a FPHC and is eligible for the benefits of the income tax treaty between
the United States and Canada.
Distributions will be includable in a U.S. Holder's gross income on the
date actually or constructively received by the U.S. Holder. These dividends
will not be eligible for the dividends-received deduction generally allowed to
U.S. corporations in respect of dividends received from other U.S. corporations.
To the extent that the amount of any cash distribution exceeds Petrofund's
current and
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accumulated earnings and profits, as determined under U.S. federal income tax
principles, the distribution will first be treated as a tax-free return of
capital, causing a reduction in the adjusted basis of the Petrofund Units
(thereby increasing the amount of gain or decreasing the amount of loss that a
U.S. Holder would recognize on a subsequent disposition of the Petrofund Units),
and the balance in excess of adjusted basis will be subject to tax as capital
gain.
To the extent Petrofund pays dividends on the Petrofund Units in
Canadian dollars, the U.S. dollar value of such dividends should be calculated
by reference to the exchange rate prevailing on the date of actual or
constructive receipt of the dividend, regardless of whether the Canadian dollars
are converted into U.S. dollars at that time. If Canadian dollars are converted
into U.S. dollars on the date of actual or constructive receipt of such
dividends, a U.S. Holder's tax basis in such Canadian dollars will be equal to
their U.S. dollar value on that date and, as a result, the U.S. Holder generally
should not be required to recognize any foreign currency exchange gain or loss.
Any gain or loss recognized on a subsequent conversion or other disposition of
the Canadian dollars generally will be treated as U.S. source ordinary income or
loss.
A U.S. Holder may be entitled to deduct, or claim a U.S. foreign tax
credit for, Canadian taxes that are withheld on dividends received by the U.S.
Holder, subject to applicable limitations in the Code. Dividends paid on the
Petrofund Units generally will constitute "passive income" or, in the case of
certain U.S. Holders, "financial services income" and will be treated as income
from sources without the United States for U.S. foreign tax credit limitation
purposes. The amount of foreign income taxes that may be claimed as a credit in
any year is subject to complex limitations and restrictions, which must be
determined on an individual basis by each holder. U.S. Holders are urged to
consult their tax advisors regarding the availability of the U.S. foreign tax
credit in their particular circumstances.
Sale, Exchange or Other Disposition of Petrofund Units
Subject to the PFIC and FIC rules discussed below, upon the sale,
exchange or other disposition of common shares, a U.S. Holder generally will
recognize capital gain or loss equal to the difference between the amount
realized upon the sale, exchange or other disposition of Petrofund Units and the
U.S. Holder's adjusted tax basis in the Petrofund Units. The capital gain or
loss generally will be long-term capital gain or loss if, at the time of sale,
exchange or other disposition, the U.S. Holder has held the Petrofund Unit for
more than one year. Net long-term capital gains of noncorporate U.S. Holders,
including individuals, are eligible for reduced rates of taxation. The
deductibility of capital losses is subject to limitations. Any gain or loss that
a U.S. Holder recognizes generally will be treated as gain or loss from sources
within the United States for U.S. foreign tax credit limitation purposes.
Passive Foreign Investment Company Rules
As discussed under "Exchange of Ultima Units for Petrofund Units -
Passive Foreign Investment Company Rules", above, special rules apply in
determining whether a non-U.S. corporation is a PFIC. Petrofund believes that it
should be considered to be engaged in the active conduct of a commodities
business, and thus should not be a PFIC for 2004. Because this conclusion is a
factual determination that is made annually and is subject to change, there can
be no assurances that Petrofund will not be a PFIC for the current or any future
taxable year. Under the Code, if Petrofund were considered to be a PFIC in any
taxable year that a U.S. Holder held Petrofund Units, Petrofund generally would
be considered a PFIC for all taxable years that such U.S. Holder held Petrofund
Units after the first taxable year that Petrofund was considered to be a PFIC.
In general, if Petrofund were a PFIC, a U.S. Holder would be taxed at
ordinary income tax rates on any gain realized on the sale or exchange of the
Petrofund Units and on any "excess distributions"
-48-
received. Excess distributions are amounts received by a U.S. Holder with
respect to Petrofund Units in any taxable year that exceed 125% of the average
distributions received by the U.S. Holder in the shorter of either the three
previous years or the U.S. Holder's holding period for the Petrofund Units
before the current taxable year. Gain and excess distributions would be
allocated ratably to each day that that U.S. Holder held Petrofund Units.
Amounts allocated to the current taxable year and to years before Petrofund
became a PFIC would be treated as ordinary income. In addition, amounts
allocated to each taxable year beginning with the year Petrofund first became a
PFIC would be taxed at the highest rate in effect for that year on ordinary
income. The tax would be subject to an interest charge at the rate applicable to
deficiencies for income tax.
Rather than being subject to this tax regime, a U.S. Holder could:
o make a qualified electing fund ("QEF") election to be taxed
currently on its pro rata portion of Petrofund's income and gain,
whether or not such income or gain were distributed in the form of
dividends or otherwise; or
o make a "mark-to-market" election and thereby agree, for the year
of the election and each subsequent tax year, to recognize
ordinary gain or, to the extent of any prior ordinary gain,
ordinary loss based on the increase or decrease in market value
for such taxable year. A U.S. Holder's basis in its shares would
be adjusted to reflect any such income or loss amounts.
A QEF election generally should be made for the first taxable year in
which a corporation is a PFIC.
If Petrofund were a PFIC, a U.S. Holder would be required to file
Internal Revenue Service Form 8621 for each year in which the U.S. Holder held
Petrofund Units.
U.S. Holders are strongly urged to consult their own tax advisors
regarding possible classification of Petrofund as a PFIC and the adverse tax
consequences that would result from such classification.
Foreign Investment Company Rules
Special U.S. federal income tax rules would apply to U.S. Holders if
Petrofund were a FIC. A non-U.S. corporation generally is classified as a FIC
for U.S. federal income tax purposes in any taxable year if it is (i) engaged
primarily in the business of investing, reinvesting, or trading in securities,
commodities, or interests in securities or commodities (ii) at a time when 50%
or more of the total combined voting power of all classes of stock entitled to
vote, or the total value of all classes of stock, is held, directly or
indirectly, by U.S. persons. After the Merger, U.S. persons may own 50% or more
of Petrofund's voting power or value. As discussed above, however, Petrofund
believes that it is engaged in the active conduct of a commodities business and
thus is not the type of investment company intended to be covered by the FIC
rules.
Foreign Personal Holding Company Rules
Special U.S. federal income tax rules would apply to U.S. Holders if
Petrofund were a FPHC. A non-U.S. corporation generally is classified as a FPHC
for U.S. federal income tax purposes in any taxable year if both (i) five or
fewer individuals who are U.S. citizens or residents actually or constructively
own more than 50% of all classes of the corporation's stock by vote or value at
any time during the corporation's taxable year and (ii) at least 60% of the
corporation's income is passive income,
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as described above with respect to the PFIC rules. Petrofund believes that it
should not currently be a FPHC. Because this conclusion is a factual
determination that is made annually and is subject to change, there can be no
assurances that Petrofund will not be a FPHC for the current or any future
taxable year.
Information Reporting and Backup Withholding
In general, unless a U.S. Holder belongs to a category of certain
exempt recipients (such as corporations), information reporting requirements
will apply to dividends as well as proceeds of sales of Petrofund Units that are
effected through the U.S. office of a broker or the non-U.S. office of a broker
that has certain connections with the United States. Backup withholding may
apply to these payments if a U.S. Holder fails to provide a correct taxpayer
identification number or certification of exempt status, fails to report in full
dividend and interest income or, in certain circumstances, fails to comply with
applicable certification requirements. Any amounts withheld under the backup
withholding rules will be allowed as a refund or credit against a U.S. Holder's
U.S. federal income tax, provided the U.S. Holder furnishes the required
information to the Internal Revenue Service in a timely manner.
SELECTED PRO FORMA INFORMATION RELATING TO PETROFUND
The following sets forth selected information relating to Petrofund and
Ultima together with pro forma information of Petrofund after giving effect to
the Special Distribution and Merger and certain other adjustments. Additional
information concerning Petrofund and Ultima is set forth in Appendices "B" and
"C" to this Information Circular. In addition, attached as Appendix "D" to this
Information Circular are Unaudited Pro Forma Combined Financial Statements of
Petrofund giving effect to the Special Distribution and Merger and certain other
adjustments.
The pro forma combined financial information set forth below and the
Unaudited Pro Forma Combined Financial Statements set forth in Appendix "D"
hereto are not necessarily indicative either of results of operations that would
have occurred in the year ended December 31, 2003 had the proposed Merger and
certain other adjustments been effected on January 1, 2003, or of the results of
operations expected in 2004 and future years. In preparing the pro forma
statements, no adjustments have been made to reflect the operating synergies and
the resulting cost savings expected to result from combining the operations of
Petrofund and Ultima.
Selected Pro Forma Combined Financial Information
The following table sets out certain financial information for
Petrofund and Ultima as at and for the year ended December 31, 2003 and for
Petrofund on a pro forma basis as at and for the year ended December 31, 2003
after giving effect to the Special Distribution and Merger and certain other
adjustments. The following is a summary only and must be read in conjunction
with the Unaudited Pro Forma Combined Financial Statements of Petrofund set
forth in Appendix "D" to this Information Circular.
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As at and for the year ended December 31, 2003
----------------------------------------------
Pro Forma
After Giving Effect
Petrofund Ultima to the Merger
------------- ----------- --------------------
($ millions)
Revenues....................... 393.1 111.1 504.2
Cash flow(1)................... 187.6 54.9 245.8
Net income..................... 85.8 12.3 62.0
Total assets................... 943.9 326.5 1,522.2
Working capital (deficiency)... (30.0) (8.2) (42.1)
Long term debt................. 110.3 73.1 193.7
Unitholders' equity............ 649.2 208.4 1,102.0
Note:
(1) Management of Ultima Co uses cash flow (before changes in non-cash
working capital) to analyze financial performance, as one measure to
benchmark performance against peers, and as one measure to determine
distribution levels. Cash flow is calculated as net income for the
period plus charges to income not requiring an outlay of funds less
credits to net income not involving a source of funds. Cash flow as
presented does not have any standardized meaning prescribed by
Generally Accepted Accounting Principles in Canada ("GAAP") and
therefore it may not be comparable with the calculation of similar
measures by other entities. Cash flow as presented is not intended to
represent operating cash flows or operating profits for the period nor
should it be viewed as an alternative to cash flow from operating
activities, net income or other measures of financial performance
calculated in accordance with GAAP. All references to cash flow
throughout this report are based on cash flow before changes in
non-cash working capital.
Selected Combined Operational Information
The following table sets out certain operational information for
Petrofund and Ultima on a pro forma combined basis after giving effect to the
Merger. Further operational information concerning Petrofund and Ultima is set
forth in their respective annual information forms which are attached as
Appendices "B" and "C" to this Information Circular.
Combined
After Giving Effect
Petrofund Ultima to the Merger
--------------- ------------ ------------------------
Production(1)
Natural gas (MMcf/d) ................ 79.4 13.7 93.1
Oil and NGLs (Bbls/d) ............... 13,448 8,065 21,513
Total (BOE/d)(3)..................... 26,681 10,348 37,029
Reserves(2)(3)
Proved (MBOE)........................ 81,762 30,725 112,487
Proved plus Probable (MBOE) ......... 102,030 41,377 143,407
Reserve Life Index(4)
Proved............................... 8.4 years 8.1 years 8.3 years
Proved plus Probable................. 10.5 years 11.0 years 10.6 years
Undeveloped land (thousands of net acres)... 250,509 35,270 285,779
Notes:
(1) Based on the 2004 forecast of proved plus probable production of each
of Petrofund and Ultima as estimated by the independent engineers of
each of Petrofund and Ultima in their respective reports of oil and gas
reserves as at December 31, 2003.
(2) Calculated on a gross basis before deducting royalties, without
including royalty interests, and based on the evaluations of the
independent engineers of each of Petrofund and Ultima as at December
31, 2003. The 11.7136% net royalty interest held by Ventures Trust in
the Weyburn Unit is treated as a working interest as Ultima is
responsible for its share of capital costs, operating costs, royalties
and abandonment costs.
(3) BOEs may be misleading, particularly if used in isolation. A BOE
conversion of 6 mcf:1 bbl is based on an energy equivalency conversion
method primarily applicable at the burner tip and does not represent a
value equivalency at the wellhead.
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(4) Calculated as proved reserves or proved plus probable reserves, as the
case may be, divided by 2004 forecast of proved plus probable
production.
Pro Forma Combined Capitalization
The following table sets out the capitalization of Petrofund and Ultima
as at December 31, 2003, together with the pro forma combined capitalization of
Petrofund as at December 31, 2003 after giving effect to the Merger and certain
other adjustments. The following is a summary only and, where applicable, must
be read in conjunction with the Unaudited Pro Forma Combined Financial
Statements of Petrofund set forth in Appendix "D" to this Information Circular.
As at December 31, 2003
----------------------------------------------------------------------
Pro Forma
After Giving Effect
Petrofund Ultima to the Merger
-------------------- ------------------- ----------------------
Net debt ($ millions)(1)..................... $140.3 $81.4 $235.8
Units outstanding ($ millions) (2) .......... $1,031.2 $324.8 $1,102.0
(73.6 million units) (57.6 million units) (100.1 million units)
Notes:
(1) Long term debt plus working capital deficiency as at December 31, 2003.
Ultima net debt also includes its deferred capital obligation relating
to the 11.7136% net royalty interest held by Ventures Trust in the
Weyburn Unit. Pro forma net debt reflects the payment of the Special
Distribution and excludes transaction costs.
(2) Units outstanding for Petrofund includes those issuable upon conversion
of outstanding exchangeable shares. Pro forma units outstanding
reflects exercise of all outstanding Ultima Rights.
RISK FACTORS
Ultima Unitholders should carefully consider the information described
under the heading "Competitive Conditions and Risk Factors" in the Renewal
Annual Information Form of Ultima dated April 30, 2004 set forth in Appendix "C"
of this Information Circular and under the heading "Risk Factors" in the Renewal
Annual Information Form of Petrofund dated March 15, 2004 set forth in Appendix
"B" of this Information Circular, as well as the other information set forth
elsewhere in this Information Circular.
In addition to the foregoing, income tax laws, or 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 Petrofund and the
Petrofund Unitholders. For instance, certain proposed amendments to the Tax Act
announced in the Canadian federal government's 2004 budget may affect the
permitted amount of non-Canadian resident ownership of the Petrofund Units and
may result in increased withholding tax on Petrofund's cash distributions paid
to non-residents of Canada. In particular, the proposed transition period within
which Petrofund may be required to take certain steps to ensure that it "not be
maintained primarily for the benefit of non-residents" of Canada (as defined in
the Tax Act), currently proposed to end on January 1, 2007, may be shortened or
eliminated. Whether or not the transition period is shortened or eliminated,
Petrofund may not be able to take steps necessary to ensure that Petrofund "not
be maintained primarily for the benefit of non-residents" within the prescribed
transition period, if any, and to ensure that Petrofund maintains its mutual
fund trust status. Even if Petrofund is successful in taking such measures,
there can be no assurance that such measures will be completed in a manner that
is not detrimental to Petrofund Unitholders, including both non-resident
Petrofund Unitholders and the Petrofund Unitholders as a whole. Additionally,
legislation may be implemented to limit the investment in income funds and
royalty trusts by certain investors or to change the manner in which these
entities are taxed. Tax authorities having jurisdiction over Petrofund or the
Petrofund Unitholders may disagree with how
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Petrofund calculates its income for tax purposes or could change administrative
practices to the detriment of Petrofund or the detriment of the Petrofund
Unitholders.
STOCK EXCHANGE LISTINGS
The currently outstanding Ultima Units are listed and posted for
trading on the TSX and the Petrofund Units are listed and posted for trading on
the TSX and the AMEX. Following the Closing Date of the Merger, the Ultima Units
will be delisted from the TSX. Information with respect to the trading history
of the Petrofund Units is contained under the heading "Additional Information
Regarding Petrofund Energy Trust - Trust Unit Price Range and Trading Volumes"
and the Ultima Units is contained under the heading "Additional Information
Regarding Ultima Energy Trust - Trust Unit Price Range and Trading Volumes".
TIMING
The Merger will become effective at Closing. If the Ultima Special
Resolution is approved at the Meeting and all other conditions specified in the
Combination Agreement are satisfied or waived, Petrofund and Ultima expect the
Closing Date will be on or about June 16, 2004.
EXPENSES OF THE MERGER
The costs to be incurred by Ultima relating to the Merger including,
without limitation, accounting and legal fees, financial advisor fees,
contractual severance obligations, the preparation and printing of this
Information Circular and other out-of-pocket costs associated with the Meeting,
but excluding retention payments and statutory severance obligations, are
estimated to be approximately $6.6 million.
INTERESTS OF EXPERTS
As of the date hereof, the partners and associates of each of Bennett
Jones LLP, considered as a group, beneficially own, directly or indirectly, less
than 1% of the issued and outstanding Ultima Units. Mr. John H. Kousinioris, a
partner with Bennett Jones LLP, is the Corporate Secretary of Ultima Co, Ultima
Energy, AcquireCo and the Manager. As of the date hereof, the partners of
Deloitte & Touche LLP do not beneficially own, directly or indirectly, any of
the issued and outstanding Ultima Units. As of the date hereof, the partners of
Collins Barrow Calgary LLP do not beneficially own, directly or indirectly, any
of the issued and outstanding Ultima Units. As of the date hereof, each of
Gilbert Laustsen Jung Associates Ltd. and McDaniel & Associates Consultants
Ltd., considered as a group, beneficially own, directly or indirectly, less than
1% of the issued and outstanding Ultima Units.
OTHER LEGAL MATTERS
Resale of Petrofund Securities
The Petrofund Units to be issued to Ultima Unitholders pursuant to the
Merger will be issued in reliance on exemptions from prospectus and registration
requirements of applicable securities laws of the various applicable provinces
and territories in Canada and (other than in Quebec and New Brunswick as
described below) will generally be "freely tradeable" (and not subject to any
"restricted period" or "hold period") if the following conditions are met: (i)
the trade is not a control distribution (as defined in applicable securities
legislation); (ii) no unusual effort is made to prepare the market or to create
a demand for the securities that are the subject of the trade; (iii) no
extraordinary commission or consideration is paid to a person or company in
respect of the trade; and (iv) if the selling securityholder
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is an insider or an officer of the issuer, the selling securityholder has no
reasonable grounds to believe that the issuer is in default of securities
legislation.
Notice of the Merger and of the issuance of the Petrofund Units
pursuant thereto will be submitted to the Autorite des marches financiers (the
"Autorite") on behalf of Petrofund which, if accepted by, or if no objection is
received within 15 days from, the Autorite, will result in the Petrofund Units
received by Ultima Unitholders resident in the Province of Quebec not being
subject to the registration and prospectus requirements of such province to
permit such securities to be freely tradeable under the applicable securities
laws of such province. In addition, an application will be made to the Office of
the Administrator for the Province of New Brunswick to provide that Petrofund
Units received by Ultima Unitholders resident in such province will not be
subject to the registration and prospectus requirements of such province and to
permit such securities to be freely tradeable (other than as a result of any
"control block" restrictions which may arise by virtue of the ownership thereof)
under applicable securities laws of such province.
It is a condition of the Combination Agreement and the completion of
the Merger that all approvals, regulatory or otherwise, necessary in respect of
the Special Distribution and Merger be obtained. See "Details of the Merger --
The Combination Agreement - Conditions of the Special Distribution and Merger".
Information for United States Holders
This Information Circular has been prepared in accordance with Canadian
disclosure requirements, which differ from those in the United States. The
financial statements and other financial information herein have been prepared
in accordance with Canadian generally accepted accounting principles that are
subject to Canadian auditing and auditor independent standards and thus may not
be comparable to financial statements and other financial information of United
States companies. Information concerning oil and gas operations and reserves
have been prepared in accordance with Canadian requirements, which differ
significantly from those of the SEC.
The Petrofund Units to be issued to United States holders of Ultima
Units pursuant to the Merger will be registered under the 1933 Act, and such
securities will be freely tradeable under applicable United States securities
laws except for any securities acquired by an affiliate of Ultima or Petrofund.
Unitholders are urged to consult their legal advisers to determine the
extent of all applicable resale provisions.
DOCUMENTS FILED AS PART OF PETROFUND'S U.S. REGISTRATION STATEMENT
A registration statement on Form F-10 has been filed by Petrofund with
the SEC under the 1933 Act relating to the Merger. The following documents have
been or will be filed with the SEC as part of the Registration Statement of
which this Information Circular is a part, insofar as called for by the SEC's
Form F-10: (i) the Form of Proxy accompanying this Information Circular; (ii)
the Combination Agreement; (iii) consents of independent auditors, counsel,
engineers and the financial advisor; and (iv) powers of attorney pursuant to
which the amendments to the Registration Statement may be signed.
AVAILABILITY OF DISCLOSURE DOCUMENTS
In the United States, Petrofund is subject to the informational
requirements of the United States Securities Exchange Act of 1934, as amended,
and in accordance therewith must file reports and other information with the
SEC. Under a multijurisdictional disclosure system adopted by the SEC, such
-54-
reports and other information may be prepared in accordance with the disclosure
requirements of Canada, which requirements are different from those in the
United States. Such reports and other information filed by Petrofund are
available for inspection and copying at the public reference facilities
maintained by the SEC at Room 1024, 450 Fifth Street, NW, Judiciary Plaza,
Washington, DC 20549.
PART III - ADDITIONAL INFORMATION
REGARDING ULTIMA ENERGY TRUST
General
Information with respect to Ultima and its business, operations and
affairs are included in the following (which are attached as Appendix "C" and
form an integral part of this Information Circular):
1. Ultima Energy Trust Renewal Annual Information Form dated April 30,
2004 for the year ended December 31, 2003, including the Compilation
Report and the Unaudited Pro Forma Combined Financial Statements of
Ultima Energy Trust after giving effect to the acquisition of all of
the issued and outstanding shares in the capital of Trioco Resources
Inc.;
2. Ultima Energy Trust Management's Discussion and Analysis for the year
ended December 31, 2003 compared to the year ended December 31, 2002;
and
3. Ultima Energy Trust comparative audited consolidated financial
statements as at and for the years ended December 31, 2003 and 2002 and
the auditors' report thereon.
Distributions
Income of Ultima that is distributed to the Ultima Unitholders pursuant
to the Ultima Trust Indenture is calculated by the Manager and is approved by
the Ultima Board of Directors and the board of directors of AcquireCo. The
Ultima Trustee distributes the income to Ultima Unitholders of record on the
last day of each month on the 15th day of the following month, or if such day
does not fall on a business day, the next business day following the 15th day of
the month. The following cash distributions per Ultima Unit have been made to
Ultima Unitholders during the periods indicated below:
2002 2003 2004
First Quarter........... $0.19 $0.27 $0.255
Second Quarter.......... 0.23 0.27 N/A
Third Quarter........... 0.24 0.285 N/A
Fourth Quarter.......... 0.24 0.265 N/A
-------- -------- ----------
Total Annual............ $0.90 $1.09 $0.255
======== ======== ==========
Trust Unit Price Range and Trading Volumes
The currently outstanding Ultima Units are listed on the TSX. The
following table shows the high, low and closing prices and volume of trading of
the Ultima Units on the TSX, as reported by such exchange, for the periods
indicated.
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Unit Price
Range($)
--------------------------
High Low Close Trading Volume
------- ------ --------- --------------
2002
First Quarter......................... 5.45 4.12 5.25 2,012,668
Second Quarter........................ 6.06 5.05 5.91 4,929,460
Third Quarter......................... 5.95 5.30 5.84 8,103,931
Fourth Quarter........................ 5.89 4.90 5.15 7,993,507
2003
First Quarter......................... 5.68 5.05 5.30 9,596,702
Second Quarter........................ 5.53 5.07 5.42 12,860,905
Third Quarter......................... 6.25 5.22 6.13 24,868,329
Fourth Quarter........................ 6.36 5.69 6.24 16,758,872
2004
January............................... 7.04 6.20 6.89 5,945,912
February.............................. 7.07 6.16 7.03 7,688,115
March................................. 7.73 6.96 7.62 5,864,881
April (through April 29).............. 7.62 7.05 7.07 6,694,800
On March 26, 2004, the last trading day prior to the announcement of the Merger,
the closing price of the Ultima Units on the TSX was $7.47. On April 29, 2004,
the closing price of the Ultima Units on the TSX was $7.07.
Executive Compensation
Compensation of the Ultima Trustee
The Ultima Trustee was reimbursed for costs and expenses it incurred as
trustee of Ultima for the year ended December 31, 2003. Compensation is paid to
the Ultima Trustee for the services it provides as trustee and as transfer agent
and registrar of Ultima. The Ultima Trustee was paid $16,512 as compensation for
the services it provided as trustee of Ultima for the year ended December 31,
2003. The Ultima Trustee was paid $44,932 for the services it provided as
transfer agent and registrar of Ultima for the year ended December 31, 2003.
Compensation of the Manager
Pursuant to the terms of the Management Agreement, the Manager provides
services in connection with the management and administration of Ultima,
Ventures Trust, Ultima Co and AcquireCo, and in connection with the operation of
the properties and assets owned, or which may be acquired, by Ventures Trust
and/or AcquireCo. The delegation of authority to the Manager is subject to the
supervision of, and restrictions imposed from time to time by, the Ultima Board
of Directors and the board of directors of AcquireCo, and the provisions of the
Management Agreement. In particular, the Ultima Board of Directors and the board
of directors of AcquireCo have exclusive authority over matters such as the
annual operating budget, acquisitions and dispositions of properties, capital
expenditures and acquisitions in excess of $2,000,000, borrowing limits and
policies, equity financing approval and Ultima's cash distribution policy. The
Manager also provides services to Ultima Energy.
On March 26, 2003, Ultima, through 1032213 Alberta Ltd. ("1032213") (a
wholly-owned subsidiary of Ultima), acquired all of the issued and outstanding
common shares of the Manager for a total cash payment of $3,800,000, plus
management and retention obligations of $1,500,000 (the "Management
Internalization Transaction"). Prior to the Management Internalization
Transaction,
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Ultima Co, for and on behalf of Ventures Trust, AcquireCo and the Ultima
Trustee, for and on behalf of Ultima, paid the Manager certain management fees
(the "Management Fees"), administration fees (the "Administration Fees") and
acquisition fees (the "Acquisition Fees"). Management Fees of $487,000 were paid
to the Manager for the period commencing January 1, 2003 and ending on March 26,
2003. No Acquisition Fee or Administration Fee was payable for that period. As a
result of the Management Internalization Transaction, the Manager is now a
wholly-owned subsidiary of Ultima. Consequently, any fees paid to the Manager
are now effectively for the account of Ultima as they remain within the trust
structure.
Compensation of Executive Officers of Ultima Co, AcquireCo and Ultima Energy
The officers of each of Ultima Co, AcquireCo and Ultima Energy receive
no direct compensation from those companies.
Pursuant to the terms of the Management Agreement, Ultima Co, AcquireCo
and the Ultima Trustee, for and on behalf of Ultima, reimburse the Manager for
the costs and expenses incurred by the Manager in the management and
administration of Ultima, Ventures Trust, Ultima Co and AcquireCo. The Manager
is also reimbursed for the costs and expenses it incurs for services it provides
to Ultima Energy. The Ultima Board of Directors and the board of directors of
AcquireCo, having regard to industry salaries, approve the amounts paid in
respect of salaries and benefits as part of their approval of the general and
administrative budget of the Manager.
The following table details the total compensation paid, during each of
the last three financial years, to the President and Chief Executive Officer of
the Manager and each of the executive officers of the Manager whose total salary
and bonus exceeded $100,000 during the financial year ended December 31, 2003
(collectively, the "Named Executive Officers").
Long Term
Annual Compensation Compensation
-------------------------------------- ------------------
Other Annual Securities Under All Other
Salary(1) Bonus Compensation Rights Granted Compensation(1)(2)(3)
Name and Principal Position Year ($) ($) ($) (#) ($)
-------------------------------- ------ -------- --------- -------------- ------------------ ------------------------
S. Brian Gieni 2003 $200,000 $100,000 Nil 70,000 $19,001
President and 2002 $127,500 $75,000 Nil Nil $11,970
Chief Executive Officer 2001 $93,125 $75,000 Nil 200,000 $11,938
Kenneth G. Pinsky 2003 $170,000 $85,000 Nil 60,000 $17,201
Chief Financial Officer 2002 $106,250 $65,000 Nil Nil $10,549
2001 $67,904 $55,000 Nil 175,000 $9,033
Michael P. Wihak 2003 $170,000 $85,000 Nil 60,000 $17,201
Chief Operating Officer 2002 $110,500 $51,500 Nil Nil $10,833
2001 $49,563 $50,000 Nil 175,000 $6,401
Notes:
(1) The amounts set forth under these columns for the financial years ended
December 31, 2002 and 2001 do not include the portion of salary and
other compensation paid by the Weyburn Limited Partnership to the Named
Executive Officer. No salary or other compensation was paid by the
Weyburn Limited Partnership to the Named Executive Officer for the
financial year ended December 31, 2003.
(2) In connection with the Management Internalization Transaction and
pursuant to the Ultima Employment Agreements, each of Messrs. Gieni,
Pinsky and Wihak also received $125,000 in cash and 11,200 Ultima Units
at closing. Each of Messrs. Gieni, Pinsky and Wihak also received
$83,333 (paid by the issuance of 11,462 Ultima Units) on the first
anniversary of the closing of the Management Internalization
Transaction and, pursuant to the Ultima Employment Agreement, are
entitled to receive an additional $83,333 on each of the second and
third anniversary dates of the closing of the Management
Internalization Transaction, in each instance paid by the issuance of
Ultima Units based on the weighted average price of the Ultima Units on
the TSX during the 20 consecutive trading days preceding the date of
payment. In connection with the Merger, the Ultima Board of Directors,
on behalf of Ultima, resolved to accelerate the timing of the payments
pursuant to the Ultima Employment Agreements to immediately prior to
the record date of the
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Special Distribution so that the right to acquire Ultima Units pursuant
to the Ultima Employment Agreements is received immediately prior to
the payment of the Special Distribution.
(3) The Manager has a company-sponsored savings plan (the "Savings Plan")
pursuant to which the Manager contributes up to 6% of an employee's
salary to the Savings Plan if the employee contributes up to 4% of his
or her salary to the Savings Plan. The amounts paid to the Named
Executive Officers pursuant to the Savings Plan are included in this
column.
Employment Agreements
Pursuant to the terms of the Ultima Employment Agreements, Messrs.
Gieni, Wihak and Pinsky are entitled to annual salaries of $200,000, $170,000
and $170,000, respectively, subject to annual review. Further, upon the
occurrence of a termination event, including the sale of all or substantially
all of the assets of Ultima, each of Messrs. Gieni, Wihak and Pinsky is entitled
to receive: (i) a sum equal to his salary for the month immediately preceding
termination, multiplied by 18, in the case of Mr. Gieni, or 12, in the case of
Messrs. Wihak and Pinsky, plus the number of full or partial years of service to
a maximum of 24 months, in the case of Mr. Gieni, or 18 months, in the case of
Messrs. Wihak and Pinsky; and (ii) the simple average of the largest annual
bonuses and other compensation paid to the Named Executive Officer during two of
the three years immediately preceding termination, multiplied by 1.5, in the
case of Mr. Gieni, or 1.0, in the case of Messrs. Wihak and Pinsky, plus the
number of full or partial years of service divided by 12.
The Ultima Employment Agreements also provide that upon the occurrence
of a termination event, including the sale of all or substantially all of the
assets of Ultima, each of Messrs. Gieni, Wihak and Pinsky may elect, by written
notice to Ultima, to receive a cash payment in respect of his vested Ultima
Rights equal to the number of such vested Ultima Rights multiplied by the amount
by which the market price for the Ultima Units (determined in accordance with
the Ultima Employment Agreement) exceeds the exercise price for such Ultima
Rights.
Ultima TURIP
Ultima currently has a Trust Unit Rights Incentive Plan, the purpose of
which is to:
1. develop the interest of directors, officers, employees and key
consultants of Ultima and its affiliates in the growth and development
of Ultima by providing such persons with the opportunity to acquire a
proprietary interest in Ultima;
2. provide a compensation mechanism for persons who provide a service to
Ultima and its affiliates on an ongoing basis, or who have provided, or
are expected to provide, a service of value to Ultima; and
3. align the interests of directors, officers, employees and key
consultants with those of Ultima Unitholders by devising a compensation
mechanism which encourages the prudent maximization of distributions to
Ultima Unitholders and long-term value growth of the Ultima Units.
The Ultima TURIP permits the Ultima Board of Directors and the board of
directors of AcquireCo to grant rights to acquire Ultima Units to those persons
eligible to participate in the Ultima TURIP. Rights to acquire Ultima Units may
only be granted with the approval of the Ultima Board of Directors and the board
of directors of AcquireCo. As at December 31, 2003, rights to acquire 2,007,669
Ultima Units pursuant to the Ultima TURIP were outstanding. Rights to acquire an
aggregate of 512,998 Ultima Units pursuant to the Ultima TURIP were exercised
during the financial year ended December 31, 2003.
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In the event that the amount of distributions to Ultima Unitholders in
any calendar quarter is greater than 2.5% of the book value of the oil and
natural gas properties and other assets of Ultima, the book value of which is
reflected in the "Capital assets, net" account appearing on the most recent
annual or quarterly, as the case may be, balance sheet of Ultima (the "Capital
Assets"), then the exercise price of each right to acquire Ultima Units pursuant
to the Ultima TURIP then outstanding shall, at the election of the holder
thereof on the date of exercise of such rights, be reduced by an amount equal to
the distributions for the calendar quarter calculated on a per Ultima Unit
basis, less 2.5% of the book value of the Capital Assets at the end of such
calendar quarter calculated on a per Ultima Unit basis. For purposes of the
Ultima TURIP, distributions in any calendar quarter shall be deemed to consist
of the aggregate distributable income declared by Ultima in such calendar
quarter.
Ultima Rights Grants During the Year Ended December 31, 2003
The following table provides details of rights to acquire Ultima Units
granted pursuant to the Ultima TURIP to the Named Executive Officers during the
year ended December 31, 2003:
Market Value of
% of Total Ultima Securities
Rights Granted to Underlying Ultima
Ultima Units Employees and Rights on the Date
under Ultima Directors in Exercise Price of Grant
Name Rights Granted Financial Year ($/Unit) ($/Units) Expiration Date
--------------------- ----------------- ------------------ ----------------- ---------------------- ------------------
S. Brian Gieni 70,000 6.1% 5.27 5.27 January 14, 2014
Kenneth G. Pinsky 60,000 5.2% 5.27 5.27 January 14, 2014
Michael P. Wihak 60,000 5.2% 5.27 5.27 January 14, 2014
Note:
(1) As at December 31, 2003, the average exercise price of each right to
acquire an Ultima Unit pursuant to the Ultima TURIP was subject to a
downward adjustment of $0.63 per Ultima Unit, at the holder's
discretion, in accordance with the adjustment provisions of the Ultima
TURIP. To date no Named Executive Officer has elected to utilize the
downward adjustment when exercising such rights.
Aggregated Ultima Rights Exercised During the Year Ended December 31, 2003
--------------------------------------------------------------------------
The following table sets forth certain information respecting the
number and accrued value of unexercised rights to acquire Ultima Units granted
pursuant to the Ultima TURIP as at December 31, 2003 and rights to acquire
Ultima Units granted pursuant to the Ultima TURIP exercised by the Named
Executive Officers during the financial year ended December 31, 2003:
Value of Unexercised
In-the-Money Ultima
Unexercised Ultima Rights at December 31,
Rights at December 31, 2003(2)(3)
2003 ($)
---------------------- -------------------------
Aggregate Value
Securities Acquired Realized
Name on Exercise ($)(1)(2) Vested Not Vested Vested Not Vested
-------------------- -------------------- ---------------- --------- ------------ ---------- --------------
S. Brian Gieni 133,333 42,668 - 136,667 - 190,567
Kenneth G. Pinsky 58,333 99,999 58,333 118,334 107,333 165,535
Michael P. Wihak 60,000 86,400 56,666 118,334 104,265 165,535
Notes:
(1) The aggregate value realized represents the dollar value equal to the
difference between the exercise price of the rights exercised and the
market value of the Ultima Units on the TSX on the date the rights were
exercised, multiplied by the number of rights exercised.
(2) Excluding the downward adjustment, which to date no Named Executive
Officer has elected to receive.
(3) The value of the unexercised "in-the-money" rights has been determined
by subtracting the exercise price of the rights from the closing Ultima
Unit price of $6.24 on December 31, 2003, as reported by the TSX, and
multiplying by the number of Ultima Units that may be acquired upon the
exercise of the rights.
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The balance of the rights to acquire Ultima Units granted pursuant to
the Ultima TURIP during the year ended December 31, 2003 were granted to
employees of the Manager and to directors of Ultima Co and AcquireCo.
Trust Unit Option Agreements
In July 2000, options to purchase Ultima Units (the "Options") were
issued to certain directors of Ultima Co and AcquireCo, at a fixed price, in
order to encourage ownership of Ultima Units by such directors. All of such
Options had been exercised prior to the commencement of the current financial
year.
The following table summarizes the number of Ultima Units acquired
pursuant to the exercise of the Options during the financial year ended December
31, 2003 and the aggregate value realized upon exercise. Value realized upon
exercise is the difference between the market value of the Ultima Units on the
exercise date and the exercise price of the Options.
Value of Unexercised
Unexercised Options at in-the-Money Options at
December 31, 2003 December 31, 2002 ($)
---------------------- ------------------------
Securities Acquired Aggregate Value
Name on Exercise Realized ($) Vested Not Vested Vested Not Vested
----------------------- ------------------- --------------- -------- ----------- --------- -------------
Marshall M. Williams 50,000 109,000 Nil Nil Nil Nil
Compensation of Directors
The directors of each of Ultima Co and AcquireCo are paid an annual
retainer and meeting fees. However, directors who are also officers of the
Manager receive no consideration for also serving as a director of Ultima Co or
AcquireCo.
The directors of Ultima Co and AcquireCo, other than the chairman (the
"Chairman") of the Ultima Board of Directors and the board of directors of
AcquireCo and those directors who are also officers of the Manager, each
received an annual retainer of $10,000 and $750 per joint meeting of the boards
of directors of Ultima Co and AcquireCo or committees of Ultima Co and AcquireCo
attended in 2003. The Chairman received an annual retainer of $16,875 and $750
per joint meeting of the boards of directors of Ultima Co and AcquireCo or
committees of Ultima Co and AcquireCo attended in 2003. For the year ended
December 31, 2003, a total of $63,125 was paid in annual retainers and $92,500
was paid for attendance at meetings to the directors of Ultima Co and AcquireCo.
Report on Executive Compensation
The Human Resources Committee is responsible for developing the
approach of the Ultima Board of Directors and the board of directors of
AcquireCo in establishing and implementing appropriate compensation and human
resource strategies, policies and practices in order to attract, motivate and
retain the quality of personnel required to meet the business objectives of
Ultima. Within the scope of the Human Resources Committee's mandate, it assesses
the performance of senior management of Ultima Co, AcquireCo, Ultima Energy and
the Manager, and reviews and approves the form and amount of compensation that
they receive including short and long-term incentive plans.
In carrying out its mandate and formulating its recommendations, the
Human Resources Committee takes into consideration a number of factors including
the education and experience of each individual, such individual's performance,
the value of such individual to Ultima, the financial
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performance of Ultima and the relative competitiveness of the overall
compensation of such individual within the industry.
Salary
------
The salaries of the Named Executive Officers are reviewed annually
having regard to a number of factors including the expertise, experience and
performance of each individual and the comparative levels of compensation paid
to executives of other industry participants of comparable size. In respect of
the salary levels established for the Named Executive Officers for 2003, the
Human Resources Committee did not specifically retain the advice of independent
consultants but rather relied on public disclosure by comparable companies and
knowledge obtained from other sources regarding competitive compensation
packages within the industry. The current view of the Human Resources Committee
is that the salaries paid to the Named Executive Officers is appropriate having
regard to a number of factors including Ultima's relative size.
Ultima Rights
-------------
Directors, officers, employees and consultants are eligible to
participate in the Ultima TURIP. Awards of rights to acquire Ultima Units are
made from time to time to participants at varying levels having regard to each
individual's level of responsibility. The term and certain other provisions of
the rights to acquire Ultima Units granted under the Ultima TURIP, including the
vesting period, are at the discretion of the Ultima Board of Directors and the
board of directors of AcquireCo. The outstanding rights to acquire Ultima Units
granted to the Named Executive Officers to date have been made to align their
interests with those of Ultima Unitholders on a long-term basis with a view to
encouraging the prudent maximization of distributions to Ultima Unitholders and
the growth in long-term value of Ultima Units.
Discretionary Bonus
-------------------
The Ultima Board of Directors and the board of directors of AcquireCo
have discretion from time to time to grant bonuses to reward exceptional
individual performance and the achievement of short term goals. In respect of
the 2003 financial year, an aggregate of $698,000 was awarded as bonuses to
officers and employees of the Manager in recognition of the superior financial
and operating performance attained by Ultima during 2003.
Compensation of the Chief Executive Officer
-------------------------------------------
Mr. Gieni received the base salary, bonus and rights to acquire Ultima
Units outlined in this Information Circular for the calendar year 2003. See
"Executive Compensation - Compensation of Executive Officers of Ultima Co,
AcquireCo and Ultima Energy". These levels were established and approved by the
Ultima Board of Directors and the board of directors of AcquireCo having regard
to the foregoing considerations.
The foregoing report has been furnished by the Human Resources
Committee consisting of Messrs. Lee (Chairman), Dumont and Williams.
Performance Table
The following table and graph illustrates changes in cumulative Ultima
Unitholder return on Ultima Units from December 31, 1998 to December 31, 2003,
assuming an initial $100 investment in Ultima Units on December 31, 1998 and the
reinvestment of cash distributions, compared to the
-61-
cumulative return of the S&P/TSX Composite Index and the TSX Oil and Gas
Producers Index for the comparable period.
Cumulative Value of $100 Investment
December 31
-----------------------------------------------------------
1998 1999 2000 2001 2002 2003
-------- -------- -------- -------- -------- ---------
Ultima Energy Trust............................. $100 $136 $238 $318 $461 $673
S&P/TSX Composite Index......................... $100 $132 $141 $123 $108 $137
TSX Oil & Gas Producers Index................... $100 $122 $179 $185 $211 $259
Ultima Energy Trust
Relative Total Return History
December 31, 1998 to December 31, 2003
[ATTORNEY TO PROVIDE TABLE]
Statement of Corporate Governance Practices
In December 1994, the TSX Committee on Corporate Governance in Canada
issued a report setting out a series of guidelines for effective corporate
governance which were subsequently incorporated into the TSX's Company Manual as
formal disclosure policies (the "TSX Guidelines"). The TSX Guidelines address
matters such as the constitution and independence of corporate boards of
directors, the functions to be performed by boards of directors and their
committees, and the effectiveness and education of board members. The TSX
requires a listed issuer to disclose, on an annual basis, its approach to
corporate governance with specific reference to the TSX Guidelines. Set out
below are the 14 TSX Guidelines and a brief description of Ultima's compliance
with those guidelines in light of its existing governance practices, which have
been established by the terms of the Ultima Trust Indenture, the Ventures USA,
the AcquireCo USA, and the Management Agreement. The Ultima Board of Directors
and the boards of directors of AcquireCo, Ultima Energy and the Manager, all of
which are comprised of the same members, are collectively referred to below as
the "Boards of Ultima".
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1. The boards should explicitly assume responsibility for stewardship of
Ultima, and specifically for adoption of a strategic planning process,
identification of principal risks, succession planning and monitoring,
communications policy and integrity of internal control and management
information systems.
The directors of Ultima Co and AcquireCo have, pursuant to the Ultima
Trust Indenture, the authority and responsibility to make or approve
most significant decisions affecting Ultima. Each of the Ultima Co USA
and AcquireCo USA provides that the Ultima Board of Directors and the
board of directors of AcquireCo may give special, but not exclusive,
consideration to the interests of the Ultima Unitholders in determining
whether a matter under its consideration is in the best interests of
Ultima Co and AcquireCo, respectively. While day-to-day management of
Ultima, Ventures Trust, Ultima Co, AcquireCo and Ultima Energy has been
delegated to the Manager (largely pursuant to the Management
Agreement), the directors fulfill their responsibility for the broader
stewardship of the business and affairs of Ultima, Ventures Trust,
Ultima Co, AcquireCo, Ultima Energy and the Manager through the
activities and procedures set forth below:
o While management is directly involved with, and often initiates
the strategic planning process for, Ultima, the Boards of Ultima
remain integral to the implementation of strategic business
decisions through their review of matters at board meetings and
through the involvement of directors, individually, with
management in the analysis and assessment of strategic business
alternatives for Ultima. The Boards of Ultima approve all
significant decisions affecting Ultima, Ventures Trust, Ultima Co,
AcquireCo, Ultima Energy and the Manager.
o The Boards of Ultima participate in strategic planning through the
review of annual forecasts, the approval of annual operating and
capital budgets and by providing advice to management. Other
strategic issues, such as acquisition or disposition transactions
or financings, are addressed at meetings of the Boards of Ultima
with members of senior management. The Boards of Ultima have set
strategic objectives to maximize distributions to Ultima
Unitholders, maintain a prudent capital structure, and pursue
appropriate acquisition and disposition opportunities, all with a
view to maximizing Ultima Unitholder value.
o The duties and limitations of the Manager are generally contained
in the Management Agreement. The day-to-day management of the
business and affairs of Ultima, Ventures Trust, Ultima Co,
AcquireCo and Ultima Energy is undertaken by the Manager, subject
to overview by the Boards of Ultima. As a result of the Management
Internalization Transaction, the Manager is now a wholly-owned
subsidiary of Ultima.
o The Boards of Ultima have assigned responsibility for senior
management succession planning to the Human Resources Committee of
the Ultima Board of Directors and the President and Chief
Executive Officer of Ultima Co, AcquireCo, Ultima Energy and the
Manager. The Human Resources Committee and the President and Chief
Executive Officer consult with, and seek approval from, the Boards
of Ultima with respect to senior management appointments. The
appointment of officers of Ultima Co, AcquireCo, Ultima Energy and
the Manager are made by their respective board of directors.
o Management has implemented internal control and information
systems including systems for compiling and processing accounting
and production information as part of the day-to-day management of
the business and affairs of Ultima, Ventures Trust, Ultima Co,
AcquireCo and Ultima Energy. The Boards of Ultima monitor the
effectiveness of
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these systems by reviewing operational and financial status
reports presented at board meetings. As well, the Audit Committee
of the Boards of Ultima meets independently with the auditors to
receive reports on the adequacy of such systems.
o The Boards of Ultima establish parameters within which management
may conduct certain activities such as those related to risk
management. The Boards of Ultima rely on management, in the
day-to-day management of the business and affairs of Ultima,
Ventures Trust, Ultima Co, AcquireCo and Ultima Energy, to
identify any significant business risks outside those parameters
and review such risks with individual directors, as circumstances
dictate, and thereafter with the full Boards of Ultima.
o Management has, with the approval of the Boards of Ultima, assumed
primary responsibility for communications with Ultima Unitholders.
Senior management attempts to respond to inquiries by individual
Ultima Unitholders in a timely fashion. The President and Chief
Executive Officer and the Chief Financial Officer of the Manager
also meet with interested Ultima Unitholders from time to time and
report to the Boards of Ultima on feedback that they have received
from Ultima Unitholders.
2. A majority of directors should be "unrelated" (free from conflicting
interest).
The Boards of Ultima are currently comprised of seven members, all of
whom have extensive and varied business experience. An "unrelated"
director for the purposes of the TSX Guidelines is one who is
independent of management and is free from any interest and any
business or other relationship that could, or could reasonably be
perceived to, materially interfere with the director's ability to act
with a view to the best interests of Ultima, Ventures Trust, Ultima Co,
AcquireCo and Ultima Energy, other than interests and relationships
arising from shareholdings. In defining an unrelated director, the TSX
Guidelines place emphasis on the ability of a director to exercise
objective judgment, independent of management. Alternatively, a related
director is a director who is not an unrelated director. The TSX
Guidelines also make an informal distinction between inside and outside
directors. The TSX Guidelines consider an inside director to be one who
is an officer or employee of the corporation or any of its affiliates.
The majority of the members of the Boards of Ultima are "unrelated
directors", as defined in the TSX Guidelines. Each of the Ultima Co USA
and AcquireCo USA provides that all of the members of each board of
directors be elected by the Ultima Unitholders. Ultima does not have a
significant unitholder with the ability to exercise a majority of the
votes for the election of directors.
3. Disclose for each director whether he or she is related, and how that
conclusion was reached.
The Boards of Ultima are of the view that Mr. Brian Gieni is a related
director as he is the President and Chief Executive Officer of Ultima
Co, AcquireCo, Ultima Energy and the Manager. The Boards of Ultima are
of the view that all of the remaining directors of Ultima Co,
AcquireCo, Ultima Energy and the Manager are unrelated to Ultima,
Ventures Trust, Ultima Co, AcquireCo, Ultima Energy and the Manager in
that they do not form part of the management team and are free from any
interest or other relationship that could, or could reasonably be
perceived to, materially interfere with their ability to act with a
view to the best interests of Ultima, Ventures Trust or the respective
corporations.
4. Appointment of a Committee responsible for appointment/assessment of
directors.
Given the relatively small size of the Boards of Ultima, it has been
determined that the establishment of a nominating committee whose
responsibility would be to propose new
-64-
nominees to the Boards of Ultima is unnecessary. New nominees to the
Boards of Ultima are reviewed by the Boards of Ultima. Assessment of
individual director's performance and the effectiveness of the Boards
of Ultima, as a whole, are considered to be of significant importance
and are undertaken by the Boards of Ultima and the Governance Committee
of the Ultima Board of Directors, which consists of Messrs. Art Dumont
(Chairman), David Tuer and Marshall Williams, all of which are
"unrelated directors".
5. Implement a process for assessing the effectiveness of the Board, its
Committees and individual directors.
Responsibility for the assessment of the effectiveness of the Boards of
Ultima, as a whole, the committees of the Boards of Ultima and the
contribution of individual directors rests with the Boards of Ultima
and the recently appointed Governance Committee. The Governance
Committee has been charged with developing and reviewing the approach
of Ultima to governance matters and was in the process of developing a
more formal process for assessing the effectiveness of the Boards of
Ultima and individual directors prior to the announcement of the
Merger.
6. Provide orientation and education programs for new directors.
To date, the directors of Ultima Co, AcquireCo, Ultima Energy and the
Manager have been persons with extensive and varied business
experience. Accordingly, Ultima Co, AcquireCo, Ultima Energy and the
Manager have not established a formal orientation and education program
for new directors. Ultima Co, AcquireCo, Ultima Energy and the Manager
would, however, provide orientation to new directors on an informal
basis as required depending on their background and knowledge of
Ultima's business and operations.
7. Consider reducing size of Board, with a view to improving
effectiveness.
The Ventures USA and the AcquireCo USA require the Ultima Board of
Directors and the board of directors of AcquireCo to consist of seven
members. The Boards of Ultima believe that this number of directors
promotes efficiency and effectiveness. There is no intention to
increase or reduce the number of directors further.
8. Review the compensation of directors in light of risks and
responsibilities.
The Ultima Board of Directors has established a Human Resources
Committee consisting of Messrs. Gary Lee (Chairman), Henry Lawrie and
Marshall Williams, all of which are "unrelated directors". One of the
functions of the Human Resources Committee is to review the adequacy
and form of directors' compensation and make recommendations designed
to ensure the directors' compensation realistically reflects the
responsibilities of the Boards of Ultima. It is also responsible for
the overall approval of the compensation policies and levels of
compensation for Ultima Co, AcquireCo, Ultima Energy and the Manager.
9. Committees should generally be composed of outside directors, a
majority of whom are unrelated.
The Boards of Ultima have established a Human Resources Committee, a
Reserves Committee, a Governance Committee and an Audit Committee.
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o The Human Resources Committee consists of Messrs. Gary Lee
(Chairman), Henry Lawrie and Marshall Williams, all of which are
"unrelated" and "outside" directors. This Committee assesses the
performance of senior management of Ultima Co, AcquireCo, Ultima
Energy and the Manager and reviews and approves the form and
amount of compensation that they receive including short and
long-term incentive plans. The Committee also evaluates the fees
that directors receive.
o The Reserves Committee consists of Messrs. John Gunn (Chairman),
David Tuer and Art Dumont, all of which are "unrelated" and
"outside" directors. This Committee is responsible for reviewing,
approving and reporting annually on the independent engineers'
reserve reports.
o The Audit Committee consists of Messrs. Henry Lawrie (Chairman),
John Gunn and Gary Lee, all of which are "unrelated" and "outside"
directors. The Audit Committee reviews the quarterly and annual
consolidated financial statements of Ultima and the systems of
internal control for Ultima, Ventures Trust, Ultima Co, AcquireCo,
Ultima Energy and the Manager. The Audit Committee meets
periodically with the Chief Financial Officer of Ultima Co,
AcquireCo, Ultima Energy and the Manager, and with the auditors of
Ultima, Ventures Trust, Ultima Co, AcquireCo and Ultima Energy, as
necessary, to review the audit process independently of
management.
o The Governance Committee consists of Messrs. Art Dumont
(Chairman), David Tuer and Marshall Williams, all of which are
"unrelated" and "outside" directors. The Committee is responsible
for developing and reviewing the approach of Ultima to corporate
governance matters.
10. Appoint a Committee responsible for Ultima's approach to corporate
governance issues.
The Ultima Board of Directors has appointed a Governance Committee,
which has been mandated to assume responsibility for developing
Ultima's approach to governance issues.
11. The Board should develop position descriptions for the Board and for
the Chief Executive Officer, and the Board should approve or develop
corporate objectives, which the Chief Executive Officer is responsible
for meeting.
The President and Chief Executive Officer is accountable to the Boards
of Ultima for meeting corporate objectives. The Boards of Ultima has
delegated to the President and Chief Executive Officer the
responsibility for the day-to-day management of Ultima's business
subject to compliance with plans and objectives approved from time to
time by the Boards of Ultima. A written position description has been
prepared for the President and Chief Executive Officer. Any
responsibility that is not delegated to the President and Chief
Executive Officer or a Committee remains with the Boards of Ultima, who
have not yet developed formal position descriptions. The Boards of
Ultima have set the strategic objectives for Ultima, Ventures Trust,
Ultima Co, AcquireCo and Ultima Energy and have approved all operating
and capital budgets.
12. Establish procedures to enable the Board to function independently of
management.
The Boards of Ultima have functioned, and are of the view that they can
continue to function, independently of management. The Chairman of each
of the Boards of Ultima, Mr. Marshall Williams, is not a member of
management and is an "outside" and "unrelated" director. The Chairman
is responsible for ensuring that the directors discharge their
responsibilities effectively.
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The Boards of Ultima and any Committee of the Boards of Ultima can meet
without management whenever appropriate or deemed necessary.
13. Establish an Audit Committee with a specifically defined mandate (all
members should be non-management directors).
The Ultima Board of Directors has established an Audit Committee. The
Ultima Board of Directors has determined that all members of this
committee are financially literate and that at least one member has
accounting or related financial expertise. The Audit Committee
communicates directly with Ultima's external auditors, both with
management and independent of management, and is responsible for
monitoring the preparation and audit of Ultima's financial statements
and the establishment of appropriate internal controls. The Audit
Committee and the Ultima Board of Directors has adopted "Terms of
Reference" which outlines the purpose of the Audit Committee, its
composition, procedures, organization, role and responsibilities.
14. Implement a system to enable individual directors to engage outside
advisors, at Corporation's expense.
The Boards of Ultima support the engagement of separate professional
advisors (e.g., financial, legal or other advisors) by an individual
director or a Committee of directors, at the expense of Ultima, Ultima
Co, AcquireCo or Ultima Energy, as the case may be, in appropriate
circumstances.
PART IV - ADDITIONAL INFORMATION
REGARDING PETROFUND ENERGY TRUST
General
Information with respect to Petrofund and its business, operations and
affairs are included in the following (which are attached as Appendix "B" and
form an integral part of this Information Circular):
1. Petrofund Energy Trust Renewal Annual Information Form dated March 15,
2004 for the year ended December 31, 2003 (the "Petrofund AIF");
2. Petrofund Energy Trust Management's Discussion and Analysis for the
year ended December 31, 2003 compared to the year ended December 31,
2002;
3. Petrofund Energy Trust comparative audited consolidated financial
statements as at December 31, 2003 and 2002 and for the years ended
December 31, 2003, 2002 and 2001 and the auditors' reports thereon; and
4. additional information relating to Petrofund.
Petrofund's syndicated facility of $240 million as described in the
Petrofund AIF under "Selected Financial and Operating Information - Credit
Facility" has been extended to May 28, 2005, unless further extended.
Distributions
The following cash distributions per Petrofund Unit have been made to
Petrofund Unitholders during the periods indicated below:
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2000 2001 2002 2003 2004
---------------------------------------------
First Quarter.................. $0.90 $1.26 $0.43 $0.48 $0.48
Second Quarter................. 0.99 1.32 0.41 0.53 $0.48(1)
Third Quarter.................. 1.02 0.93 0.42 0.54 N/A
Fourth Quarter................. 1.08 0.73 0.45 0.54 N/A
Total Annual................... $3.99 $4.24 $1.71 $2.09 $0.96
Note:
(1) A distribution of $0.16 per Petrofund Unit was paid to Petrofund
Unitholders of record on April 30, 2004. Based on current commodity
prices, Petrofund expects to maintain the $0.16 distribution per
Petrofund Unit for both the May and June distribution periods, which
distributions reflect Petrofund's current expectation with regard to
its near term performance and are subject to change based on actual
market conditions.
Cash distributions by Petrofund are payable on the last business day of
each month to Petrofund Unitholders of record on the tenth business day
preceding the end of such month. Former Ultima Unitholders who are Petrofund
Unitholders of record on June 16, 2004 (and any subsequent record date for
distributions to Petrofund Unitholders) will be entitled to receive
distributions from Petrofund following the Closing Date of the Merger without
any further action required on their part provided they have exchanged their
certificates representing Ultima Units for Petrofund Units on or prior to the
sixth anniversary of the Closing Date.
Distributions may vary significantly from period to period based on,
among other things, commodity prices and production levels of Petrofund. The
acquisition and development activity of Petrofund will also impact the level of
distributions. Petrofund has historically been engaged in an active program of
acquiring producing oil and gas properties with a view to replacing exploited
reserves and increasing production per Petrofund Unit in order to enhance
distributions; however, there can be no assurance that such acquisitions will
continue in the foreseeable future. Distributions for any given period will also
vary to the extent cash flow is utilized for debt repayment, reserved for
purposes of funding future operating costs, capital expenditures, reclamation
obligations, general and administrative costs or debt service charges or to the
extent such reserve is utilized in a particular period. Distributions per
Petrofund Unit will also vary based on the number of outstanding Petrofund
Units. There is no minimum distribution payable in any period.
The twelve month trailing distributions (including April, 2004) are
$2.08 per Petrofund Unit. Average prices received by Petrofund for the twelve
months ended February 29, 2004 were $37.94 per Bbl before hedging ($36.79 per
Bbl net of hedging) for crude oil, $6.45 per Mcf before hedging ($6.33 per Mcf
net of hedging) for natural gas and $33.67 per Bbl for NGL's.
The Petrofund Board of Directors on behalf of Petrofund reviews the
distribution policy from time to time. The current distribution policy allows
for the payment into a reserve of a portion of the amounts that would otherwise
be available for distribution to provide greater stability to distributions.
Over a twelve month period, Petrofund intends to distribute the majority of its
cash flow.
Trust Unit Price Range and Trading Volumes
The Petrofund Units are listed on the TSX and the AMEX. The following
table shows the high, low and closing prices and volume of trading of the
Petrofund Units on the TSX and the AMEX, as reported by such exchanges, for the
periods indicated.
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Toronto Stock Exchange American Stock Exchange
----------------------------------- ----------------------------------------
Unit Price Range ($) Unit Price Range (U.S.$)
------------------------ ---------------------------
Trading Trading
High Low Close Volume High Low Close Volume
------- ------- -------- --------- -------- -------- --------- -----------
2002
First Quarter................................ 14.01 11.42 13.17 8,253,120 8.86 7.19 8.32 3,320,300
Second Quarter............................... 13.55 11.50 12.06 6,382,746 8.55 7.57 8.04 3,948,800
Third Quarter................................ 12.70 10.01 11.80 4,617,459 8.63 6.20 7.42 4,023,700
Fourth Quarter............................... 11.95 10.10 10.85 6,566,922 7.50 6.45 6.90 5,128,300
2003
First Quarter................................ 12.54 10.30 11.47 6,536,345 8.55 6.89 7.85 8,496,500
Second Quarter............................... 13.59 10.69 13.15 15,649,323 10.06 7.36 9.78 19,558,300
Third Quarter................................ 16.70 13.01 16.00 16,214,493 12.24 9.51 11.90 28,347,400
Fourth Quarter............................... 19.15 15.89 18.79 14,730,252 14.73 11.81 14.46 27,898,080
2004
January...................................... 19.24 14.56 16.80 4,339,354 15.01 10.95 12.70 18,638,100
February..................................... 17.50 14.67 17.45 4,477,979 13.13 11.03 13.05 12,636,800
March........................................ 18.00 15.12 17.35 4,259,182 13.65 11.75 13.22 9,262,200
April (through April 29)..................... 18.08 16.36 16.42 3,282,500 13.54 11.95 11.95 6,624,300
On March 26, 2004, the last trading day prior to the announcement of
the Merger, the closing price of the Petrofund Units on the TSX was $17.14 and
on the AMEX was U.S.$12.97. On April 29, 2004, the closing price of the
Petrofund Units on the TSX was $16.42 and on the AMEX was U.S.$11.95.
Information Relating to Arthur Andersen LLP
In connection with the filing of this Information Circular, Ultima
would normally be required to obtain written consent from Arthur Andersen LLP,
independent auditors, to the filing of their audit report on the consolidated
financial statements of Petrofund for the year ended December 31, 2001 and to
file that consent with this Information Circular. In addition, Petrofund would
normally be required to obtain written consent from Arthur Andersen LLP, to the
filing of their audit report on the consolidated financial statements of
Petrofund for the year ended December 31, 2001 and to file that consent with the
SEC as an exhibit to the registration statement. However, on June 3, 2002,
Arthur Andersen LLP, which was an Ontario limited liability partnership,
separate from Arthur Andersen LLP in the United States, ceased to practice
public accounting in Canada, including at its Calgary, Alberta, Canada office,
from which Petrofund was primarily serviced. As a consequence, representatives
of Arthur Andersen LLP are no longer available to provide consent in connection
with the filing of this Information Circular with the Canadian securities
commissions and similar regulatory authorities and the filing of the
registration statement with the SEC. Ultima is filing this Information Circular
in Canada in reliance on a staff notice of the Canadian Securities
Administrators and Petrofund has filed the registration statement with the SEC
in reliance on an SEC rule, each of which relieves an issuer from the obligation
to obtain the consent of Arthur Andersen LLP in certain cases.
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CONSENTS
Consent of Bennett Jones LLP
TO: The Trustee of Ultima Energy Trust
The Board of Directors of Ultima Ventures Corp.
The securities commission or similar regulatory authority in each of
the provinces of Canada
We hereby consent to the inclusion of and reference to our opinion
contained under "Canadian Federal Income Tax Considerations" in the Proxy
Statement and Information Circular of Ultima Energy Trust dated April 30, 2004
with respect to the proposed merger of Petrofund Energy Trust and Ultima Energy
Trust.
Calgary, Alberta (Signed) BENNETT JONES LLP
April 30, 2004 Bennett Jones LLP
Consent of Gilbert Laustsen Jung Associates Ltd.
TO: The Trustee of Ultima Energy Trust
The Board of Directors of Ultima Ventures Corp.
The securities commission or similar regulatory authority in each of
the provinces of Canada
We hereby consent to the inclusion of and reference to our reports in
the Proxy Statement and Information Circular of Ultima Energy Trust dated April
30, 2004 with respect to the proposed merger of Petrofund Energy Trust and
Ultima Energy Trust.
Calgary, Alberta (Signed) Dana B. Laustsen, P. Eng.
April 30, 2004 Gilbert Laustsen Jung Associates Ltd.
Consent of McDaniel & Associates Consultants Ltd.
TO: The Trustee of Ultima Energy Trust
The Board of Directors of Ultima Ventures Corp.
The securities commission or similar regulatory authority in each of
the provinces of Canada
We hereby consent to the inclusion of and reference to our reports in
the Proxy Statement and Information Circular of Ultima Energy Trust dated April
30, 2004 with respect to the proposed merger of Petrofund Energy Trust and
Ultima Energy Trust.
Calgary, Alberta (Signed) P.A. Welch, P. Eng.
April 30, 2004 McDaniel & Associates Consultants Ltd.
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Consent of Collins Barrow Calgary LLP
TO: The Trustee of Ultima Energy Trust
The Board of Directors of Ultima Ventures Corp.
The securities commission or similar regulatory authority in each of
the provinces of Canada
We refer to the Proxy Statement and Information Circular of Ultima
Energy Trust (the "Circular") dated April 30, 2004 with respect to the proposed
merger of Petrofund Energy Trust and Ultima Energy Trust.
We consent to the inclusion in the Circular of our report to the
Directors of Trioco Resources Inc. ("Trioco") on the balance sheets of Trioco as
at December 31, 2002 and 2001 and the statements of income and retained earnings
and cashflow for each of the years then ended. Our report is dated March 31,
2003 (except for Note 9 which is dated June 20, 2003).
Calgary, Alberta (Signed) Collins Barrow Calgary LLP
April 30, 2004 Chartered Accountants
Consent of CIBC World Markets Inc.
TO: The Trustee of Ultima Energy Trust
The Board of Directors of Ultima Ventures Corp.
The securities commission or similar regulatory authority in each of
the provinces of Canada
Dear Sirs:
We refer to the Proxy Statement and Information Circular of Ultima
Energy Trust (the "Circular") dated April 30, 2004 with respect to the proposed
merger of Petrofund Energy Trust and Ultima Energy Trust.
We consent to the inclusion in, and the references contained in, the
Circular of our fairness opinion dated April 30, 2004 to the Board of Directors
of Ultima Ventures Corp. with respect to the proposed merger of Petrofund Energy
Trust and Ultima Energy Trust.
Calgary, Alberta (Signed) CIBC WORLD MARKETS INC.
April 30, 2004 CIBC World Markets Inc.
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Consent of Deloitte & Touche LLP
We have read the Proxy Statement and Information Circular of Ultima
Energy Trust (the "Circular") dated April 30, 2004 with respect to the proposed
transaction between Petrofund Energy Trust ("Petrofund") and Ultima Energy Trust
("Ultima"). We have complied with Canadian generally accepted standards for an
auditor's involvement with offering documents.
We consent to the use in the Circular of our report dated February 6,
2004 (except as to Note 19 which is as of April 30, 2004) to the Board of
Directors of Petrofund Corp. on the following financial statements:
o Consolidated balance sheet of Petrofund as at December 31, 2003
and 2002; and
o Consolidated statements of operations, unitholders' equity and
cash flows of Petrofund for the years ended December 31, 2003 and
2002.
We consent to the use in the Circular of our report dated February 24,
2004 (except as to Notes 14 and 15 which are as of April 30, 2004) to the Board
of Directors of Ultima Ventures Corp. and Ultima Acquisitions Corp. on the
following financial statements:
o Consolidated balance sheet of Ultima as at December 31, 2003 and
2002; and
o Consolidated statements of income and deficit and cash flows of
Ultima for the years ended December 31, 2003 and 2002.
Calgary, Alberta (Signed) DELOITTE & TOUCHE LLP
April 30, 2004 Chartered Accountants
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Disclosure in Lieu of Consent of Arthur Andersen LLP
The consolidated financial statements of Petrofund for the year ended
December 31, 2001 were audited by Arthur Andersen LLP. Arthur Andersen LLP
expressed an opinion without reservation on those financial statements in their
report dated February 14, 2002 which is attached as part of Appendix "B" of this
Information Circular. Neither Ultima nor Petrofund obtained the consent of
Arthur Andersen LLP to the use of their auditors' report. The consent of Arthur
Andersen LLP was not obtained because, on June 3, 2002, Arthur Andersen LLP
ceased to practice public accounting in Canada. See "Additional Information
Regarding Petrofund Energy Trust - Information Relating to Arthur Andersen LLP".
INTEREST OF INSIDERS IN MATERIAL TRANSACTIONS
Except as disclosed in this Information Circular, neither the Manager,
nor any director or officer of Ultima Co, Ultima Energy, the Manager or
AcquireCo, nor any other insider of Ultima, Ultima Co, Ultima Energy or
AcquireCo, nor any proposed nominee for election as a director of Ultima Co or
AcquireCo, nor any associate or affiliate of any one of them, has or has had, at
any time since January 1, 2003, the beginning of the most recently completed
financial year of Ultima, any material interest, direct or indirect, in any
transaction or proposed transaction that has materially affected or would
materially affect Ultima, Ventures Trust, Ultima Co, Ultima Energy, the Manager
or AcquireCo.
INDEBTEDNESS OF DIRECTORS,
EXECUTIVE OFFICERS AND SENIOR OFFICERS
None of the directors, executive officers or senior officers of Ultima
Co, AcquireCo, Ultima Energy or the Manager, nor any proposed nominee for
election as a director, nor any associate or affiliate of any one of them, is or
has been indebted, directly or indirectly, to Ultima, Ventures Trust, Ultima Co,
AcquireCo, Ultima Energy or the Manager at any time since January 1, 2003, the
beginning of the most recently completed financial year of Ultima.
OTHER MATTERS
As of the date of this Information Circular, neither the Ultima Board
of Directors nor management of Ultima Co knows of any amendment, variation or
other matter to come before the Meeting other than the matters referred to in
the Notice of Annual and Special Meeting. If any other matter properly comes
before the Meeting, however, the accompanying proxies will be voted on such
matter in accordance with the best judgment of the person or persons voting the
proxies.
QUESTIONS AND OTHER ASSISTANCE
If you have any questions about the information contained in this
Information Circular or require assistance in completing your form of proxy
(printed on blue paper) or letter of transmittal (printed on yellow paper),
please contact Georgeson Shareholder, the Corporation's proxy solicitation
agent, at:
66 Wellington Street West
TD Tower - Suite 5210
Toronto Dominion Centre
P.O. Box 240
Toronto, Ontario, Canada M5K 1J3
Toll Free Number in Canada and U.S.A.:
1-866-800-4722
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APPROVAL AND CERTIFICATION
The contents and sending of this Information Circular have been
approved by the Ultima Board of Directors, for and on behalf of Ultima.
The foregoing contains no untrue statement of a material fact and does
not omit to state a material fact that is required to be stated or that is
necessary to make a statement not misleading in the light of the circumstances
in which it was made.
DATED at Calgary, Alberta this 30th day of April, 2004.
ULTIMA ENERGY TRUST
by ULTIMA VENTURES CORP.
"S. Brian Gieni" "Kenneth G. Pinsky"
S. Brian Gieni Kenneth G. Pinsky
President and Chief Executive Officer Chief Financial Officer
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APPENDIX "A"
TEXT OF SPECIAL RESOLUTION OF UNITHOLDERS
OF ULTIMA ENERGY TRUST
BE IT RESOLVED AS A SPECIAL RESOLUTION THAT:
1. the Special Distribution and Merger of Petrofund and Ultima as
described in the Information Circular which accompanies the Notice of
Annual and Special Meeting dated April 30, 2004 (the "Information
Circular"), and upon the terms and conditions set out in the
Combination Agreement, be and is hereby authorized and approved and, in
order to give effect thereto, the following events are hereby
authorized and shall occur and be deemed to occur in the sequence set
out below without further act or formality:
(a) the Ultima Trust Indenture and other constating documents of
the Ultima Parties shall be amended to the extent necessary to
permit the completion of the transactions contemplated in the
Combination Agreement, including, without limitation, to
provide for the right of Ultima to declare and pay the Special
Distribution, distribute the rights pursuant to the Unitholder
Indemnity Agreement and redeem any or all outstanding Ultima
Units (other than the Ultima Remaining Unit) in exchange for
consideration consisting of Petrofund Units, without further
notice to, agreement of, or act by, any holder of Ultima
Units;
(b) all of the Ultima Assets shall be transferred to Petrofund in
exchange for the assumption by Petrofund of all of the Assumed
Liabilities and for the issuance by Petrofund of the Petrofund
Payment Units to Ultima, with the number of such Petrofund
Payment Units to be based upon the Exchange Ratio multiplied
by the number of Ultima Units issued and outstanding as of the
Closing Date, all as described in the Information Circular;
(c) Petrofund shall subscribe for the Ultima Payment Unit upon
payment of $10.00 and Ultima shall issue to Petrofund the
Ultima Remaining Unit; and
(d) the Ultima Units (other than the Ultima Remaining Unit) shall
be redeemed and, upon the redemption of the Ultima Units
(other than the Ultima Remaining Unit), the Petrofund Units
which are issuable as contemplated by paragraph (b) above
shall be distributed to Ultima Unitholders (other than
Petrofund) on a proportionate basis in accordance with the
Exchange Ratio, all as described in the Information Circular;
2. the directors of Ultima Co and any officer of Ultima Co be and is
hereby authorized and directed to execute on behalf of Ultima, Ultima
Co, AcquireCo, Ventures Trust, Ultima Energy or the Manager and to
deliver and to cause and be delivered, all such documents, agreements
and instruments and to do or cause to be done all such other acts and
things as they shall determine to be necessary or desirable in order to
carry out the intent of the foregoing resolutions and the matters
authorized thereby, such determination to be conclusively evidenced by
the execution and delivery of such document, agreement or instrument or
the doing of any such act or thing;
3. the Ultima Board of Directors is authorized to revoke this resolution
for any reason whatsoever in its sole and absolute discretion, without
further approval of the Ultima Unitholders at any time prior to the
completion of the Merger; and
4. all capitalized terms not otherwise defined in this Ultima Special
Resolution have the meanings ascribed thereto in the Information
Circular.
APPENDIX "B"
INFORMATION RELATING TO PETROFUND ENERGY TRUST
TABLE OF CONTENTS
Page
----
1. Renewal Annual Information Form dated March 15, 2004 for the
year ended December 31, 2003............................................ B-o
2. Management's Discussion and Analysis for the year ended
December 31, 2003 compared to year ended December 31, 2002.............. B-o
3. Comparative Audited Consolidated Financial Statements as at
and for the years ended December 31, 2003 and 2002, together
with the auditors' report thereon....................................... B-o
4. Additional Information.................................................. B-o
PETROFUND ENERGY TRUST
RENEWAL ANNUAL INFORMATION FORM
FOR THE YEAR ENDED DECEMBER 31, 2003
March 15, 2004
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TABLE OF CONTENTS
INFORMATION PREPARED BY PETROFUND CORP. .......................................5
FORWARD-LOOKING STATEMENTS.....................................................5
DOLLAR AMOUNTS.................................................................5
GLOSSARY OF TERMS..............................................................6
THE TRUST.................................................................9
MANAGEMENT OF THE TRUST..................................................10
STRATEGY.................................................................11
ACQUISITION CRITERIA.....................................................12
KEY FACTORS FOR SUCCESS..................................................13
GENERAL DEVELOPMENT OF THE BUSINESS OF THE TRUST..............................13
FINANCINGS...............................................................13
BUSINESS AND PROPERTIES.......................................................16
REPORT OF MANAGEMENT AND DIRECTORS ON RESERVES DATA AND OTHER INFORMATION.....20
REPORT ON RESERVES DATA BY....................................................21
INDEPENDENT QUALIFIED RESERVES................................................21
EVALUATOR OR AUDITOR..........................................................21
STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION..................23
DISCLOSURE OF RESERVES DATA..............................................23
RESERVES DATA (CONSTANT PRICES AND COSTS)................................24
RESERVES DATA (FORECAST PRICES AND COSTS)................................26
DEFINITIONS AND OTHER NOTES..............................................27
PRICING ASSUMPTIONS......................................................32
RECONCILIATIONS OF CHANGES IN RESERVES AND FUTURE NET REVENUE ...........33
ADDITIONAL INFORMATION RELATING TO RESERVES DATA.........................34
UNDEVELOPED RESERVES.....................................................34
SIGNIFICANT FACTORS OR UNCERTAINTIES.....................................34
FUTURE DEVELOPMENT COSTS.................................................34
OTHER OIL AND GAS INFORMATION............................................35
OIL AND GAS WELLS........................................................35
PROPERTIES WITH NO ATTRIBUTABLE RESERVES.................................35
ADDITIONAL INFORMATION CONCERNING ABANDONMENT AND RECLAMATION COSTS......36
FORWARD CONTRACTS........................................................36
TAX HORIZON..............................................................36
CAPITAL EXPENDITURES.....................................................36
EXPLORATION AND DEVELOPMENT ACTIVITIES...................................36
PRODUCTION ESTIMATES.....................................................37
PRODUCTION HISTORY.......................................................37
SELECTED FINANCIAL AND OPERATING INFORMATION..................................38
CONSOLIDATED FINANCIAL INFORMATION.......................................38
SENSITIVITY ANALYSIS.....................................................38
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DISTRIBUTION POLICY......................................................39
DISTRIBUTIONS............................................................39
CREDIT FACILITY..........................................................40
OUTLOOK FOR NEXT YEAR....................................................41
ENVIRONMENT, HEALTH AND SAFETY................................................41
MANAGING LIABILITIES.....................................................42
STEWARDSHIP..............................................................42
CORPORATE CITIZENSHIP....................................................42
CORPORATE GOVERNANCE..........................................................43
INDEPENDENCE OF THE BOARD................................................43
COMMITTEES...............................................................43
GOVERNANCE COMMITTEE.....................................................44
HUMAN RESOURCES AND COMPENSATION COMMITTEE...............................44
RESERVES AUDIT COMMITTEE.................................................44
AUDIT COMMITTEE..........................................................44
MANAGEMENT'S DISCUSSION AND ANALYSIS..........................................46
RISK FACTORS..................................................................46
OIL AND NATURAL GAS PRICES...............................................46
FOREIGN CURRENCY EXCHANGE RATES AND INTEREST RATES.......................47
OPERATIONS...............................................................47
COMPETITION..............................................................47
ENVIRONMENTAL CONCERNS...................................................48
RESERVES.................................................................48
DEPLETION OF RESERVES....................................................49
MARKETABILITY OF PRODUCTION..............................................49
ASSESSMENTS OF VALUE OF ACQUISITIONS.....................................49
RELIANCE ON THIRD PARTY OPERATORS........................................50
ENFORCEMENT OF OPERATING AGREEMENTS......................................50
BORROWING................................................................50
DELAYS IN DISTRIBUTIONS..................................................50
UNFORESEEN TITLE DEFECTS.................................................51
ACCOUNTING WRITE-DOWNS AS A RESULT OF GAAP...............................51
NATURE OF TRUST UNITS....................................................51
TRADING PRICE OF TRUST UNITS.............................................51
RELIANCE ON PETROFUND CORP. AND OTHERS...................................52
UNITHOLDER LIMITED LIABILITY.............................................52
RETRACTION RIGHT.........................................................52
FUTURE DILUTION..........................................................52
CHANGES IN LEGISLATION...................................................52
CHANGES IN THE TRUST'S STATUS UNDER TAX LAWS.............................53
GOVERNANCE OF THE TRUST AND PC................................................53
TRUST INDENTURE..........................................................53
PC UNANIMOUS SHAREHOLDER AGREEMENT.......................................57
ROYALTY AGREEMENT........................................................57
MANAGEMENT AGREEMENT.....................................................58
UNITHOLDER PROTECTION RIGHTS PLAN.............................................59
DISTRIBUTION REINVESTMENT AND UNIT PURCHASE PLAN .............................60
DIRECTORS AND OFFICERS........................................................60
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OWNERSHIP OF TRUST UNITS BY DIRECTORS AND OFFICERS.......................63
ESCROWED SECURITIES...........................................................63
MARKET FOR SECURITIES.........................................................63
CONFLICTS OF INTEREST.........................................................63
ADDITIONAL INFORMATION........................................................63
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INFORMATION PREPARED BY PETROFUND CORP.
The information contained in this annual information form has been
prepared by Petrofund Corp., who manages the Trust.
FORWARD-LOOKING STATEMENTS
Some of the statements contained herein including, without limitation,
financial and business prospects and financial outlooks, may be forward-looking
statements which reflect management's expectations regarding future plans and
intentions, growth, results of operations, performance and business prospects
and opportunities. Words such as "may", "will" "should", "could", "anticipate",
"believe", "expect", "intend", "plan", "potential", "continue" and similar
expressions have been used to identify these forward-looking statements. These
statements reflect management's current beliefs and are based on information
currently available to management. Forward-looking statements involve
significant risk and uncertainties. A number of factors could cause actual
results to differ materially from the results discussed in the forward-looking
statements including, but not limited to, changes in general economic and market
conditions and other risk factors. Although the forward-looking statements
contained herein are based upon what management believes to be reasonable
assumptions, we cannot assure that actual results will be consistent with these
forward looking statements. Investors should not place undue reliance on
forward-looking statements. These forward-looking statements are made as of the
date hereof and we assume no obligation to update or revise them to reflect new
events or circumstances.
Forward-looking statements and other information contained herein
concerning the oil and gas industry and our general expectations concerning this
industry is based on estimates prepared by us using data from publicly available
industry sources as well as from reserve reports, market research and industry
analysis and on assumptions based on data and knowledge of this industry which
we believe to be reasonable. However, this data is inherently imprecise,
although generally indicative of relative market positions, market shares and
performance characteristics. While we are not aware of any misstatements
regarding any industry data presented herein, the industry involves risks and
uncertainties and is subject to change based on various factors.
DOLLAR AMOUNTS
Unless otherwise specified, all dollar amounts set out in this annual
information form are in Canadian dollars.
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GLOSSARY OF TERMS
The following terms used herein have the meanings set out below:
AECO: The regional pricing hub for natural gas located
at the storage facilities of Alberta Energy
Company near Medicine Hat, Alberta.
Aggregate Equivalent Vote With respect to any matter, proposition or
Amount: question on which Unitholders are entitled to
vote, consent or otherwise act, the number of
votes that the holder of a Special Voting Unit
would be entitled to had the holder exchanged
all of the Exchangeable Shares held by the
holder for Petrofund Units immediately prior to
the record date set for any such meeting.
bbl: Barrel.
bcf: Billions of cubic feet.
Board or Board of The board of directors of PC.
Directors:
boe: Barrels of oil equivalent, using a conversion
factor of 6 mcf of gas being equivalent to one
bbl of oil and one bbl of NGLs being equivalent
to one bbl of oil.
boepd: Barrels of oil equivalent per day.
bpd: Barrels of oil or NGLs per day.
Cash Retraction Notice: A notice to redeem PC Exchangeable Shares
exercisable for a period of 5 business days from
the date of expiry of the subject Dividend
Period.
Current Market Price: In respect of a Unit on any date, the weighted
average trading price of a Unit on the TSX for
the 10 trading days preceding that date.
Distribution Payment Date: Each date from and after the effective date on
which a distribution is paid to Unitholders.
Distribution Record Date: In respect of any distribution, the day on which
Unitholders are identified for purposes of
determining entitlement to such distribution.
Dividend Period: A period within two business days of a
Distribution Payment Date.
Drip Price: In respect of a Unit on any Valuation Date, the
most recently applicable price at which a holder
of a Unit is entitled to purchase a Unit in
respect of the Distribution to which the subject
Valuation Date relates pursuant to any
distribution re-investment plan which Petrofund
may have in effect on such Valuation Date and
which is available to the holders of Units
generally.
Established Reserves: Company interest reserves (proved plus 50%
probable) prior to royalties that conform to
National Policy Statement 2-B.
Exchange Ratio: At any time and in respect of each PC
Exchangeable Share, shall initially be equal to
one, and provided that PC shall not have
declared a dividend in respect of the subject
Dividend Period, shall be cumulatively increased
on the expiry date of each Dividend Period by an
amount equal to the (i) fraction having as its
numerator the Per Share Dividend Amount relating
to the subject expired Dividend Period, and
having as its denominator the Current Market
Price on the Valuation Date, or (ii) in the
event that: (a) as at the subject Valuation
Date, the Trust has in place a distribution
re-investment plan which is available to the
holders of Units generally, and (b) the holder
has not delivered a Cash
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Retraction Notice in respect of the Distribution
to which the expired Dividend Period relates
within the time period provided for, the
fraction having as its numerator the Per Share
Dividend Amount relating to the subject expired
Dividend Period, and having as its denominator
the Drip Price in effect as at the Valuation
Date.
gj: Gigajoule.
GLJ: Gilbert Laustsen Jung Associates Ltd.,
independent oil and gas reservoir engineers of
Calgary, Alberta.
GLJ Report: The report prepared by GLJ dated February 17
2004 with respect to the petroleum, natural
gas and NGL reserves of PC effective as
at December 31, 2003.
Internalization The transaction approved at the annual and
Transaction: special meeting of Unitholders held on April 16,
2003 under which management of the Trust was
internalized through the acquisition by PC of
all of the issued and outstanding shares of NCEP
Management and the consequent elimination of all
management, acquisition and disposition fees
payable to NCEP Management.
Management Agreement: The amended and restated management, advisory
and administration agreement made as of January
1, 2002 among PC, the Trust and NCEP Management.
mbbls: Thousands of barrels.
mboe: Thousands of barrels of oil equivalent.
mcf: Thousands of cubic feet.
mcfe: Thousands of cubic feet of natural gas
equivalent, using a conversion factor of one
barrel of oil and one barrel of NGL's being
equivalent to 6 mcf of gas.
mcfepd: Thousands of cubic feet of natural gas
equivalent per day.
mcfpd: Thousands of cubic feet per day.
mlt: Thousand long tons.
mmboe: Millions of barrels of oil equivalent.
MMBtu: Millions of British Thermal Units
mmcf: Millions of cubic feet.
mmcfpd: Millions of cubic feet per day.
M$: Thousands of dollars.
MM$: Millions of dollars.
NCEP Management: NCE Petrofund Management Corp., the previous
manager.
NCE Services or NMSI: NCE Management Services Inc.
netback: The amount received from the sale of a barrel of
oil or barrel of oil equivalent after deduction
of operating costs and royalty payments.
NGL or NGLs: Natural gas liquids.
PC: Petrofund Corp.
PC Exchangeable Share The rights, privileges and conditions attaching
Provisions: to the PC Exchangeable Shares set forth in the
Articles of PC.
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PC Exchangeable Shares: Non voting exchangeable shares in the capital of
PC.
PC Support Voting and The agreement dated April 29, 2003 between PC,
Exchange Agreement: the Trust, 1518274 Ontario Limited
("Exchangeco."), and Petro Assets Inc. ("Petro
Assets") whereby PC will take certain actions
and make certain payments and deliveries
necessary to ensure that the Trust and
Exchangeco. will be able to make certain
payments and to deliver or cause to be delivered
Units in satisfaction of the obligations of the
Trust and Exchangeco under the PC Exchangeable
Share Provisions and the Unanimous Shareholders
Agreement.
Per Share Dividend A distribution relating to the subject
Amount: Distribution Payment Date multiplied by the
Exchange Ratio.
Petro Assets: Petro Assets Inc.
Petrofund or the Trust: Petrofund Energy Trust.
Properties: The interests, including working interests and
unit interests, in petroleum and natural gas
rights held by PC.
Redemption Date: The date which is 60 days after the date of
delivery of a Redemption Notice.
Redemption Price: A price per PC Exchangeable Share equal to the
amount determined by multiplying the Exchange
Ratio on the last business day prior to the
applicable Redemption Date by the current market
price on the last Business Day prior to such
Redemption Date.
Retracted Shares: Means the number of Exchangeable Shares redeemed
in accordance with a Cash Retraction Notice.
Retraction Date: The date that is 5 Business days after the date
on which PC receives a retraction request in
respect of the Retracted Shares.
Royalty Agreement: The amended and restated royalty agreement dated
as of April 16, 2003 between PC and the Trust.
Special Resolution: A resolution approved in writing by Unitholders
holding not less than 66 2/3% of the outstanding
Trust Units or passed by a majority of not less
than 66 2/3% of the votes cast, either in person
or by proxy, at a meeting of the Unitholders
called for the purpose of approving such
resolution.
Tax Act: Income Tax Act (Canada), as amended.
TSX: Toronto Stock Exchange.
Trustee: Computershare Trust Company of Canada, as
trustee of the Trust.
Trust Indenture: The amended and restated trust indenture made as
of April 16, 2003 between PC and the Trustee.
Trust Unit or Unit: A trust unit created pursuant to the Trust
Indenture and representing a fractional
undivided interest in the Trust.
Unanimous Shareholder The unanimous shareholder agreement made as of
Agreement: November 1, 2000 among PC, the Trust and NCEP
Management.
Unitholder: A holder from time to time of Trust Units.
Valuation Date: The first Business Day following the
Distribution Record Date in respect of the
Distribution to which the expired Dividend
Period relates.
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PETROFUND ENERGY TRUST
RENEWAL ANNUAL INFORMATION FORM
FOR THE YEAR ENDED DECEMBER 31, 2003
DATED March 15, 2004
PETROFUND ENERGY TRUST
The Trust
The Trust is an open-ended investment trust created under the laws of
the Province of Ontario on December 18, 1988 under the name "NCE Petrofund I".
Active operations commenced March 3, 1989. On July 4, 1996, the name of the
Trust was changed to "NCE Petrofund" and on November 1, 2003 the name was
changed to its present name of "Petrofund Energy Trust". Effective September 7,
2001, the Trustee became the trustee of the Trust. The Trust is currently
governed by the Trust Indenture.
The executive office was relocated from 130 King Street West, Suite
2850, Toronto, Ontario, M5X 1A4 in conjunction with the internalization of
management. The executive office, head office and operations of the Trust are
now located at Suite 600, 444 - 7th Avenue S.W., Calgary, Alberta, T2P 0X8.
The Trust's primary source of income is from 99% net royalty interests
granted by PC, its wholly-owned subsidiary. PC is a corporation incorporated
under the laws of Alberta. PC acquires, manages and disposes of petroleum and
natural gas rights and royalties and related property rights and interests
located primarily in western Canada. In addition, PC may acquire royalties or
other property interests or securities of other resource issuers. The Trust may
also purchase directly or indirectly securities of oil and gas companies, oil
and gas properties and other related assets.
The following chart shows the structure of the Trust at the date
hereof:
UNITHOLDERS
|
| Trust Units
|
---------------
PETROFUND
---------------
|
99% Net Royalty Interests | 100% of Capital Stock
| |
| |
---------------
PETROFUND CORP.
---------------
|
| Working Interests
|
---------------
OIL AND GAS
PROPERTIES
---------------
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Each Trust Unit represents an equal undivided beneficial interest in
the assets of the Trust. Historically, the Trust's activities have been focused
on the acquisition of net royalties from PC. For each property for which a net
royalty is granted by PC, the Trust receives 99% of the revenue generated by the
property net of operating costs, management fees (prior to 2003), debt service
charges, general and administrative costs and certain other taxes and charges.
The Trust distributes to its Unitholders a majority of its cash flow in the form
of monthly distributions, part of which is on a tax-advantaged basis. Cash flow
includes royalty income and may include cash flow generated by properties and
interests not currently subject to the Trust's net royalty interests.
The Trust was initially formed as a closed-end royalty trust for the
purposes of acquiring royalty interests from PC. Effective February 2, 1999, the
Trust was converted to an open-ended investment trust. The Trust Indenture,
Royalty Agreement and related agreements were amended to: (i) permit the Trust
and PC to acquire, directly or indirectly, interests in resource issuers and/or
resource properties and other related assets; (ii) remove certain financing
restrictions applicable to the Trust and PC to permit the Trust and PC, subject
to certain limitations, to raise or issue capital in connection with, or to
finance, such acquisitions, either through the issuance of Trust Units or other
equity or debt securities of the Trust or PC or through borrowing; and (iii)
provide that Unitholders have the right to cause the Trust to redeem their Trust
Units in certain circumstances.
Effective November 1, 2000, the Trust acquired all of the issued and
outstanding shares of PC from a subsidiary of NCEP Management for nominal
consideration, resulting in PC becoming a wholly-owned direct subsidiary of the
Trust. This change simplified the structure of the Trust and related entities
and allows the Trust to present consolidated financial statements which fully
reflect the assets and liabilities of the Trust and PC.
In conjunction with PC becoming a wholly-owned subsidiary of the Trust,
the corporate governance of the Trust was changed so that the stewardship of the
Trust and PC was undertaken by the Board of Directors of PC.
Management of the Trust
On January 1, 1990 PC entered into the Management Agreement, under
which it retained the services of NCEP Management to identify, assess and assist
in the acquisition, disposition and ongoing management of the Trust's properties
and to administer its net royalties and other assets. Management of the Trust is
now carried out directly by directors, officers and other employees of PC, see
"Governance of the Trust and PC - Management Agreement" and "Internalization of
Management".
Employees and Consultants
As at December 31, 2003 PC had 90 office employees and 18 full time
consultants. PC also has 31 direct field employees and a number of contractors
to manage its field operations.
Internalization of Management
On March 10, 2003, the Trust entered into an agreement to internalize
its management structure such that NCEP Management, the then manager of the
Trust, became a wholly owned subsidiary of PC. Unitholder and regulatory
approval of the Internalization Transaction was received at the annual and
special meeting of Unitholders held on April 16, 2003. As a result of the
Internalization Transaction, all management, acquisition and disposition fees
payable to NCEP Management were eliminated effective January 1, 2003. The cost
of the Internalization Transaction was $30.9 million including $2.5 million of
transaction costs, all of which was expensed to the income statement. The
transaction was effected in the following manner:
o Prior to the closing, NCEP Management acquired NMSI (which
employed all of the Calgary-based personnel who provided services
to the Trust and PC on behalf of NCEP Management).
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o At the closing, PC purchased all of the issued shares of NCEP
Management from Petro Assets Inc. for $21.7 million. Petro Assets
Inc. is owned by the Driscoll Family Trust (a trust established
for the family of John F. Driscoll). John Driscoll was Chairman
and Chief Executive Officer of PC at closing.
o The purchase price for the shares of NCEP Management was
satisfied by the issuance of 1,939,147 PC Exchangeable Shares,
plus a cash amount per PC Exchangeable Share equal to the
distributions paid or payable per Trust Unit by the Trust to
Unitholders of record from and after January 1, 2003 up to and
including the closing date. Initially each PC Exchangeable Share
was exchangeable into one Trust Unit. The exchange rate is
adjusted from time to time to reflect distributions paid on each
Trust Unit after the closing date. Each PC Exchangeable Share was
initially ascribed a value of $12.1703, representing the weighted
average trading price of the Trust Units over the 10 trading
days, ending on March 4, 2003 on the TSX. For accounting purposes
the PC Exchangeable Shares were deemed to be issued at a value of
$11.20 per share being the average trading value of the Trust
Units for the last ten days prior to the closing date.
o At closing, PC paid $3.4 million in cash to fund the repayment of
indebtedness owing by NCEP Management. In addition, as part of
the Internalization Transaction NMSI paid certain senior
executives of NCEP Management $780,000 in cash and issued 100,244
Trust Units plus an amount per Trust Unit equal to the
distributions per Trust Unit paid to holders of record of Trust
Units during the period commencing on January 1, 2003 and ending
on the closing date.
Subsequent to the closing of the Internalization Transaction, the Trust
proceeded to consolidate all activities in PC's offices in Calgary, Alberta. To
ensure an orderly transition of the services then provided by NCEP Management
through its office in Toronto, Ontario, Sentry Select Capital Corp. ("Sentry")
entered into an agreement on closing, which was effective January 1, 2003, with
the Trust, PC and NCEP Management to provide certain of these services to the
Trust and PC at Sentry's cost until December 31, 2003, subject to a maximum cost
of $2 million. After December 31, 2003, Sentry no longer provides any services.
At closing Sentry was an affiliate of NCEP Management and is a company in which
John F. Driscoll owns a controlling interest.
As part of the agreement, all management fees and acquisition and disposition
fees were eliminated retroactive to January 1, 2003.
Strategy
The Trust's objective is to maximize cash flow for distribution to its
Unitholders. The Trust intends to execute its business strategy by:
o continuing to pursue selected acquisitions that meet its
portfolio acquisition criteria;
o continuing to develop its existing properties to enhance
production and increase reserves;
o maintaining a balanced portfolio of geographically and
geologically diversified oil and gas properties;
o controlling costs through efficient operation of existing and
acquired properties;
o maintaining a capital structure that provides flexibility in
accessing debt and capital markets;
o and managing commodity price risk when appropriate through
hedging agreements that will increase the level of predictability
in prices for its oil and gas production.
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Acquisition Criteria
The Royalty Agreement requires PC to comply with the
following criteria and procedures before purchasing a property:
o Properties will be acquired with the objective of providing
Unitholders with an average annual net yield after all costs but
before income taxes of at least 15% over the first five years
from the date of acquisition and at least a 15% internal rate of
return over the life of the reserves after all costs but before
income taxes.
o At least 70% of the purchase price of all gas and oil properties
must be represented by proved reserves.
o At least 50% of the properties purchased will be estimated to be
producing for 20 years following their acquisition, based on
independent engineering reports.
o Generally accepted industry practices and procedures will be
employed in investigating title to the properties.
o No property having an acquisition cost of $10 million or more
will be acquired unless a report has been obtained from an
independent engineering consultant.
o Where the acquisition price of a property has not been determined
by arm's length negotiations, the price will be no greater than
the fair market value of the property at the time of acquisition
as determined by an independent engineering consultant.
o The amount of anticipated future capital expenditures for a
property will not be significant and such expenditures will be of
the type which are intended to maintain, realize or improve
production from the properties.
In addition to the above, the Trust's properties, in aggregate, must be
geographically and geologically diversified. Not more than 25% of the asset
value of all the Trust's properties may be attributable to a single reservoir.
The Trust's properties will be located primarily in western Canada (namely,
British Columbia, Alberta, Saskatchewan and Manitoba). At the time of each
acquisition, after giving effect to the proposed acquisition, not more than 10%
of the asset value of the Trust's properties may be represented by properties
located outside of western Canada. All of the Trust's properties must be located
in Canada. Asset value is the fair market value of the property as estimated by
the Board of Directors based on the most recent independent engineering report
respecting such property. If there is a material change to such property, a new
report will be prepared and used to determine the fair market value of such
property.
The foregoing acquisition criteria apply only to the Trust's property
acquisitions. The foregoing criteria may only be amended by Special Resolution.
Although the Trust is not required to apply these criteria when it acquires oil
and gas companies, as a matter of policy, the Trust is generally guided by the
same criteria. In addition, the Trust Indenture requires that any such
acquisition will be subject to standard industry due diligence procedures and a
favourable valuation report.
In the event of a sale of a property, the Board of Directors must make
a determination as to whether the proceeds of the sale will be reinvested in
additional properties or assets or will be distributed to the Unitholders, in
each case after repayment of such portion of the outstanding indebtedness as PC
may determine. A sale involving more than 35% of the asset value of all
properties requires the approval of the Unitholders by Special Resolution.
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Key Factors for Success
The success of the Trust in meeting its objectives lies in management's
ability to positively influence three main factors:
1) Identify, pursue and acquire oil and gas properties and/or
companies at prices which meet the acquisition criteria
previously mentioned and add value to the Trust;
2) Cost effectively add or extend reserves with farmouts and
internal development and drilling; and,
3) Manage and contain costs.
PC's ability to achieve these three factors depends mainly on the
experience, knowledge, and capability of the management team. In addition to the
factors over which management has influence, there are numerous other factors
beyond management's control which will influence the success of the
organization. These other potential risks are identified in the Risk Factors
section of this document.
GENERAL DEVELOPMENT OF THE BUSINESS OF THE TRUST
Financings
The Trust was established in 1988 to raise funds for the purposes of
acquiring royalties from PC. On July 6, 2001, the Trust Units were consolidated
on a one-for-three basis. All relevant figures, including Trust Units
outstanding, net income per Trust Unit and distributions per Trust Unit, have
been restated to reflect this consolidation.
During the last three years, the Trust completed the following public
offerings of Trust Units:
Date Trust Units Price Gross Proceeds
April, 2001 13,600,000* $ 5.50* $ 74,800,000*
August, 2001 3,450,000 15.00 51,750,000
November, 2001 3,200,000 12.75 40,800,000
March, 2002 4,600,000 13.00 59,800,000
May, 2003 9,200,000 10.60 97,520,000
December, 2003 6,600,000 $16.20 $ 106,920,000
*Prior to the 3 for 1 consolidation of the units on July 6, 2001.
Acquisitions
2001
Apache Properties
Effective January 1, 2001, PC purchased a 50% interest in a diverse
group of oil and gas producing properties from a major oil and gas company for
$23.8 million. The acquisition added 3.7 mmboe of Established Reserves, at a
cost of $6.40 per boe, and 702 boepd of production. The reserves and production
were 57% gas.
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Strachan
On March 6, 2001, PC closed the purchase of an interest in a gas
producing property in Strachan, Alberta from a major Canadian oil and gas
producer. The purchase price was $9.5 million. The acquisition added
approximately 1.2 million boe of Established Reserves and 270 boepd of
production.
Magin Energy Inc.
In July 2001, PC completed the acquisition of Magin Energy Inc., a
company listed on the TSX. The purchase price consisted of $58.6 million in cash
and 8.5 million Trust Units. PC also assumed $43.7 million of debt, including
negative working capital, the outstanding bank loan and capital leases, and
incurred other transaction costs of $11.8 million (comprised principally of
brokers' fees, severance costs and an acquisition fee of $4.4 million paid to
NCEP Management) and received net stock option proceeds of $6.9 million. In
consideration for the delivery of such Trust Units, the Trust received
promissory notes of PC in the aggregate amount of $157.1 million. Magin Energy
was amalgamated into PC and a royalty was granted in the Magin Energy properties
in favour of the Trust. Cash flow from the Magin Energy properties is paid to
the Trust as royalty income and as payment on the promissory notes.
Magin Energy was a Canadian oil and gas exploration and production
company whose principal areas of operation were Alberta and Saskatchewan. Prior
to the completion of the acquisition of Magin Energy, Magin Energy sold its
interest in a property known as the Copton property.
As a result of the acquisition, PC acquired Established Reserves of 29
mmboe and production of 9,000 boepd at the time of the acquisition at an
effective purchase price of $9.17 per Established Reserves boe. The reserves and
production were 50% gas. The reserve life index for the Magin Energy properties
at December 31, 2000 was 7.5 years. Over 90% of the Magin Energy properties were
operated by Magin Energy, and are now operated by PC. The Magin Energy
properties are located in areas with year round road access and this, along with
the multiple geological zone potential, is expected to help keep development
costs at or below the average for the area. As a result of the Magin Energy
acquisition, PC also acquired undeveloped land of 345,080 net (460,287 gross)
acres.
Swan Hills
Effective November 1, 2001, PC acquired a 1.2% interest in the Swan
Hills Unit #1 along with other minor interests in the Swan Hills area from a
Large independent U.S. oil and gas company. The transaction closed on
February 26, 2002. The purchase price was $12.3 million. The acquisition added
approximately 2.5 million boe of Established Reserves and 400 boepd
of production.
On December 31, 2001, PC acquired a 1.4% interest in the Swan Hills
Unit #1 in north central Alberta from a large independent U.S. oil and gas
company for $7.5 million. The acquisition added approximately 2.2 million boe of
Established Reserves and 300 boepd of production.
2002
Central Alberta
Effective March 2002, PC acquired two gas properties and two oil
properties in Central Alberta for $40.2 million. Three of the properties are
unitized and one is operated. Net Established Reserves acquired were estimated
at 8.8 million boe and net production at date of acquisition was approximately
1,800 boepd consisting of 67% oil. The properties had a reserve life index in
excess of 13 years.
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NCE Energy Trust
On May 30, 2002, PC completed the acquisition of NCE Energy Trust, a
royalty trust listed on the TSX. The acquisition was completed through the
exchange of 0.2325 of a unit of PC for each unit of NCE Energy Trust. The total
price of the transaction was $140.1 million comprised of 7.6 million Trust Units
with an assigned value of $98.6 million, the assumption of $39.5 million of debt
and negative working capital, and transaction costs of $2.0 million. A non-cash
amount of $27.1 million was added to oil and gas properties to reflect the
difference between the cost and the tax basis of the properties acquired.
As a result of the acquisition, PC acquired Established Reserves of
13.9 mmboe and production of 5,300 boepd at an effective purchase price of
$10.08 per boe and $26,400 per boepd. The reserves and production were
approximately 50% gas and the reserve life index for these properties was 7.2
years. The NCE Energy Trust properties are located in British Columbia, Alberta
and Saskatchewan. Over 50% of the production was operated by NCE Energy Trust
and is now operated by PC. Approximately 30% of the production and reserves in
NCE Energy Trust were common with or adjacent to PC properties.
The Trust and NCE Energy Trust were managed by affiliated management
companies. Although it was concluded that the acquisition was not a "related
party transaction" within the meaning of certain Canadian securities laws,
because of the fact that the Trust and NCE Energy Trust were managed by
management companies that were under common control, the acquisition was
effectively treated as a related party transaction. As such, certain valuation,
disclosure and minority approval requirements were complied with. A valuation of
each of the Trust and NCE Energy Trust was completed by Sayer Securities
Limited. The valuation report, dated April 19, 2002, concluded that a reasonable
range of the fair market value for the units of the Trust was a low of $11.39
and a high of $14.29 and that a reasonable range of the fair market value for
the units of NCE Energy Trust was a low of $2.59 and a high of $3.29. The
acquisition was negotiated on an arm's length basis on behalf of the Trust and
NCE Energy Trust by a special committee of the board responsible for each
respective entity.
ATCO
On December 31, 2002, PC acquired producing gas properties in the Fort
Saskatchewan, Alberta area from ATCO Gas for $31.5 million. PC now operates the
properties and holds an average 95% working interest. Production net to PC was
approximately 6 mmcfpd and the Established Reserves acquired were approximately
19 bcf.
2003
Solaris
Effective January 1, 2003, PC acquired 100% of the outstanding common
share of Solaris Oil & Gas Inc. ("Solaris"), and on February 7, 2003,
amalgamated Solaris in PC. PC paid $7.4 million in cash, and assumed debt and
negative working capital of $1.2 million, for a total cost of the oil and gas
properties of $8.6 million. The acquisition added 720,000 boe of Established
Reserves and approximately 200 boepd of production.
Property Package
In the second quarter of 2003, PC closed the acquisition of a diverse
group of oil and gas properties for $61.7 million after adjustment. The purchase
was accretive to distributable cash flow, production from the properties was
approximately 2,300 boepd of which 42% was gas. Production and cash flow for the
month of June has been included in this report. Net revenue of $4.3 million from
the effective date to May 31, 2003 was applied against the purchase price. The
properties contain a large percentage of unit production, and have an RLI of
11.6 years.
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Swan Hills
On August 21, 2003, PC purchased a 7.22% interest in Swan Hills Unit #1
for $37.1 million from a private Canadian company. This acquisition increased
the Trust's interest in the Unit, bringing the Trust's total interest in the
Unit to 9.87%. This acquisition added 8.5 mmboe of Established Reserves and
approximately 1,100 boepd of production. The property's RLI was over 20 years.
BUSINESS AND PROPERTIES
PC acquires, manages and disposes of petroleum and natural gas property
rights and interests. As of December 31, 2003, PC's principal properties were
located in Alberta, British Columbia, Manitoba and Saskatchewan. PC primarily
produces light and medium oil, natural gas and natural gas liquids. As at
December 31, 2003, PC's asset base included proved plus probable reserves
(before deduction of royalties) of 53.4 mbbls of oil, 248.7 bcf of natural gas
and 7.2 mbbls of natural gas liquids based on forecast prices and cost
assumptions, and an inventory of undeveloped land totaling 534,589 gross acres
and 250,509 net acres. See "Statement of Reserves Data and Other Oil and Gas
Information - Disclosure of Reserves Data" and "Statement of Reserves Data and
Other Oil and Gas Information - Properties With No Attributed Reserves".
One of PC's ongoing objectives is to enhance reserves and production
through acquisitions. With respect to acquisitions, PC operates in a competitive
environment with both large and small competitors.
In 2003, PC acquired new properties for a total purchase price of $58.4
million and expended approximately $57.2 million to increase interests in
existing properties. PC disposed of properties for total proceeds of $33.5
million. In addition, PC incurred approximately $71.4 million mainly for
drilling, well equipment and facility costs.
The following is a summary of PC's properties as at December 31, 2003.
Unless otherwise specified, gross and net acres and well count information are
as at December 31, 2003. Reserve amounts are stated, before deduction of
royalties, as at December 31, 2003 based on forecast costs and price assumptions
as evaluated in the GLJ Report. The estimates of reserves and future net revenue
for individual properties may not reflect the same confidence level as estimates
of reserves and future net revenue for all properties, due to the effects of
aggregation.
Proved Plus
Average 2003 Average Probable
Working Production Reserves
Property Name Operator Interest Major Product (boepd) (mboe)
--------------------------------------------------------------------------------------------------------
Swan Hills Various Oil 2,300 14,424
Weyburn PanCanadian 9.3% Oil 2,000 14,012
Pembina Various Oil & Gas 1,200 8,815
Hatton Apache 95.0% Gas 1,100 4,100
Strachan Various Oil & Gas 1,225 3,963
Ring Border Burlington Resources 9.4% Gas 750 3,941
July Lake Canadian Natural Resources 35.0% Gas 1,200 3,175
Fort St. John Petrofund and Others Oil & Gas 775 3,031
Fort Saskatchewan Petrofund 97.0% Gas 850 3,015
Minehead Shiningbank Energy 35.0% Gas 500 2,838
Others Various Various Oil & Gas 16,518 40,716
----------------------------
28,418 102,030
============================
B-16
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Weyburn, Saskatchewan
The Weyburn Unit, operated by EnCana Oil & Gas Partnership, is located
30 kilometres south of the city of Weyburn in southeastern Saskatchewan.
Petrofund owns a 9.3% interest in the Weyburn Unit following the acquisition of
an additional 2.3% unit interest in 2003. This unit has an especially long
reserves life index (20+ years) due to ongoing enhanced recovery operations by
water and CO2 flooding. The unit's 2003 performance exceeded budget
expectations. 2003 development activity included further expansion of the CO2
flood, horizontal drilling (10 producers within the waterflood area and 2
injectors within the CO2 flood area) and the commencement of pre-engineering
work on Phase 4 of the CO2 flood. Petrofund's unit working interest production
averaged 2,000 boepd in 2003. Petrofund's total proved plus probable reserves as
of December 31, 2003, amounted to 14,012 mboe consisting of 13,655 mbbl of oil
and 357 mbbl of NGL.
Swan Hills, Alberta
Petrofund's Swan Hills (including Swan Hills North) property is located
approximately 200 kilometres northwest of Edmonton, Alberta and includes
significant ownership in such major oil units as Swan Hills Unit #1, Judy Creek
West Beaverhill Lake Unit, South Swan Hills Unit and House Mountain Unit #1.
Each of these units has long life reserves due to enhanced recovery through
water flooding and/or miscible hydrocarbon flooding. Early in 2003, Petrofund
significantly increased its Swan Hills Unit #1 ownership from 2.6% to 9.9%
through an acquisition. In addition, 6 horizontal wells were drilled in House
Mountain Unit #1 and 2 verticals wells in Swan Hills Unit #1. The Swan Hills
Unit #1 owners agreed to implement a pilot CO2 enhanced recovery project that's
expected to start up in early 2004. At yearend, Petrofund's working interest
Swan Hills production was 2,300 boepd. Petrofund's total proved plus probable
reserves as of December 31, 2003, totaled 14,424 mboe, consisting of 12,654 mbbl
of oil, 4.2 bcf of gas and 1,074 mbbl of NGL.
Pembina, Alberta
Petrofund's extensive Pembina holdings are situated 100 kilometres
southwest of Edmonton, Alberta. Petrofund operates several Pembina properties,
including Alder Flats, Cynthia, Lodgepole, Pembina, Rose Creek and Warburg.
Partner operated properties include North Pembina Cardium Unit, Berrymoor
Cardium Unit, Pembina Cardium Unit #7, Pembina Easyford Cardium Unit #1,
Lobstick Cardium Unit and Pembina Knobhill Belly River Unit #2. Development
activity in 2003 included the drilling of approximately 40 gross wells and
continued optimization/reactivation of several unit waterfloods. Petrofund
anticipates a similar number of wells being drilled on its properties next year.
Petrofund's working interest Pembina averaged 1,200 boepd during 2003.
Petrofund's total proved plus probable reserves as of December 31, 2003, totaled
8,815 mboe, comprising of 6,753 mbbl of oil, 8.9 bcf of gas and 576 mbbl of NGL.
Hatton, Saskatchewan
Petrofund's Hatton gas property is located approximately 140 kilometres
west of Swift Current, Saskatchewan. Petrofund operates 265 shallow gas wells,
including 74 new 100% working interest wells drilled in late 2003. Petrofund's
production originates from the shallow (500 metres) commingled Medicine Hat and
Milk River sand zones. At yearend, Petrofund's working interest production was
1,100 boepd. Petrofund's total proved plus probable reserves as of December 31,
2003, were 4,100 mboe, comprising of 24.6 bcf of gas.
Strachan-Caroline, Alberta
Petrofund's Strachan-Caroline property is located approximately 160
kilometres northwest of Calgary and consists of a combination of operated and
non-operated producing entities. Petrofund operates approximately
B-17
18
85% of its Strachan-Caroline production. This area is well-known for its
multiple targets as evidenced by Petrofund's production coming from a variety of
zones such as the Leduc, Beaverhill Lake, Cardium, Viking, Ostracod, Glauconite
and Lower Mannville. In 2003, Petrofund successfully completed, equipped and
tied in 2 operated gas wells that had been drilled in late 2002. Petrofund's
working interest production averaged 1,225 boepd in 2003. Petrofund's total
proved plus probable reserves as of December 31, 2003, were 3,963 mboe, made up
of 67 mbbl of oil, 17.8 bcf of gas and 924 mbbl of NGL.
Border Bluesky, British Columbia
Petrofund's Border Bluesky gas property is located 190 kilometres
northeast of Fort St. John in northeastern British Columbia and is operated by
Burlington Resources Canada. Petrofund owns a 9.4% interest in the Border
Bluesky-Gething-Montney Unit "B" and a similar interest in certain surrounding
non-unit lands. Petrofund also has ownership in the Border gas plant. Sixteen
unit and non-unit wells were drilled and equipped in early 2003. A similar
infill drilling program is planned for early 2004 (winter access only).
Petrofund's 2003 working interest production averaged 750 boepd. Petrofund's
total proved plus probable reserves as of December 31, 2003, were 3,941 mboe,
comprising of 20.9 bcf of gas and 450 mbbl of NGL.
July Lake, British Columbia
Petrofund's July Lake property is situated approximately 160 kilometres
northeast of Fort Nelson in northeastern British Columbia. Petrofund holds an
average 34% working interest in 19 producing gas wells, several of which are
horizontals, within a Production Sharing Area operated by Canadian Natural
Resources Limited. Petrofund also owns 100% working interest in nine additional
gas wells. All gas production comes from the Jean Marie formation and is
processed at Duke's Fort Nelson gas plant. No wells were drilled on Petrofund
lands in 2003 but as many as 8 wells could be drilled in 2004. Petrofund's
working interest production averaged 1,200 boepd during 2003. Petrofund's total
proved plus probable reserves as of December 31, 2003, were 3,175 mboe,
consisting of 19.0 bcf of gas and 8 mbbl of NGL.
Fort St. John, British Columbia
Petrofund's Fort St. John property is located close by the city of the
Fort St. John in northeastern British Columbia. Petrofund's operated entities
include Boundary Lake, Cecil Lake, Fort St. John and Wilder, while non-operated
entities include West Eagle and Stoddart. During 2003, Petrofund successfully
drilled 2 operated Boundary Lake wells, plus completed, equipped and tied in 2
operated Cecil Lake oil wells that had been drilled late in 2002. Petrofund is
moving ahead with plans to waterflood its Cecil Lake property in 2004. Petrofund
is also contemplating follow-up drilling on its Boundary Lake and Cecil Lake oil
properties in 2004. Petrofund's working interest production from this property
averaged 775 boepd during 2003. Petrofund's total proved plus probable reserves
as of December 31, 2003, totaled 3,031 mboe, containing 1,417 mbbl of oil, 8.1
bcf of gas and 267 mbbl of NGL.
Minehead, Alberta
Minehead is a gas property located approximately 120 kilometres
southwest of Edmonton, Alberta. Shiningbank Energy and Calpine Canada operate
Petrofund's Minehead production. Petrofund's working interests vary from 27.8
per cent to 40 per cent. Producing zones include the Cardium and Belly River.
Cardium production is characterized by low decline and high NGL recovery. During
2003, Petrofund participated for its 40% working interest in drilling 2
successful Cardium gas wells which came on stream in the 4th quarter. Petrofund
anticipates as many as 8 gross wells being drilled on its Minehead acreage in
2004. Petrofund's working interest production from this property averaged 500
boepd in 2003. Petrofund's total proved plus probable reserves as of December
31, 2003, were 2,838 mboe, comprising of 12.8 bcf of gas and 712 mbbl of NGL.
B-18
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Fort Saskatchewan, Alberta
Petrofund operates its Fort Saskatchewan gas property located
immediately east of Edmonton, Alberta. Petrofund's Fort Saskatchewan property
includes the Beaverhill Lake Viking Gas Unit #1 along with the nearby Partridge
Hill and Bremner producing fields. Petrofund's average working interest for this
area is nearly 100%. Besides the wells, Petrofund owns and operates 3 associated
compression-dehydration facilities. Production is predominantly gas from the
Viking zone. During 2003, Petrofund aggressively recompleted and reactivated
several wells with mixed success. In 2004, Petrofund will continue to evaluate
its lands and wells for development opportunities. Petrofund's working interest
production averaged 850 boepd during 2003. Petrofund's total proved plus
probable reserves as of December 31, 2003, amounted to 3,015 mboe, consisting of
18.1 bcf of gas.
The above 10 properties account for about 60% of PC's total proved plus
probable reserves as at December 31, 2003.
Other Properties
PC has various interests in numerous other properties located in
Alberta, British Columbia, Manitoba and Saskatchewan. PC's proved plus probable
reserves for these other properties as at December 31, 2003 amounted to
approximately 40,700 mboe. In total, these properties represent approximately
40% of PC's proved plus probable reserves as at December 31, 2003.
A map which illustrates the approximate locations of PC's principal
properties is set out below:
[GRAPHIC OF MAP OMITTED]
B-19
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REPORT OF MANAGEMENT AND DIRECTORS ON RESERVES DATA AND OTHER
INFORMATION
Management of Petrofund Corp. (the "Company") are responsible for the
preparation and disclosure of information with respect to the Company's oil and
gas activities in accordance with securities regulatory requirements. This
information includes reserves data, which consist of the following:
(a) (i) proved and proved plus probable oil and gas reserves
estimated as at December 31, 2003 using forecast prices and
costs; and
(ii) the related estimated future net revenue; and
(b) (i) proved oil and gas reserves estimated as at December 31,
2003 using constant prices and costs; and
(ii) the related estimated future net revenue.
An independent qualified reserves evaluator has evaluated the Company's reserves
data. The report of the independent qualified reserves evaluator is presented
below.
The Reserves Committee of the board of directors of the Company has:
(a) reviewed the Company's procedures for providing information to
the independent qualified reserves evaluator;
(b) met with the independent qualified reserves evaluator to
determine whether any restrictions affected the ability of the
independent qualified reserves evaluator to report without
reservation; and
(c) reviewed the reserves data with management and the independent
qualified reserves evaluator.
The Reserves Committee of the board of directors has reviewed the Company's
procedures for assembling and reporting other information associated with oil
and gas activities and has reviewed that information with management. The board
of directors has, on the recommendation of the Audit Committee, approved:
(a) the content and filing with securities regulatory authorities of
the reserves data and other oil and gas information;
(b) the filing of the report of the independent qualified reserves
evaluator on the reserves data; and
(c) the content and filing of this report.
Because the reserves data are based on judgments regarding future events, actual
results will vary and the variations may be material.
(signed) "Jeffery E. Errico" (signed) "Glen C. Fischer"
Jeffery E. Errico Glen C. Fischer
President and Chief Executive Officer Senior Vice President, Operations
(signed) "Wayne M. Newhouse" (signed) "James E. Allard"
Wayne M. Newhouse James E. Allard
Director and Chairman of the Director and Member of the
Reserves Audit Committee Reserves Audit Committee
March 1, 2004
B-20
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REPORT ON RESERVES DATA BY
INDEPENDENT QUALIFIED RESERVES
EVALUATOR OR AUDITOR
To the board of directors of Petrofund Corp. (the "Company"):
1. We have evaluated the Company's reserves data as at February 17, 2004.
The reserves data consist of the following:
(a) (i) proved and proved plus probable oil and gas reserves
estimated as at December 31, 2003 using forecast prices and
costs; and
(ii) the related estimated future net revenue; and
(b) (i) proved oil and gas reserves estimated as at December 31,
2003 using constant prices and costs; and
(ii) the related estimated future net revenue.
2. The reserves data are the responsibility of the Company's
management. Our responsibility is to express an opinion on the
reserves data based on our evaluation.
We carried out our evaluation in accordance with standards set out in
the Canadian Oil and Gas Evaluation Handbook (the "COGE Handbook")
prepared jointly by the Society of Petroleum Evaluation Engineers
(Calgary Chapter) and the Canadian Institute of Mining, Metallurgy &
Petroleum (Petroleum Society).
3. Those standards require that we plan and perform an evaluation to
obtain reasonable assurance as to whether the reserves data are free
of material misstatement. An evaluation also includes assessing
whether the reserves data are in accordance with principles and
definitions presented in the COGE Handbook.
4. The following table sets forth the estimated future net revenue
(before deduction of income taxes) attributed to proved plus probable
reserves, estimated using forecast prices and costs and calculated
using a discount rate of 10 percent, included in the reserves data of
the Company evaluated by us for the year ended December 31, 2003, and
identifies the respective portions thereof that we have audited,
evaluated and reviewed and reported on to the Company's board of
directors:
Location of
Reserves
(County or Net Present Value of Future Net Revenue
Description and Reserves (M$ before income taxes, 10% discount rate)
Preparation Date Foreign ----------------------------------------------------------
of Report Geographic Area) Audited Evaluated Reviewed Total
------------------ --------------- ------------- ------------- ------------- -------------
February 4, 2004 Canada nil 678,788 nil 678,788
5. In our opinion, the reserves data respectively evaluated by us have, in
all material respects, been determined and are in accordance with the
COGE Handbook.
B-21
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6. We have no responsibility to update this evaluation for events and
circumstances occurring after the preparation date.
7. Because the reserves data are based on judgements regarding future
events, actual results will vary and the variations may be material.
(signed) "Wayne Chow, P.Eng"
Vice President
Gilbert Laustsen Jung Associates Ltd.
Calgary, Alberta
February 17, 2004
B-22
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STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION
The statement of reserves data and other oil and gas information set
forth below (the "Statement") is dated February 17, 2004. The effective date of
the Statement is December 31, 2003 and the preparation date of the Statement is
February 4, 2004.
Disclosure of Reserves Data
The reserves data set forth below (the "Reserves Data") is based upon
an evaluation by GLJ with an effective date of December 31, 2003 contained in
the GLJ Report dated February 17, 2004. The Reserves Data summarizes the oil,
liquids and natural gas reserves of PC and the net present values of future net
revenue for these reserves using constant prices and costs and forecast prices
and costs. The Reserves Data conforms with the requirements of National
Instrument 51-101 Standards of Disclosure for Oil and Gas Activities ("NI
51-101"). Additional information not required by NI 51-101 has been presented to
provide continuity and additional information which we believe is important to
the readers of this information. PC engaged GLJ to provide an evaluation of
proved and proved plus probable reserves and no attempt was made to evaluate
possible reserves.
All of PC's reserves are in Canada and, specifically, in the provinces
of Alberta, British Columbia, Manitoba and Saskatchewan.
PC is not taxable under the existing trust structure. The Alberta
Securities Commission has advised that PC will be exempt from disclosing after
tax future net revenues from its reserves.
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Reserves Data (Constant Prices and Costs)
SUMMARY OF OIL AND GAS RESERVES
AND NET PRESENT VALUES OF FUTURE NET REVENUE
as of December 31, 2003
CONSTANT PRICES AND COSTS
RESERVES
-------------------------------------------------------------------------------
LIGHT AND NATURAL GAS
MEDIUM OIL HEAVY OIL NATURAL GAS LIQUIDS
----------------- ----------------- ----------------- ------------------
Gross Net Gross Net Gross Net Gross Net
RESERVES CATEGORY (mbbl) (mbbl) (mbbl) (mbbl) (mmcf) (mmcf) (mbbl) (mbbl)
------------------------- -------- -------- -------- -------- -------- -------- -------- --------
PROVED
Developed Producing 33,914 29,686 853 750 196,898 155,614 5,213 3,674
Developed Non-Producing 310 292 0 0 5,903 4,488 148 107
Undeveloped 8,671 7,815 0 0 5,402 4,170 376 255
-------- -------- -------- ------- -------- -------- ------- -------
TOTAL PROVED 42,895 37,793 853 750 208,203 164,271 5,738 4,036
PROBABLE 11,240 9,677 205 183 45,680 36,115 1,584 1,211
-------- -------- -------- ------- -------- -------- ------- -------
TOTAL PROVED PLUS PROBABLE 54,135 47,471 1,058 933 253,883 200,386 7,323 5,247
======== ======== ======== ======= ======== ======== ======= =======
NET PRESENT VALUES OF FUTURE NET REVENUE
BEFORE INCOME TAXES DISCOUNTED AT (%/year)
---------------------------------------------------------------
---------------------------------------------------------------
0 5 10 12 15 20
RESERVES CATEGORY (MM$) (MM$) (MM$) (MM$) (MM$) (MM$)
------------------------------------- ------- ------- ------- ------- ------- -------
PROVED
Developed Producing 1,214 902 728 678 616 538
Developed Non-Producing 32 24 19 18 16 14
Undeveloped 174 105 67 57 44 30
------- ------- ------- ------- ------- -------
TOTAL PROVED 1,419 1,031 814 753 677 582
PROBABLE 429 239 155 134 110 83
------- ------- ------- ------- ------- -------
TOTAL PROVED PLUS PROBABLE 1,848 1,270 970 887 787 664
======= ======= ======= ======= ======= =======
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TOTAL FUTURE NET REVENUE
(UNDISCOUNTED)
as of December 31, 2003
CONSTANT PRICES AND COSTS
FUTURE
NET
REVENUE
WELL BEFORE
OPERATING DEVELOPMENT ABANDONMENT INCOME
REVENUE ROYALTIES COSTS COSTS COSTS TAXES
RESERVES CATEGORY (M$) (M$) (M$) (M$) (M$) (M$)
------------------------ --------- --------- --------- ----------- ----------- ---------
Proved Reserves 3,122,731 591,013 942,158 116,124 54,124 1,419,313
Proved Plus Probable
Reserves 3,886,979 730,689 1,105,367 147,279 55,609 1,848,034
FUTURE NET REVENUE
BY PRODUCTION GROUP
as of December 31, 2003
CONSTANT PRICES AND COSTS
FUTURE NET REVENUE
BEFORE INCOME TAXES
(discounted at 10%/year)
RESERVES CATEGORY PRODUCTION GROUP (M$)
------------------------- ---------------------------------------------------- ------------------------
Proved Reserves Light and Medium Crude Oil (including solution gas
and other by-products) 394,007
Heavy Oil (including solution gas and other 9,108
by-products)
Natural Gas (including by-products but excluding
solution gas from oil wells) 411,312
Proved Plus Probable Light and Medium Crude Oil (including solution gas
Reserves and other by-products) 487,656
Heavy Oil (including solution gas and other
by-products) 10,563
Natural Gas (including by-products but excluding
solution gas from oil wells) 471,389
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Reserves Data (Forecast Prices and Costs)
SUMMARY OF OIL AND GAS RESERVES
AND NET PRESENT VALUES OF FUTURE NET REVENUE
as of December 31, 2003
FORECAST PRICES AND COSTS
RESERVES
-------------------------------------------------------------------------------
LIGHT AND NATURAL GAS
MEDIUM OIL HEAVY OIL NATURAL GAS LIQUIDS
----------------- ----------------- ----------------- -----------------
Gross Net Gross Net Gross Net Gross Net
RESERVES CATEGORY (mbbl) (mbbl) (mbbl) (mbbl) (mmcf) (mmcf) (mbbl) (mbbl)
------------------------- -------- -------- -------- -------- -------- -------- -------- --------
PROVED
Developed Producing 32,512 28,565 848 750 191,682 151,527 5,060 3,577
Developed Non-Producing 276 260 0 0 6,071 4,616 154 112
Undeveloped 8,675 8,196 0 0 5,408 4,177 377 258
-------- -------- ------- ------- -------- -------- ------- -------
TOTAL PROVED 41,463 37,021 848 750 203,161 160,320 5,591 3,947
PROBABLE 10,889 9,458 203 182 45,605 36,114 1,575 1,208
-------- -------- ------- ------- -------- -------- ------- -------
TOTAL PROVED PLUS PROBABLE 52,352 46,479 1,051 932 248,766 196,434 7,166 5,155
======== ======== ======= ======= ======== ======== ======= =======
NET PRESENT VALUES OF FUTURE NET REVENUE
BEFORE INCOME TAXES DISCOUNTED AT (%/year)
---------------------------------------------------------------
0 5 10 12 15 20
RESERVES CATEGORY (MM$) (MM$) (MM$) (MM$) (MM$) (MM$)
------------------------------------- ------- ------- ------- ------- ------- -------
PROVED
Developed Producing 790 615 513 483 446 397
Developed Non-Producing 24 18 15 14 12 11
Undeveloped 111 63 37 30 21 12
TOTAL PROVED 925 696 565 527 479 419
PROBABLE 320 177 114 98 81 60
TOTAL PROVED PLUS PROBABLE 1,245 873 679 625 560 480
======= ====== ======= ======== ========= ========
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TOTAL FUTURE NET REVENUE
(UNDISCOUNTED)
as of December 31, 2003
FORECAST PRICES AND COSTS
FUTURE NET
REVENUE
WELL BEFORE
OPERATING DEVELOPMENT ABANDONMENT INCOME
REVENUE ROYALTIES COSTS COSTS COSTS TAXES
RESERVES CATEGORY (M$) (M$) (M$) (M$) (M$) (M$)
------------------------ --------- --------- --------- ----------- ----------- ---------
Proved Reserves 2,590,205 473,795 1,003,268 123,226 64,581 925,335
Proved Plus
Probable
Reserves 3,267,061 589,762 1,206,744 156,876 68,834 1,244,846
FUTURE NET REVENUE
BY PRODUCTION GROUP
as of December 31, 2003
FORECAST PRICES AND COSTS
FUTURE NET REVENUE
BEFORE INCOME TAXES
(discounted at 10%/year)
RESERVES CATEGORY PRODUCTION GROUP (M$)
------------------------- ---------------------------------------------------- ------------------------
Proved Reserves Light and Medium Crude Oil (including solution gas and
other by-products) 241,996
Heavy Oil (including solution gas and other by-products) 6,674
Natural Gas (including by-products but excluding solution
gas from oil wells) 316,033
Proved Plus Probable Light and Medium Crude Oil (including solution gas and
Reserves other by-products) 309,328
Heavy Oil (including solution gas and other by-products) 7,797
Natural Gas (including by-products but excluding solution
gas from oil wells) 361,663
Definitions and Other Notes
In the tables set forth above in "Disclosure of Reserves Data" and elsewhere in
this Annual Information Form the following definitions and other notes are
applicable:
1. "Gross" means:
(a) in relation to PC's interest in production and reserves, its "PC
gross reserves", which are PC's interest (operating and
non-operating) share before deduction of royalties and without
including any royalty interest of PC;
(b) in relation to wells, the total number of wells in which PC has
an interest; and
(c) in relation to properties, the total area of properties in which
PC has an interest.
B-27
28
2. "Net" means:
(a) in relation to PC's interest in production and reserves, its "PC
net reserves", which are PC's interest (operating and
non-operating) share after deduction of royalties obligations,
plus PC's royalty interest in production or reserves.
(b) in relation to wells, the number of wells obtained by aggregating
PC's working interest in each of its gross wells; and
(c) in relation to PC's interest in a property, the total area in
which PC has an interest multiplied by the working interest
owned by PC.
3. Definitions used for reserve categories are as follows:
Reserve Categories
------------------
Reserves are estimated remaining quantities of oil and natural gas and
related substances anticipated to be recoverable from known
accumulations, from a given date forward, based on
o analysis of drilling, geological, geophysical and engineering
data;
o the use of established technology; and
o specified economic conditions (see the discussion of "Economic
Assumptions" below).
Reserves are classified according to the degree of certainty
associated with the estimates.
(a) Proved reserves are those reserves that can be estimated with a
high degree of certainty to be recoverable. It is likely that the
actual remaining quantities recovered will exceed the estimated
proved reserves.
(b) Probable reserves are those additional reserves that are less
certain to be recovered than proved reserves. It is equally
likely that the actual remaining quantities recovered will be
greater or less than the sum of the estimated proved plus
probable reserves.
"Economic Assumptions" will be the prices and costs used in the
estimate, namely:
o constant prices and costs as at the last day of PC's financial
year
o forecast prices and costs
Development and Production Status
---------------------------------
Each of the reserve categories (proved and probable) may be divided
into developed and undeveloped categories:
(a) Developed reserves are those reserves that are expected to be
recovered from existing wells and installed facilities or, if
facilities have not been installed, that would involve a low
expenditure (for example, when compared to the cost of drilling a
well) to put the reserves on production. The developed category
may be subdivided into producing and non-producing.
(i) Developed producing reserves are those reserves that are
expected to be recovered from completion intervals open at
the time of the estimate. These reserves may be currently
B-28
29
producing or, if shut-in, they must have previously been
on production, and the date of resumption of production
must be known with reasonable certainly.
(ii) Developed non-producing reserves are those reserves that
either have not been on production, or have previously
been on production, but are shut-in, and the date of
resumption of production is unknown.
(b) Undeveloped reserves are those reserves expected to be recovered
from known accumulations where a significant expenditure (for
example, when compared to the cost of drilling a well) is
required to render them capable of production. They must fully
meet the requirements of the reserves classification (proved,
probable) to which they are assigned.
In multi-well pools it may be appropriate to allocate total pool
reserves between the developed and undeveloped categories or to
subdivide the developed reserves for the pool between developed
producing and developed non-producing. This allocation should be based
on the estimator's assessment as to the reserves that will be
recovered from specific wells, facilities and completion intervals in
the pool and their respective development and production status.
Levels of Certainty for Reported Reserves
-----------------------------------------
The qualitative certainty levels referred to in the definitions above
are applicable to individual reserve entities (which refers to the
lowest level at which reserves calculations are performed) and to
reported reserves (which refers to the highest level sum of individual
entity estimates for which reserves are presented). Reported reserves
should target the following levels of certainty under a specific set
of economic conditions:
o At least a 90 percent probability that the quantities actually
recovered will equal or exceed the estimated proved reserves;
o At least a 50 percent probability that the quantities actually
recovered will equal or exceed the sum of the estimated proved
plus probable reserves.
A qualitative measure of the certainty levels pertaining to estimates
prepared for the various reserves categories is desirable to provide a
clearer understanding of the associated risks and uncertainties.
However, the majority of reserves estimates will be prepared using
deterministic methods that do not provide a mathematically derived
quantitative measure of probability. In principle, there should be no
difference between estimates prepared using probabilistic or
deterministic methods.
4. Forecast prices and costs Future prices and costs that are:
(a) Generally acceptable as being a reasonable outlook of the future;
and
(b) If and only to the extent that, there are fixed or presently
determinable future prices or costs to which PC is legally bound
by a contractual or other obligation to supply a physical
product, including those for an extension period of a contract
that is likely to be extended, those prices or costs rather than
the prices and costs referred to in paragraph (a).
The forecast summary table under "Pricing Assumptions" identifies
benchmark reference pricing that apply to PC.
B-29
30
5. Constant prices and costs
Prices and costs used in an estimate that are:
(a) PC's prices and costs as at the effective date of the estimation,
held constant throughout the estimated lives of the properties to
which the estimate applies; and
(b) If, and only to the extent that, there are fixed or presently
determinable future prices or costs to which PC is legally bound
by a contractual or other obligation to supply a physical
product, including those for an extension period of a contract
that is likely to be extended, those prices or costs rather than
the prices and costs referred to in paragraph (a).
For the purposes of paragraph (a), PC prices are the posted prices for
oil and the spot price for gas, after historical adjustments for
transportation, gravity and other factors.
6. The Alberta royalty tax credit ("ARTC") is included in the cumulative
cash flow amounts. ARTC is based on the program announced November
1989 by the Alberta government with modifications effective January 1,
1995. PC qualifies for the maximum ARTC.
7. Future income tax expense
` Future income tax expenses estimate:
(a) Making appropriate allocations of estimated unclaimed costs and
losses carried forward for tax purposes;
(b) Without deducting estimated future costs that are not deductible
in computing taxable income;
(c) Taking into account estimated tax credits and allowances; and
(d) Applying to the future pre-tax net cash flows relating to PC's
oil and gas activities the appropriate year-end statutory rates,
taking into account future tax rates already legislated.
8. "Development well" means a well drilled inside the established limits
of an oil and gas reservoir, or in close proximity to the edge of the
reservoir, to the depth of a stratigraphic horizon known to be
productive.
9. "Development costs" means costs incurred to obtain access to reserves
and to provide facilities for extracting, treating, gathering and
storing the oil and gas from reserves. More specifically, development
costs, including applicable operating costs of support equipment and
facilities and other costs of development activities, are costs
incurred to:
(a) Gain access to and prepare well locations for drilling, including
surveying well locations for the purpose of determining specific
development drilling sites, clearing ground draining, road
building, and relocating public roads, gas lines and power lines,
pumping equipment and wellhead assembly;
(b) Drill and equip development wells, development type stratigraphic
test wells and service wells, including the costs of platforms
and of well equipment such as casing, tubing, pumping equipment
and wellhead assembly;
B-30
31
(c) Acquire, construct and install production facilities such as flow
lines, separators, treaters, heaters, manifolds, measuring
devices and production storage tanks, natural gas cycling and
processing plants, and central utility and waste disposal
systems; and
(d) Provide improved recovery systems.
10. "Exploration well" means a well that is not a development well, a
service well or a stratigraphic test well.
11. "Exploration costs" means costs incurred in identifying areas that may
warrant examination and in examining specific areas that are considered
to have prospects that may contain oil and gas reserves, including
costs of drilling exploratory wells and exploratory type stratigraphic
test wells. Exploration costs may be incurred both before acquiring the
related property and after acquiring the property. Exploration costs,
which include applicable operating costs of support equipment and
facilities and other costs of exploration activities, are:
(a) Costs of topographical, geochemical, geological and geophysical
studies, rights of access to properties to conduct those studies,
and salaries and other expenses of geologists, geophysical crews
and others conducting those studies;
(b) Costs of carrying and retaining unproved properties, such as
delay rentals, taxes (other than income and capital taxes) on
properties, legal costs for title defence, and the maintenance of
land and lease records;
(c) Dry hole contributions and bottom hole contributions;
(d) Costs of drilling and equipping exploratory wells; and
(e) Costs of drilling exploratory type stratigraphic test wells.
12. "Service well" means a well drilled or completed for the purpose of
supporting production in an existing field. Wells in this class are
drilled for the following specific purposes: gas injection (natural
gas, propane, butane or flue gas), water injection, steam injection,
air injection, salt water disposal, water supply for injection,
observation or injection for combustion.
13. Numbers may not add due to rounding.
14. The estimates of future net revenue presented in the tables above do
not represent fair market value.
15. Disclosure provided herein in respect of boes may be misleading,
particularly if used in isolation. A boe conversion ratio of 6 mcf : 1
bbls is based on an energy equivalency conversion method primarily
applicable at the burner tip and does not represent a value equivalency
at the wellhead.
16. Estimated further abandonment and reclamation costs related to a
property have been taken into account by GLJ in determining reserves
that should be attributable to a property and in determining the
aggregate future net revenue therefrom, there was deducted the
reasonable estimated further well abandonment costs.
17. Both the constant and forecast price and cost assumptions assume the
continuance of current laws and regulations.
18. The extended character of all factual data supplied to GLJ were
accepted by GLJ as represented. No field inspection was conducted.
B-31
32
Pricing Assumptions
The following sets out the benchmark reference prices, as at December 31, 2003,
reflected in the Reserves Data. These price assumptions were provided to PC by
GLJ, PC's independent qualified evaluator.
SUMMARY OF PRICING ASSUMPTIONS
as of December 31, 2003
CONSTANT PRICES AND COSTS
OIL
OIL
----------------------------------------------------
Cromer
WTI Edmonton Hardisty Medium NATURAL Edmonton
Cushing Par Price Heavy 29.3(degree) GAS AECO Edmonton Edmonton Pentanes EXCHANGE
Oklahoma 40(degree) API 12(degree) API API Gas Price Propane Butane Plus RATE((1)
Year ($US/bbl) ($Cdn/bbl) ($Cdn/bbl) ($Cdn/bbl) ($Cdn/MMBtu) ($Cdn/bbl) ($Cdn/bbl) ($Cdn/bbl) ($US/$Cdn)
------------- --------- ---------- ---------- ---------- ------------ ---------- ---------- ---------- ----------
Historical
As at December 32.52 40.81 23.31 34.81 6.09 29.81 31.81 41.31 0.7738
31, 2003
Notes:
(1) The exchange rate used to generate the benchmark reference prices in
this table.
SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS
as of December 31, 2003
FORECAST PRICES AND COSTS
OIL
-------------------------------------------------------
Edmonton Cromer
WTI Par Hardisty Medium NATURAL Edmonton
Cushing Price Heavy 29.3(degree) GAS AECO Edmonton Edmonton Pentanes INFLATION EXCHANGE
Oklahoma 40(degree) API 12(degree) API) API Gas Price Propane Butane Plus RATES(1) RATE(2)
Year ($US/bbl) ($Cdn/bbl) ($Cdn/bbl ($Cdn/bbl) ($Cdn/MMBtu) ($Cdn/bbl) ($Cdn/bbl) ($Cdn/bbl) %/Year ($US/$Cdn)
-------- --------- -------------- --------------- ----------- ------------ ---------- ---------- ---------- -------- ----------
Forecast:
2004 29.00 37.75 20.25 31.75 5.85 26.75 28.75 38.25 1.5 0.750
2005 26.00 33.75 20.25 28.75 5.15 21.75 23.75 34.25 1.5 0.750
2006 25.00 32.50 21.00 28.50 5.00 20.50 22.50 33.00 1.5 0.750
2007 25.00 32.50 21.00 28.50 5.00 20.50 22.50 33.00 1.5 0.750
2008 25.00 32.50 21.00 28.50 5.00 20.50 22.50 33.00 1.5 0.750
Notes:
(1) Inflation rates for forecasting prices and costs.
(2) Exchange rates used to generate the benchmark reference prices in this
table.
PC's weighted average prices received in 2003 after transportation and quality
differentials were $37.91/bbl for oil, $6.30/mcf for natural gas and $34.66/bbl
for natural gas liquids.
B-32
33
Reconciliations of Changes in Reserves and Future Net Revenue
RECONCILIATION OF
COMPANY NET RESERVES
BY PRINCIPAL PRODUCT TYPE
CONSTANT PRICES AND COSTS
ASSOCIATED AND
LIGHT AND MEDIUM OIL HEAVY OIL NON-ASSOCIATED GAS
---------------------------- ---------------------------- ---------------------------
Net Net Net
Proved Proved Proved
Net Net Plus Net Net Plus Net Net Plus
Proved Probable Probable Proved Probable Probable Proved Probable Probable
FACTORS (mbbl) (mbbl) (mbbl) (mbbl) (mbbl) (mbbl) (bcf) (bcf) (bcf)
-------------------- ------ -------- -------- ------ -------- -------- ------ -------- --------
December 31 2002(1) 34,834 6,758 41,592 553 40 593 181 32 213
Extensions 159 23 182 0 0 0 1 0 1
Improved Recovery 681 (492) 189 0 0 0 0 0 0
Technical Revisions (1,303) 2,478 1,175 318 143 461 (8) 3 (6)
Discoveries 79 21 100 0 0 0 0 0 0
Acquisitions 9,319 2,348 11,667 0 0 0 15 2 17
Dispositions (2,186) (1,520) (3,705) 0 0 0 (2) (1) (3)
Economic Factors (102) 62 (39) 0 0 0 1 1 1
Production (3,689) (3,689) (121) (121) (23) (23)
----------------------------------------------------------------------------------------
December 31, 2003 37,793 9,678 47,471 750 183 933 164 36 200
========================================================================================
NATURAL GAS LIQUIDS BARRELS OF OIL EQUIVALENT
--------------------------- ----------------------------
Net Net
Proved Proved
Net Net Plus Net Net Plus
Proved Probable Probable Proved Probable Probable
FACTORS (mbbl) (mbbl) (mbbl) (mboe) (mboe) (mboe)
------------------- ------ -------- -------- ------ -------- --------
December 31 2002(1) 4,175 762 4,937 69,753 12,850 82,602
Extensions 30 4 34 332 53 385
Improved Recovery 11 1 13 757 (478) 280
Technical Revisions (1,007) 294 (713) (3,391) 3,365 (27)
Discoveries 0 0 0 79 21 100
Acquisitions 1,367 129 1,496 13,201 2,820 16,020
Dispositions (13) (8) (22) (2,537) (1,750) (4,287)
Economic Factors 17 29 45 11 211 222
Production (545) (545) (8,248) (8,248)
---------------------------------------------------------
December 31, 2003 4,036 1,211 5,247 69,957 17,091 87,048
=========================================================
Note:
(1) The evaluation as at December 31, 2002 was prepared using National
Policy Statement 2-B reserves definitions. Under those definitions,
probable reserves were adjusted by a factor to account for the risk
associated with their recovery. PC previously applied a risk factor of
50% in reporting probable reserves. Under current NI 51-101 reserves
definitions, estimates are prepared such that the full proved plus
probable reserves are estimated to be recoverable (proved plus probable
reserves are effectively a "best estimate"). The above reconciliation
reflects current probable reserves versus previous risk adjusted (50%)
probable reserves reported by PC.
B-33
34
RECONCILIATION OF CHANGES IN
NET PRESENT VALUES OF FUTURE NET REVENUE
DISCOUNTED AT 10% PER YEAR
PROVED RESERVES
CONSTANT PRICES AND COSTS
2003
PERIOD AND FACTOR (M$)
------------------------------------------------------------------------------- -----------
Estimated Net Present Value Before Tax at Beginning of Year 1,027,930
Oil and Gas Sales During the Period(1) (217,054)
Changes due to Prices, Production Costs and Royalties Related to Forecast Production(2) (151,647)
Development Costs During the Period(3) (71,400)
Changes in Forecast Development Costs(4) 15,421
Changes Resulting from Extensions and Improved Recovery(5) 12,665
Changes Resulting from Discoveries(5) 989
Changes Resulting from Acquisitions of Reserves(5) 156,038
Changes Resulting from Dispositions of Reserves(5) (28,991)
Accretion of Discount(6) 102,793
Net Change in Income Taxes(7) N/A
Changes Resulting from Technical Reserves Revisions Plus All Other Changes (32,317)
-----------
Estimated Net Present Value Before Tax at End of Period 814,427
===========
Notes:
(1) Net of production costs and royalties, before income taxes
(2) The impact of changes in prices and other economic factors on future net
revenue
(3) Actual capital expenditures relating to the exploration and development and
production of oil and gas reserves
(4) Includes the difference between actual and forecast development costs during
the period
(5) Production and capital costs associated with recovery of the related
reserves are included in this category
(6) 10% of after adjustments for dispositions
(7) Includes the difference between actual and forecast income taxes during the
period
Additional Information Relating to Reserves Data
Undeveloped Reserves
Proved and probable undeveloped reserves have been estimated in
accordance with procedures and standards contained in the COGE Handbook. In
general, undeveloped reserves are scheduled to be developed within the next two
years of the effective date. Capital expenditures to develop proved undeveloped
reserves are estimated at $15.8 million in 2004 and $11.4 million in 2005.
Significant Factors or Uncertainties
For details of important economic factors or significant uncertainties
that affect particular components of the Reserves Data, see "Management's
Discussion And Analysis" and "Risk Factors - Business-Related Risks".
Future Development Costs
The following table sets forth development costs deducted in the
estimation of PC's future net revenue attributable to the reserve categories
noted below.
B-34
35
Constant Prices
Forecast Prices and Costs (M$) and Costs (M$)
----------------------------------- ---------------
Proved Plus
Year Proved Reserves Probable Reserves Proved Reserves
--------------- ----------------- ---------------
2004 24,634 29,548 24,634
2005 17,535 24,829 17,446
2006 14,504 18,473 14,209
2007 13,975 16,194 13,487
2008 7,383 12,280 7,049
Remainder 45,195 55,552 39,299
--------- --------- ---------
Total Undiscounted 123,226 156,876 116,124
========= ========= =========
Total Discounted at 10% 83,033 106,285 80,566
The source of funding for future development costs will be internally
generated cash flow, debt or a combination of both. Disclosed reserves and
future net revenue will not be materially affected by the costs of funding the
future development expenditures.
Other Oil and Gas Information
Oil And Gas Wells
The following table sets forth the number and status of wells in which
PC has a working interest as at December 31, 2003.
Oil Wells Natural Gas Wells
------------------------------------- ------------------------------------
Producing Non-Producing Producing Non-Producing
---------------- ---------------- ---------------- ---------------
Gross Net Gross Net Gross Net Gross Net
----- ----- ----- ----- ----- ----- ----- -----
Alberta 2,618 392.4 762 172.5 845 256.1 187 105.5
British Columbia 88 23.2 69 11.0 244 37.8 71 13.6
Manitoba 121 114.8 51 49.1 0 0.0 0 0.0
Saskatchewan 1,592 525.1 237 34.2 341 298.5 16 9.3
----- ------- ----- ----- ----- ----- --- -----
Total 4,419 1,055.5 1,119 266.8 1,430 592.4 274 128.4
===== ======= ===== ===== ===== ===== === =====
Properties with no Attributable Reserves
The following table sets out PC's undeveloped land holdings as at
December 31, 2003.
Undeveloped Acres
-----------------------------
Gross Net
----------- ----------
Alberta 311,218 150,319
British Columbia 132,701 44,346
Manitoba 1,201 1,181
Saskatchewan 89,469 54,663
------- -------
Total 534,589 250,509
======= =======
There are no material work commitments on the undeveloped land
holdings.
PC expects that rights to explore, develop and exploit 48,680 net acres
of its undeveloped land holdings will expire by December 31, 2004.
B-35
36
Additional Information Concerning Abandonment and Reclamation Costs
Future abandonment and reclamation costs have been estimated based on
actual costs incurred to date by PC for abandonment and reclamation activities.
Costs to abandon and reclaim approximately 2,040 net wells totaling $61.6
million net of salvage value ($26.0 million discounted at 10%) are included in
the estimate of future net revenue. Facility abandonment costs of $20.7 million
($3.1 million discounted at 10%) are not included in the estimate of future net
revenue. Abandonment and reclamation costs estimated for the next three years
are $4.3 million in 2004, $4.1 million in 2005 and $3.3 million in 2006.
Forward Contracts
For details of material commitments to sell natural gas and crude oil
which were outstanding at December 31, 2003, see Note 14 to the Trust's audited
consolidated financial statement for the year ended December 31, 2003, which
Note is incorporated herein by reference.
Tax Horizon
Under its existing trust structure, PC does not pay income tax because
the tax liability is transferred to the individual Unitholders.
Capital Expenditures
The following tables summarize capital expenditures (net of incentives
and net of certain proceeds and including capitalized general and administrative
expenses) related to PC's activities for the year ended December 31, 2003:
(M$)
-----------
Property acquisition costs
Proved properties $82,100
Undeveloped properties 1,700
Exploration costs 5,700
Development costs 64,000
--------
Total $153,500
========
Exploration and Development Activities
The following tables sets forth the gross and net exploratory and
development wells in which PC participated during the year ended December 31,
2003:
Working Interest Wells
Development Wells Exploration Wells
------------------- -------------------
Gross Net Gross Net
--------- ------- --------- -------
Oil 74 7.9 6 1.5
Gas 110 80.2 5 1.9
Service 4 2.2 0 0
Dry 7 1.5 8 3.7
--- ---- -- ---
Total: 195 91.8 19 7.1
=== ==== == ===
B-36
37
Farm-out Wells
Development Exploration
Wells Wells
---------------------------------
Oil 2 1
Gas 10 22
Service 0 0
Dry 1 4
---- ----
Total: 13 27
==== ====
PC's most important current and likely exploration and development
activities are described under "Business and Properties".
Production Estimates
The following table sets out the gross volume of PC's production
estimated for the year ended December 31, 2004 which is reflected in the
estimate of future net revenue disclosed in the tables contained under
"Disclosure of Reserves Data" using constant prices and costs.
Light and Medium Natural Gas
Oil Heavy Oil Natural Gas Liquids BOE
(bpd) (bpd) (mcfpd) (bpd) (boepd)
---------------- --------- ----------- ----------- ---------
Proved Producing 10,381 333 74,091 2,020 25,083
Total Proved 10,745 333 76,739 1,899 25,767
Proved plus Probable 11,088 340 78,077 1,921 26,361
Production History
The following tables summarize certain information in respect of
production, product prices received, royalties paid, operating expenses and
resulting netbacks of PC for the periods indicated below:
Quarter Ended
--------------------------------------
2003
--------------------------------------
Dec. 31 Sept. 30 June 30 Mar. 31
------- -------- ------- -------
Oil Wells(1)
Average Daily Production (boepd) 15,111 14,297 13,005 12,847
Revenue ($/boe) 33.72 36.50 37.32 44.04
Royalties ($/boe) 5.87 6.62 6.55 8.36
Production Costs ($/boe) 11.06 12.85 12.22 10.49
--------------------------------------
Netback ($/boe) 16.79 17.03 18.55 25.19
======================================
Gas Wells(1)
Average Daily Production (mcfepd) 85,660 85,099 84,866 87,384
Revenue ($/mcfe) 5.63 5.77 6.26 7.46
Royalties ($/mcfe) 1.33 1.37 1.51 1.91
Production Costs ($/mcfe) 0.91 1.10 0.97 0.89
--------------------------------------
Netback ($/mcfe) 3.39 3.30 3.78 4.66
======================================
Note:
(1) Principal product type attributable to the wells
B-37
38
SELECTED FINANCIAL AND OPERATING INFORMATION
Consolidated Financial Information
The following is a summary of selected consolidated financial
information of the Trust for the years indicated.
---------------------------------------------------------------------------------------------------------
December 31, 2003 2002 2001(2)
---------------------------------------------------------------------------------------------------------
(MM$, except per unit amounts)
---------------------------------------------------------------------------------------------------------
Total revenues................................. $393.1 $270.7 $244.5
---------------------------------------------------------------------------------------------------------
Royalties, net of incentives................... $ 84.8 $ 50.4 $ 54.8
---------------------------------------------------------------------------------------------------------
Lease operating costs.......................... $ 91.3 $ 74.8 $ 48.2
---------------------------------------------------------------------------------------------------------
Proceeds on disposition of property interests.. $ 33.5 $ 30.0 $ 3.7
---------------------------------------------------------------------------------------------------------
Cash flow from operations...................... $187.6 $112.6 $110.2
---------------------------------------------------------------------------------------------------------
Cash flow available for distribution........... $150.7 $103.1 $110.6
---------------------------------------------------------------------------------------------------------
per Unit - basic...................... $ 2.47 $ 2.07 $ 3.50
---------------------------------------------------------------------------------------------------------
per Unit - diluted.................... $ 2.46 $ 2.06 $ 3.49
---------------------------------------------------------------------------------------------------------
Net income..................................... $ 85.8 $ 24.4 $ 54.0
---------------------------------------------------------------------------------------------------------
Per Unit - basic...................... $ 1.41 $ 0.49 $ 1.71
---------------------------------------------------------------------------------------------------------
Per Unit - diluted ................... $ 1.40 $ 0.49 $ 1.71
---------------------------------------------------------------------------------------------------------
Working Capital (deficit)...................... $(30.0) $(6.9) $(20.6)
---------------------------------------------------------------------------------------------------------
Total assets................................... $943.9 $890.6 $699.3
---------------------------------------------------------------------------------------------------------
Total long-term debt(1)........................ $110.3 $219.2 $145.0
---------------------------------------------------------------------------------------------------------
Unitholders' equity............................ $649.2 $480.1 $398.7
---------------------------------------------------------------------------------------------------------
Weighted average number of Units
outstanding
---------------------------------------------------------------------------------------------------------
Basic ................................ 61.0 49.9 31.6
---------------------------------------------------------------------------------------------------------
Diluted............................... 61.2 49.9 31.6
---------------------------------------------------------------------------------------------------------
Note:
(1) Although the Trust does not have any long term indebtedness, PC does have
long term indebtedness, which is secured against all of PC's assets. The
loan is the legal obligation of PC. While principal and interest payments
are allowable deductions in the calculation of royalty income, the
Unitholders of the Trust have no direct liability to PC's lenders or to PC
should the assets securing the loan generate insufficient cash flow to
repay the obligations.
(2) On July 6, 2001, the Trust Units were consolidated on a one-for-three
basis. All relevant figures, including Trust Units, outstanding net income
per Trust Unit and distributions per Trust Unit have been restated to
reflect this consolidation.
Sensitivity Analysis
In 2003, PC's cash flow from operating activities was $187.6 million,
and net income was $85.8 million. The sensitivity of PC's cash flow and net
income before income taxes to oil price, gas price, $US/$CAN exchange rate, and
the prime interest rate is listed below.
The table below shows sensitivities to pre-hedging cash flow as a
result of product price and operational changes. The table is based on actual
2003 prices received and production volumes of 27,000 boepd. These sensitivities
are approximations only and are not necessarily valid at other price and
production levels. As well, hedging activities can significantly affect these
sensitivities.
B-38
39
--------------------------------------------------------------------------------
$/unit
Change M$ per year
--------------------------------------------------------------------------------
Price per barrel of oil $ 1.00US $ 5,331 $ 0.072
--------------------------------------------------------------------------------
Price per mcf of natural gas $ 0.25Cdn $ 5,585 $ 0.076
--------------------------------------------------------------------------------
US/Cdn exchange rate $ 0.01 $ 2,650 $ 0.036
--------------------------------------------------------------------------------
Interest rate on debt ($125 million) 1% $ 1,250 $ 0.017
--------------------------------------------------------------------------------
Oil production volumes - 100 bpd 1,131 $ 0.015
--------------------------------------------------------------------------------
Gas production volumes - 1 mmcfpd 1,784 $ 0.024
--------------------------------------------------------------------------------
*After adjustment for estimated royalties
--------------------------------------------------------------------------------
Distribution Policy
A major objective of the Trust's distribution policy is to provide
unitholders with relatively stable and predictable monthly distributions despite
potentially significant variations in product prices. A second objective is to
retain a portion of cash flow to fund ongoing development and optimization
projects designed to enhance the sustainability of cash flow.
The percentage of cash flow from operations paid to unitholders each
quarter will vary according to a number of factors assessed by management
including:
o Fluctuations in oil and gas prices
o Changes in the $Canadian/$US exchange rate
o The size of the development drilling programs and the portion
funded from cash flow
o The level of debt within PC.
Although the payout ratio will vary significantly from quarter to
quarter, the objective is to pay to unitholders 80% of cash flow over the long
term. The payout ratio was 70% in 2003 and 75% in 2002. The payout ratio in 2003
ranged between 45% in the first quarter to 92% in the third quarter.
Distributions
The following cash distributions per Trust Unit in respect of the
quarters indicated have been made to Unitholders since 2001:
Cash Distributions
----------------------------------
2003 2002 2001
---- ---- ----
First Quarter $0.48 $0.43 $1.26
Second Quarter 0.53 0.41 1.32
Third Quarter 0.54 0.42 0.93
Fourth Quarter 0.54 0.45 0.73
----- ----- -----
Total Annual $2.09 $1.71 $4.24
===== ===== =====
Product Marketing
Petrofund markets its products to a diverse group of buyers with a
variety of contract terms and lengths as a way to help stabilize distributions
and mitigate the effect of price fluctuations. Forward selling instruments such
as swaps, collars, and floors are used for up to 50 percent of its production,
with the remainder subject to market prices. This marketing strategy is not
intended to make money as a speculation on future commodity prices. The goal of
this hedging program is to improve financial protection and help sustain cash
flow should prices drop.
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During 2003, product prices were impacted by commodity price fluctuations and
the rising value of the Canadian dollar. Crude oil prices were robust throughout
2003 with West Texas Intermediate (WTI) averaging US$ 31.04/bbl in the fourth
quarter, up US$ 2.89/bbl from the same period in 2002. WTI for the year returned
the highest average annual price of US$ 31.04/bbl since 1982. So far in 2004,
product prices have exceeded those realized in the fourth quarter 2003 levels
and are following early 2003 levels in the mid-thirty dollar per barrel range.
Market fundamentals remain strong as US commercial crude inventories
decreased in 2003 to 29-year lows, while the US remains committed to filling the
US Strategic Petroleum Reserve by 2005. Supply additions from OPEC and non-OPEC
were strong in 2003 but incremental demand from the US and China offset the new
supply. Petrofund expects supply growth from non-OPEC and Iraq arising late in
2004 will exceed demand although it should be noted that re-building crude
inventories takes several years to complete. Strong oil prices are also broadly
supported by long-term geopolitical risks that can affect supply and demand.
Petrofund continues to believe that OPEC and other large crude
suppliers will manage supplies to meet demand and that the low inventory levels
actually provide a substantial cushion for any overproduction that might occur
in the short run.
AECO spot natural gas prices were also at record high levels, ending
the year on a strong note closely following US natural gas prices. For the year,
AECO prices averaged $6.70/mcf, up 65 percent from 2002. AECO prices were
strongest early in the year but fourth quarter 2003 prices averaging $5.59/mcf
still exceeded fourth quarter 2002 levels by $.34/mcf, or 6.5 percent. December
2003 AECO gas prices were markedly higher than October and November, and natural
gas prices are tracking rising oil prices in the first quarter of 2004. Basis
differentials between AECO and the Henry Hub widened by $0.05/mcf, to
approximately $0.70/mcf over the year. This level is expected to remain constant
over 2004.
Petrofund believes the fundamentals underpinning natural gas markets
will continue to support attractive price levels for the commodity in North
America. Gas-directed drilling recovered in 2003 as rig counts rose 34 percent
in the US year-over-year to 959 rigs. Canadian gas directed rig counts were only
up 20 percent over the same period. The increased drilling will increase
supplies after the first quarter of 2004; however, growth in the US economy and
natural production declines are expected to absorb the new supply. Liquefied
Natural Gas (LNG) imports to the US increased by upwards of one bcf/d in 2003,
but large scale increases in imports with the potential to impact prices are not
expected until 2005-2007.
Credit Facility
PC has a revolving working capital operating facility of $25 million
and a syndicated facility of $240 million. Interest on the working capital loan
is at prime and interest on the syndicated facility depends on PC's debt to cash
flow ratio and varies from prime to prime plus 75 basis points or, at the
Trust's option, bankers acceptance plus a stamping fee. Substantially all of the
credit facility is financed with banker's acceptances, resulting in an average
reduction in interest rates of 0.50% per annum.
The limit of the syndicated facility is subject to adjustment from time
to time to reflect changes in PC's asset base. PC had long-term debt outstanding
of $110 million at December 31, 2003, compared to $212 million at the end of the
prior year.
The revolving period on the syndicated facility ends on May 28, 2004,
unless extended for a further 364 day period. There are no principal repayments
required during the revolving period. PC may request the facility be extended no
earlier than 90 days and no later than 60 days prior to the end of the revolving
period at which time lenders may extend the facility for an additional one year
period. If the revolving period is not extended, the loan will convert to a one
year term with payments due in three consecutive quarterly amounts equal to
one-
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twentieth of the loan amount with an additional payment due on the last day of
the term period equal to the remaining balance outstanding. In the event that
the revolving period is not extended, the Trust will prepay the required
quarterly instalments into a reserve account.
The credit facility is secured by a debenture in the amount of $350
million under which a Canadian chartered bank, as principal and as agent for the
other lenders, received a first ranking security interest on all of PC's assets.
The loan is the legal obligation of PC. Unitholders have no direct liability to
the lenders or to PC should the assets securing the loan generate insufficient
cash flow to repay the obligation.
Outlook for Next Year
The level of cash flow for 2004 will be affected by oil and gas prices,
the $US/$CAN exchange rate and the Trust's ability to add reserves and
production in a cost effective manner. Both product prices and the exchange rate
showed significant volatility in 2003 and this trend is expected to continue in
2004. The acquisition market is expected to continue to be active and supply
should increase with the recent announcement by three large producers of their
intention to dispose of their Canadian properties in 2004. Nevertheless,
competition for these assets is expected to be fierce due to increased demand
resulting from the increasing number of oil and gas companies that have
converted to a trust structure. We expect prices for quality, long life assets
to be at or near record levels. Petrofund expects to be an active participant in
this market but success will be tempered by commitment to maintain historic
discipline and bid only at levels consistent with the best long term interest of
our unitholders.
Acquisition activities will be complemented by an extensive drilling
and farmout program that will be conducted on our existing land base.
Although product prices have remained at high levels, the strengthening
of the Canadian dollar in the second half of 2003 significantly moderated the
net effect of these prices on Petrofund's cash flow. We expect the Canadian
dollar to remain very strong in the short term with a possible decrease toward
the end of 2004.
Petrofund pursues a well defined risk management program to help offset
the effect of price fluctuations. This program utilizes collars as the main
hedging tool but Petrofund also enters into fixed price transactions when
commodity prices approach historic highs. To date, the Trust has not entered
into any currency related transactions.
ENVIRONMENT, HEALTH AND SAFETY
Petrofund recognizes that our efforts to protect the environment and
the health and safety of our workers and the public are essential to our
continuing success. The Environment, Health and Safety program is designed to
meet four objectives:
o Provide our workers with the tools and training needed to
complete work assignments safely and effectively;
o Identify and manage environmental, health and safety risks as an
integral part of every business activity;
o Monitor performance to ensure that Petrofund operations comply
with our legal obligations and the standards we set for
ourselves, and;
o Identify and manage environmental liabilities associated with our
existing asset base and potential acquisitions.
All employees of Petrofund are responsible and accountable for ensuring
that we manage environmental protection and health and safety responsibilities
properly. Senior Management ensures work places are healthy and safe and workers
know and understand Petrofund's environment, health and safety operating
standards and expectations. Supervisors ensure that activities at our workplaces
meet or exceed our standards and regulatory
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requirements. Each employee is responsible for working safely, maintaining a
healthy workplace and conducting their activities with respect for other people
and the environment. Collectively, we strive to continually improve our
performance and reduce the potential risks of our operations to people and the
environment.
Managing Liabilities
Liability management is a cornerstone of Petrofund's environmental
protection and restoration activities. We closely monitor our site abandonment
and reclamation liabilities. We have taken steps to properly abandon well sites
and facilities and restore the land at locations that have reached the end of
their economic life. In 2003, Petrofund abandoned 70 wells and continued
restoration work at over 350 sites across Western Canada. By the end of 2003,
Petrofund successfully completed restoration work at over 80 sites and began the
process of submitting the necessary documentation to our regulators to obtain
reclamation certificates. In order to eliminate the environmental and financial
liabilities of non-producing assets, Petrofund actively manages its abandonment
and site restoration program. The goal is to minimize the cycle time between the
initial abandonment and the final restoration.
Petrofund is also committed to fully assessing potential environmental
liabilities associated with wells and facilities that may be candidates for
acquisition. We review records held by governments and owners, and conduct
inspections of the assets to assure ourselves that we are aware of the
conditions at each site and the costs to restore these locations to meet
government imposed environmental standards. The objective is to provide a
realistic assessment of the liabilities associated with potential asset
acquisition candidates and provide management with a factual basis to negotiate
purchase terms and conditions. In 2003, Petrofund conducted 2 major and 2 minor
reviews of potential acquisition opportunities as part of our due diligence
process.
Stewardship
In 2003, Petrofund initiated a formal third party environmental
compliance and best practices audit program to assure management and unitholders
that our field operations meet or exceed regulatory requirements and our
internal operating standards. We will conduct formal assessments of compliance
with regulations and operating standards at our major properties every three
years. Assessments were completed at 85 active sites in 13 producing fields in
Alberta this past year. Our insurer conducts a safety audit/risk survey of our
operations and a cross section of our field facilities each year. In 2003, seven
facilities in three fields in Alberta were included in the safety audit program.
The results of these audits have confirmed that our facilities are
operated and maintained at or above industry standards and that our field staff
are knowledgeable and give workplace health and safety, and environmental
protection a high priority in their operations. The audit findings have been
incorporated into our on-going environment, health and safety program planning
to better manage potential risks to people and the environment.
These external audits complement Petrofund's long standing site
inspection program where field operating staff formally inspect each producing
well and facility twice per year. These inspections not only identify real or
potential environmental and safety risks at each location but they also serve to
remind workers of the importance placed on these aspects of our business.
Corporate Citizenship
In 2003, Petrofund embarked on major projects to identify the sources
and volumes of greenhouse gas emissions and other air contaminants from
producing facilities. These studies will be used to confirm compliance with
provincial and federal air quality guidelines, contaminant emission regulations,
and possible requirements to meet Canada's potential greenhouse gas emission
reduction commitments under the Kyoto protocol. These
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investigations will also assist us in establishing priorities for planning
upgrades to our facilities to improve energy efficiency across operations.
Petrofund continues to review environmental, health and safety programs
and commitments to ensure that we are positioned to address the increasing
public expectation of higher levels of performance. We understand and accept our
responsibility for developing and maintaining superior environment, health and
safety standards and performance levels to sustain public trust and the
confidence of regulators everywhere we operate.
CORPORATE GOVERNANCE
The relationship between the Board and the management of Petrofund is
grounded in a mutual understanding of respective roles and the ability of the
Board to act independently while fulfilling its responsibilities. Further, the
Board's involvement in strategic planning recognizes that the role of directors
is not to manage but to guide management. The board oversees and monitors
systems for managing business risk and regularly reviews strategic plans with
management. Petrofund is in full compliance with the corporate governance
standards outlined by the TSX.
Petrofund has actively sought men and women with a diversity of
experience and competencies to add value to boardroom deliberations. In 2003,
the Board increased in size by one directorship with a view to increase overall
effectiveness and improve decision making. In keeping with best practices, the
Board separated the role of Chairman and Chief Executive Officer in early 2003.
The Board acknowledges the critical role they must play in choosing the Chief
Executive Officer and in contributing to and continually assessing Petrofund's
strategic direction. All directors are elected by unitholders. Voting for
directors is conducted during Petrofund's annual general meeting.
In addition to those matters which must be approved by the Board of
Directors by law, significant business activities and actions proposed to be
undertaken by Petrofund are subject to Board approval. The Board of Directors
approves appropriate corporate objectives and recommended courses of action
which have been brought forward by the Chief Executive Officer and management
Independence of the Board
The Board currently comprises seven members. Five of the seven are
unrelated directors within the context and meaning outlined within TSX
Guidelines. The responsibility for ensuring that individual directors are
unrelated rests with the Board of Directors. The Board will ensure that
Petrofund discloses on an annual basis the number of related and unrelated
directors.
Petrofund has instituted a formal orientation program intended to
further assist new Board members in familiarizing themselves with Petrofund's
field operations, management, administration, policies and plans.
All members of the Board of Directors, with the exception of Mr. Errico
and Mr. Driscoll, are unrelated. All Board committees consist entirely of
unrelated directors.
Committees
The Board has four committees; the Governance Committee, the Human
Resources & Compensation Committee, the Reserves Audit Committee and the Audit
Committee. The committees have formal written mandates based on the council of
outside advisors and approved by the Board of Directors. These mandates reflect
current 'best practices' concerning committee mandates. The committees review
these mandates and work processes at least annually; taking into account changes
in regulatory and other appropriate requirements or practices, and propose
changes as appropriate to the Board of Directors for its approval. All
committees have the right to retain independent advisors at the expense of
Petrofund.
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Governance Committee
The Governance Committee comprises Sandra S. Cowan (Chairman), Frank
Potter and Peter N. Thomson. The Committee has the responsibility of reviewing
the Board's size, composition and working processes and proposing changes to the
Board for its consideration. It has the responsibility for assessing the
performance of the Board, its committees, and individual directors. It
recommends to the Board at least annually and at such other times as it sees
fit, the composition of board committees and the chairmanship of such
committees. A component of the Committee's mandate is the responsibility for
considering and proposing nominations to the Board, should such nominations be
required. It reviews director compensation at least annually, and recommends
changes as it sees fit to the Board for its approval.
Human Resources and Compensation Committee
The Human Resources and Compensation Committee comprises Frank Potter
(Chairman), Sandra S. Cowan and Wayne M. Newhouse. The Committee is responsible
to the Board for overseeing the development and administration of competitive
policies designed to attract, develop and retain employees of the highest
standards at all levels. It recommends to the Board appropriate policies dealing
with recruitment, compensation, benefits and training, and oversees the
administration of succession planning. It is responsible for recommending to the
Board the compensation arrangements for individual senior officers, in
consultation with the Chief Executive Officer.
Reserves Audit Committee
The Reserves Audit Committee comprises Wayne M. Newhouse (Chairman),
James E. Allard and Peter N. Thomson. The Committee oversees the integrity of
Petrofund's reserve estimates. Contained within the Committee mandate is the
responsibility to ascertain those procedures and policies which minimize
environmental, occupational and safety risks to asset value thereby mitigating
any potential damage to or deterioration of asset value. It meets at least
annually, and such other times as it sees fit. It meets with Petrofund's
independent engineering consultants, and does so at least once per year.
Audit Committee
The Audit Committee comprises James E. Allard (Chairman), Frank Potter
and Peter N. Thomson. All listed committee members possess the requisite
financial skills necessary to qualify them as committee directors. Additionally,
Mr. Allard fulfills the requirement for financial sophistication, having served
as Chief Executive Officer and Chief Financial Officer for several private and
publicly traded companies throughout a lengthy career.
SHARE CAPITAL OF PC
PC's authorized capital is comprised of an unlimited number of common
shares and an unlimited number of PC Exchangeable Shares.
Common Shares
PC has authorized for issuance an unlimited number of common shares of
which, as at February 27, 2004, two common shares are issued and outstanding and
held by Computershare Trust Company of Canada, as trustee of the Trust. The
holders of common shares are entitled to notice of, to attend and to one vote
per share held at any meeting of the shareholders of PC (other than meetings of
a class or series of shares of PC other than the common shares as such). The
holders of common shares are entitled to receive dividends as and when declared
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by the Board of Directors of PC on the common shares as a class, and subject to
prior satisfaction of all preferential rights to dividends attached to all
shares of other classes of shares of PC ranking in priority to the common shares
in respect of dividends, to share rateably, together with the shares of any
other class of shares of PC ranking equally with the common shares in respect of
dividends. The holders of common shares are entitled to in the event of any
liquidation, dissolution or winding up of PC, whether voluntary or involuntary,
or any other distribution of the assets of PC among its shareholders for the
purpose of winding up its affairs, and subject to prior satisfaction of all
preferential rights to return of capital on dissolution attached to all shares
of other classes of shares of PC ranking in priority to the common shares in
respect of return of capital on dissolution, to share rateably, together with
the shares of any other class of shares of PC ranking equally with the common
shares in respect of return of capital on dissolution, in such assets of PC as
are available for distribution.
Exchangeable Shares
PC has authorized to issue an unlimited number of PC Exchangeable
Shares, of which, as at February 27, 2004, 851,471 PC Exchangeable Shares are
issued and outstanding. The PC Exchangeable Shares rank prior to the common
shares of PC and any other shares ranking junior to the PC Exchangeable Shares
with respect to the payment of dividends and the distribution of assets in the
event of the liquidation, dissolution or winding up of PC, whether voluntary or
involuntary, or any other distribution of the assets of PC among its
shareholders for the purpose of winding up its affairs. Provided that same is
declared during the Dividend Period, holders of PC Exchangeable Shares are
entitled to receive, as and when declared by the board of directors of PC in its
sole discretion, from time to time, non cumulative preferential cash dividends
in an amount per share equal to the amount of the Distribution relating to the
subject Distribution Payment Date multiplied by the Exchange Ratio as at the
subject Distribution Payment Date. It is not anticipated that dividends will be
declared or paid on the PC Exchangeable Shares; however, the board of directors
of PC has the right in its sole discretion to do so.
PC will not, without obtaining the approval of the holders of the PC
Exchangeable Shares as set forth below:
(a) pay any dividend on the common shares of PC or any other shares
ranking junior to the PC Exchangeable Shares, other than stock
dividends payable in common shares of PC or any such other shares
ranking junior to the PC Exchangeable Shares;
(b) redeem, purchase or make any capital distribution in respect of
the common share of PC or any other shares ranking junior to the
PC Exchangeable Shares;
(c) redeem or purchase any other shares of PC ranking equally with
the PC Exchangeable Shares with respect to the payment of
dividends or on any liquidation distribution; or
(d) issue any shares, other than PC Exchangeable Shares or common
shares of PC, which rank superior to the PC Exchangeable Shares
with respect to the payment of dividends or on any liquidation
distribution.
In the event that a dividend is not declared by PC prior to the expiry
of a Dividend Period, each holder of PC Exchangeable Shares shall have the
right, exercisable for a period of 5 business days from the date of expiry of
the subject Dividend Period, to redeem such number of PC Exchangeable Shares
(the "Cash Retracted Shares") as have a value (calculated as the amount equal to
the Exchange Ratio as at the date of delivery of the notice of the holder to
retract multiplied by the Current Market Price) equal to the aggregate amount of
the dividend which would have been paid to the holder had a dividend been
declared and paid in respect of the subject Dividend Period (the "Aggregate
Dividend Amount") for an amount in cash equal to the Aggregate Dividend Amount.
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A holder of PC Exchangeable Shares is entitled at any time to exchange
each PC Exchangeable Share into the number of Trust Units equal to the Exchange
Ratio then in effect.
The PC Exchangeable Shares provide holders with a security having
economic, ownership and voting rights which are substantially equivalent to
those of Trust Units. The PC Exchangeable Shares are maintained economically
equivalent to the Trust Units by the progressive increase in the Exchange Ratio
to reflect distributions paid by the Trust to Unitholders. The PC Exchangeable
Shares are provided equivalent voting rights as unitholders through the PC
Support Voting and Exchange Agreement. Pursuant to the PC Support Voting and
Exchange Agreement, the Trust has issued a Special Voting Unit to Petro Assets,
the holder of the PC Exchangeable Shares. The Special Voting Unit entitles Petro
Assets to such number of votes, exerciseable at any meeting at which unitholders
are entitled to vote, equal to the Aggregate Equivalent Vote Amount.
At any time on or after April 29, 2010, or at any time on or after the
date when the aggregate number of issued and outstanding PC Exchangeable Shares
is less than 100,000, holders of PC Exchangeable Shares may be required by PC to
sell all of the then outstanding PC Exchangeable Shares in exchange for the
payment of either cash, PC Exchangeable Shares or that number of Trust Units
determined by multiplying the number of PC Exchangeable Shares by the Exchange
Ratio then in effect.
The PC Exchangeable Shares are convertible, at the option of the holder
thereof, into common shares of PC, on a one for one basis (the "Conversion
Right"). Pursuant to the provisions of the Unanimous Shareholders Agreement,
Petro Assets has agreed never to exercise the Conversion Right in respect of any
PC Exchangeable Shares held thereby.
MANAGEMENT'S DISCUSSION AND ANALYSIS
The Trust's Management's Discussion and Analysis, filed with the
Trust's audited consolidated financial statements for the year ended December
31, 2003, is incorporated by reference herein.
RISK FACTORS
The following are certain risk factors relating to the business of the
Trust which prospective investors should carefully consider before deciding
whether to purchase Trust Units.
Industry-Related Risks
Oil and Natural Gas Prices
The monthly cash distributions the Trust pays to Unitholders are highly
dependent on the prices received for PC's oil and natural gas production. Oil
and natural gas prices can fluctuate widely on a month-to-month basis in
response to a variety of factors that are beyond the control of the Trust and
PC. These factors include, among others:
o political conditions throughout the world;
o worldwide economic conditions;
o weather conditions;
o the supply and price of foreign oil and natural gas;
o the level of consumer demand;
o the price and availability of alternative fuels;
o the proximity to, and capacity of, transportation facilities;
o the effect of worldwide energy conservation measures; and
o government regulations.
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Declines in oil or natural gas prices will have an adverse effect on
the Trust's operations, financial condition, reserves and ultimately on its
ability to pay distributions to Unitholders.
Oil prices were fairly strong throughout 2003 averaging US$31.04 WTI as
compared to and average of US$26.08 WTI in 2002. The only quarter in the last
two years that saw relatively low prices was the first quarter of 2002 when oil
prices averaged US$21.64 WTI.
Monthly AECO prices averaged $6.71/mcf in 2003 as compared to $4.07/mcf
in 2002, an increase of 65%. The AECO gas price was weak throughout the first
nine months of 2002 averaging $3.67/mcf; however, increased significantly to
$5.26/mcf in the fourth quarter. The monthly AECO price in 2003 ranged from a
high of $10.13/mcf in March to a low of $5.48/mcf in November.
Foreign Currency Exchange Rates and Interest Rates
World oil prices are quoted in United States dollars and the price
received by Canadian producers is therefore affected by the $US/$CAN exchange
rate that may fluctuate over time. A material increase in the value of the
Canadian dollar, which occurred in 2003, negatively impacted PC's net production
revenue and may affect the future value of the Trust's reserves as determined by
independent evaluations at this time. The impact is reduced to the extent that
PC has engaged in, or in the future will engage in risk management activities
related to commodity prices and foreign exchange rates. PC will be subject to
unfavourable price changes and credit risks associated with the counterparties
with which it contracts. PC has not entered into any foreign exchange contracts
at this time.
Variations in interest rates could result in a significant increase in
the amount the Trust pays to service debt which may result in a decrease in
distributions to Unitholders.
Operations
PC's operations are subject to all of the risks normally associated
with drilling for and the production and transportation of oil and gas. Such
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, property damage and environmental damage. Although PC has safety
and environmental policies in place to protect operators and employees, as well
as to meet regulatory requirements, and although PC has liability insurance
policies in place, PC cannot fully insure against all such risks, nor are all
such risks insurable. PC may become liable for damages arising from such events
against which it cannot insure or against which we may elect not to insure
because of high premium costs or other reasons. Costs incurred to repair such
damage or pay such liabilities will reduce payments made by PC to the Trust.
Competition
There is strong competition relating to all aspects of the oil and gas
industry. 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
those 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
world wide basis and as such have greater and more diverse resources to draw on.
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Environmental Concerns
The oil and natural gas industry is subject to extensive environmental
regulation pursuant to local, provincial and federal legislation. A breach of
such legislation may result in the imposition of fines or issuance of clean up
orders. Such legislation may be changed to impose higher standards and
potentially more costly obligations. Although PC has established a reclamation
fund for the purpose of funding its estimated future environmental and
reclamation obligations based on its current knowledge, there can be no
assurance that PC will be able to satisfy its actual future environmental and
reclamation obligations.
While PC has established a reserve for extraordinary and significant
site reclamation or abandonment costs, actual abandonment costs incurred in the
ordinary course of business during a specific period will reduce the amounts
available for distribution to Unitholders.
Although PC maintains insurance coverage considered to be customary in
the industry, it 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 (compared to sudden and catastrophic damages) is not
available. Accordingly, PC's properties may be subject to liability due to
hazards which cannot be insured against, or have not been insured against due to
prohibitive premium costs or for other reasons. In such an event, these
environmental obligations will be funded out of PC's cash flow and could
therefore reduce distributable income payable to Unitholders.
Business-Related Risks
Reserves
The value of the Trust Units will depend upon, among other things, the
reserves attributable to PC's properties. Estimating reserves is inherently
uncertain. Ultimately, actual production, revenues and expenditures for PC's
properties will vary from estimates and those variations could be material. The
reserve and cash flow information contained in this annual information form
represent estimates only. Reserves and estimated future net cash flow from PC's
properties have been independently evaluated at the dates indicated by
independent firms of oil and gas reservoir engineers. These firms consider a
number of factors and make assumptions 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 the assumed effect of governmental regulation;
o assumptions about future commodity prices, production and
development costs, severance and excise taxes, and capital
expenditures;
o initial production rates;
o production decline rates;
o ultimate recovery of reserves;
o timing and amount of capital expenditures;
o marketability of production;
o future prices of oil and natural gas;
o operating costs and royalties; and
o other government levies that may be imposed over the producing
life of reserves.
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These factors and assumptions were based on prices at the date the
relevant evaluations were prepared. If these factors and assumptions prove to be
inaccurate, the actual results may vary materially from the reserve estimates.
Many of these factors are subject to change and are beyond the Trust's control.
For example, evaluations are based in part on the assumed success of
exploitation activities intended to be undertaken in future years. Actual
reserves and estimated cash flows will be less than those contained in the
evaluations to the extent that such exploitation activities do not achieve the
level of success assumed in the evaluations. Furthermore, cash flows may differ
from those contained in the evaluations depending upon whether capital
expenditures and operating costs differ from those estimated in the evaluations.
Depletion of Reserves
The Trust has certain unique attributes which differentiate it from
other oil and gas industry participants. Distributions by the Trust, absent
commodity price increases or cost effective acquisition and development
activities, will decline. The Trust will not be reinvesting cash flow in the
same manner as other industry participants. Accordingly, absent capital
injections and acquisition and development activities, the Trust's production
levels and reserves will decline.
PC's reserves and production, and therefore its cash flows, will be
highly dependent upon its success in exploiting its reserve base and acquiring
additional reserves. Without reserve additions through acquisition or
development activities, PC's reserves and production will decline over time as
reserves are exploited.
To the extent that external sources of capital, including the issuance
of additional Trust Units, become limited or unavailable, the Trust's ability to
make the necessary capital investments to maintain or expand reserves will be
impaired.
Even if the Trust does obtain the necessary capital, there is no
assurance of success in developing or acquiring additional reserves on terms
that meet the Trust's investment objectives.
Marketability of Production
The marketability of PC's production depends in part upon the
availability, proximity and capacity of gas gathering systems, pipelines and
processing facilities. Canadian federal and provincial, as well as U.S. federal
and state, regulation of oil and gas production and transportation, tax and
energy policies, general economic conditions, and changes in supply and demand
all could adversely affect PC's ability to produce and market oil and natural
gas. If market factors dramatically change, the financial impact on the Trust's
business could be substantial. The availability of markets is beyond PC's
control.
Assessments of Value of Acquisitions
Acquisitions of resource issuers and resource assets will be based in
large part on engineering and economic assessments made by independent
engineers. These assessments will include a series of assumptions regarding such
factors as recoverability and marketability of oil and gas, future prices of oil
and gas and operating costs, future capital expenditures and royalties and other
government levies which will be imposed over the producing life of the reserves.
Many of these factors are subject to change and are beyond PC's control. In
particular, the prices of and markets for resource products may change from
those anticipated at the time of making such assessment. In addition, all such
assessments involve a measure of geologic and engineering uncertainty which
could result in lower production and reserves than anticipated. Initial
assessments of acquisitions may be based on reports by a firm of independent
engineers that are not the same as the firm that PC uses for its year end
reserve evaluations. Because each of these firms may have different evaluation
methods and approaches, these initial assessments may differ significantly from
the assessments of the firm used by PC. Any such instance may offset the return
on and value of the Trust Units.
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Reliance on Third Party Operators
Continuing production from a property and marketing of product produced
from the property are dependent to a large extent on the ability of the operator
of the property. PC currently operates properties that represent approximately
50% of its total daily production. To the extent the operator fails to perform
these functions properly or becomes insolvent, revenue may be reduced.
Enforcement of Operating Agreements
Operations of the wells on properties not operated by PC are generally
governed by operating agreements, which typically require the operator to
conduct operations in a good and workmanlike manner. Operating agreements
generally provide, however, that the operator will have no liability to the
other non-operating working interest owners for losses sustained or liabilities
incurred, except such as may result from gross negligence or wilful misconduct.
In addition, third-party operators are generally not fiduciaries with respect to
PC, the Trust or the Unitholders. PC, as owner of working interests in
properties not operated by it, will generally have a cause of action for damages
arising from a breach of such duty. Although not established by definitive legal
precedent, it is unlikely that the Trust or Unitholders would be entitled to
bring suit against third-party operators to enforce the terms of the operating
agreements; thus, Unitholders will be dependent on PC, as owner of the working
interest, to enforce such rights.
Borrowing
PC has secured credit facilities with variable interest rates.
Variations in interest rates and scheduled principal repayments could result in
significant changes in the amount of PC's revenues required to be applied to its
debt service before payment of any amounts to the Trust. Certain covenants
contained in PC's agreements with its lenders may also limit the amounts paid to
the Trust and the distributions paid by the Trust to Unitholders.
PC's lenders have been provided with security over substantially all of
the assets of PC. If PC becomes unable to pay its debt service charges or
otherwise commits an event of default, such as bankruptcy, these lenders may
foreclose on or sell PC's properties. The proceeds of any such sale would be
applied to satisfy amounts owed to PC's lenders and other creditors and only the
remainder, if any, would be available to the Trust.
Although PC believes that the credit facilities are sufficient, there
is no assurance that the amounts available thereunder will be adequate for its
future obligations or that additional funds can be obtained. The syndicated
facility is available on a one year revolving basis. If the revolving period at
which the lenders may extend the facility is not renewed for an additional one
year period, the loan will convert to a one year term with payments due in three
consecutive quarterly amounts equal to one-twentieth of the loan amount with an
additional payment due on the last day of the term equal to the balance
outstanding. If this occurs, PC will have to arrange alternate financing. There
is no assurance that such financing will be available or be available on
favourable terms. Trust distributions may be materially reduced in these
circumstances and the failure to obtain suitable replacement financing may have
a material adverse effect on the Trust.
Delays in Distributions
In addition to the usual delays in payment by purchasers of oil and
natural gas to the operators of PC's properties, and by those operators to PC,
payments between any of these parties may also be delayed by restrictions
imposed by lenders, delays in the sale or delivery of products, delays in the
connection of wells to a gathering system, blowouts or other accidents, recovery
by the operator of expenses incurred in the operation of the properties or the
establishment by the operator of reserves for such expenses. Any of these delays
could adversely affect Trust distributions.
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Unforeseen Title Defects
Although title reviews are conducted prior to any purchase of resource
issuers or resource assets, such reviews do not guarantee that an unforeseen
defect in the chain of title will not arise to defeat PC's title to certain
assets. A reduction of the distributable cash flow of the Trust and possible
reduction of capital could result from such defects.
Accounting Write-Downs as a Result of GAAP
Canadian Generally Accepted Accounting Principles ("GAAP") requires
that management apply certain accounting policies and make certain estimates and
assumptions which affect reported amounts in the consolidated financial
statements of the trust. The accounting policies may result in non-cash charges
to net income and write-downs of net assets in the financial statements. Such
non-cash charges and write-downs may be viewed unfavourably by the market and
result in an inability to borrow funds and/or may result in a decline in the
trust unit price.
Under GAAP, the net amounts at which petroleum and natural gas costs on
a property or project basis are carried are subject to a cost-recovery test
which is based in part upon estimated future net cash flow from reserves. If net
capitalized costs exceed the estimated recoverable amounts, PC will have to
charge the amounts of the excess to earnings. A decline in the net value of oil
and natural gas properties could cause capitalized costs to exceed the cost
ceiling, resulting in a charge against earnings.
Emerging GAAP surrounding hedge accounting may result in non-cash
charges against net income as a result of changes in the fair market value of
hedging instruments. A decrease in the fair market value of the hedging
instruments as the result of fluctuations in commodity prices and foreign
exchange rates may result in a write-down of net assets and a non-cash charge
against net income. Such write-downs and non-cash charges may be temporary in
nature if the fair market value subsequently increases.
Risks Related to the Securities Markets and the Ownership of Trust Units
Nature of Trust Units
The Trust Units do not represent a traditional investment in the oil
and natural gas sector and should not be viewed by investors as shares in PC.
The Trust Units are also dissimilar to conventional debt instruments in that
there is no principal amount owing directly to Unitholders. The Trust Units
represent a fractional interest in the Trust. As holders of Trust Units,
Unitholders do not have the statutory rights normally associated with ownership
of shares of a corporation including, for example, the right to bring
"oppression" or "derivative" actions.
Trading Price of Trust Units
The price per Trust Unit is a function of anticipated Trust Unit
distributions, the properties acquired by the Trust and its ability to effect
long-term growth in the value of the Trust. The market price of the Trust Units
will be sensitive to a variety of market conditions including, but not limited
to, interest rates and the ability of the Trust to acquire suitable oil and
natural gas properties. Changes in market conditions may adversely affect the
trading price of the Trust Units.
Trust Units will have no value when reserves from the properties can no
longer be economically produced or marketed and, as a result, cash distributions
do not represent a "yield" in the traditional sense as they represent both
return of capital and return on investment. Investors in Trust Units will have
to obtain the return of capital invested out of cash flow derived from their
investments in the Trust Units during the period when reserves can be
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economically recovered. Accordingly, there is no assurance that the
distributions Unitholders receive over the life of their investment will meet or
exceed their initial capital investment.
Reliance on Petrofund Corp. and Others
Unitholders are entirely dependent on the management of PC 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 properties and the administration of the Trust. The loss of
the services of key individuals who currently comprise the management team of PC
could have a detrimental effect on the Trust. PC currently operates properties
that represent approximately 50% of its total daily production. Investors who
are not willing to rely on the management of PC should not invest in the Trust
Units.
Unitholder Limited Liability
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 (to the extent that claims are not satisfied by the Trust) in respect
of contracts or undertakings which the Trust enters into and for certain
liabilities arising otherwise than out of contract including claims in tort,
claims for taxes and possibly certain other statutory liabilities. The Trust
Indenture requires that the operations of the Trust be conducted in such a way
as to minimize any such risk and, in particular, where feasible, every written
contract or commitment of the Trust must contain an express disavowal of
liability upon the Unitholders and a limitation of liability to Trust property.
Notwithstanding the terms of the Trust Indenture, Unitholders may not be
protected from liabilities of the Trust to the same extent as a shareholder is
protected from the liabilities of a corporation. It is unlikely, however, that
personal liability will attach in Canada to the holders of Trust Units for
claims arising out of any agreement or contract containing such a disavowal and
limitation of liability. It is also considered unlikely that personal liability
will attach in Canada to the holders of Trust Units for claims in tort, claims
for taxes and possibly certain other statutory liabilities. In the event that a
Unitholder is required to satisfy any obligation of the Trust, such Unitholder
will be entitled to reimbursement from any available assets in the Trust.
Retraction Right
Cash payments for Trust Units surrendered for retraction are subject to
limitations and any notes issued in lieu of a cash payment will not be listed on
any stock exchange and no market is expected to develop for such notes.
Future Dilution
An objective of the Trust is to continually add to its reserves through
acquisitions and through development, and because the Trust does not reinvest
its cash flow, the success of the Trust is in part dependent on its ability to
raise capital from time to time. Holders of Trust Units may also suffer dilution
in connection with future issuances of Trust Units, whether issued pursuant to a
financing or acquisition or otherwise.
Changes in Legislation
There can be no assurance that income tax laws, other laws or
government incentive programs relating to the oil and gas industry, such as the
status of mutual fund trusts and resource allowance, will not be changed in a
manner which will adversely affect the Trust and Unitholders. There can be no
assurance that tax authorities having jurisdiction will agree with how the Trust
calculates its income for tax purposes or that such tax authorities will not
change their administrative practices to the detriment of the Trust or the
Unitholders.
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Changes in the Trust's Status under Tax Laws
Legislative or regulatory changes remain an ongoing risk associated
with the trust units and there can be no assurance that the provisions of the
Tax Act relating to the qualification of the trust as a mutual fund trust will
be maintained in their current form or if changes are implemented how the new
provisions may affect the trust.
Under the trust indenture of the Trust, PC may require declarations as
to the jurisdictions in which beneficial holders of trust units are resident. It
may also make a public announcement advising that it 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 a
not a non-resident of Canada. If, notwithstanding the foregoing, PC determines
that a majority of the trust units are held by non-residents, PC may send a
notice to non-resident holders of trust units, chosen in inverse order to the
order of acquisition or registration or in such other manner as PC may consider
equitable and practicable, requiring them to sell their trust units or a
specified portion thereof within a specified period of not less than 60 days. If
the unitholders receiving such notice have not sold the specified number of
trust units or provided PC with satisfactory evidence that they are not
non-residents within such period, PC may on behalf of such unitholders sell such
trust units and in the interim, may suspend the voting and distribution rights
attached to such trust units. Any such sale shall be made on any stock exchange
on which the trust units are listed and, upon such sale, the affected holders
shall cease to be holders of trust units and their rights shall be limited to
receiving the net proceeds of sale upon surrender of the certificates
representing such trust units.
Should the status of the trust as a mutual fund trust be lost, certain
adverse consequences may arise. The material consequences of losing mutual fund
status are as follows: (1) trust units would not constitute qualified
investments for Exempt Plans upon the trust ceasing to be a mutual fund trust.
Where at the end of any month an Exempt Plan holds trust units that are not
qualified investments, the Exempt Plan must, in respect of that month, pay a tax
under Part XI.1 of the tax Act equal to 1% of the fair market value of the trust
units at the time such trust units were acquired by the Exempt Plan. An RRSP or
RRIF holding trust units that are not qualified investments would become taxable
on the income attributable to the trust units while they are not qualified
investments. RESPs which hold trust units that are not qualified investments may
have their registration revoked by the Canada Customs and Revenue Agency; (2)
the trust would be required to pay a tax under Part XII.2 of the Tax Act in
respect of amounts distributed to non-resident persons if it ceases to be a
mutual fund trust. The payment of Part XII.2 tax by the trust may have adverse
income tax consequences for certain unitholders, since the amount of cash
available for distribution would be reduced by the amount of the tax; (3) the
trust would cease being eligible for the capital gains refund mechanism
available under the tax Act upon ceasing to be a mutual fund trust; (4) units
held by unitholders that are not residents of Canada would become taxable
Canadian property upon the trust ceasing to be a mutual fund trust. Such holders
would be subject to Canadian income tax on any gains realized on a disposition
of units constituting taxable Canadian property; and (5) the trust would be
subject to alternative minimum tax under Part 1 of the Tax Act.
GOVERNANCE OF THE TRUST AND PC
Trust Indenture
General
The Trust is an investment trust created pursuant to the Trust
Indenture and governed by the laws of the Province of Ontario. The Trust has
been established for the purpose of holding royalties granted by PC and
acquiring, directly and indirectly, securities and royalties of oil and gas
companies, oil and gas properties and other related assets.
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An unlimited number of Trust Units are issuable pursuant to the Trust
Indenture. As at December 31, 2003, 73.6 million Trust Units and Trust Units
issuable for PC Exchangeable Shares were issued and outstanding. Each Trust Unit
represents an equal undivided beneficial interest in the assets of the Trust.
Each outstanding Trust Unit is entitled to an equal share of distributions by
the Trust and, in the event of termination of the Trust, the net assets of the
Trust. All Trust Units rank equally. Each Trust Unit entitles the holder thereof
to one vote at all meetings of Unitholders.
An unlimited number of Special Voting Units are also issuable pursuant
to the Trust Indenture. Special Voting Units may only be issued by the Trust in
conjunction with the issuance by the Corporation or an affiliate of exchangeable
shares. Each holder of a Special Voting Unit of record is entitled to vote at
all meetings of Unitholders. The maximum number of votes attached to each
Special Voting Unit shall be that number of Trust Units into which the
exchangeable shares issued in conjunction with the Special Voting Unit and at
that time outstanding are then exchangeable. The holders of Trust Units and the
holder of Special Voting Units vote together as a single class on all matters.
Special Voting Units have the foregoing rights in respect of voting at all
meetings of unitholders but have no other rights and, for greater certainty,
Special Voting Units do not represent a beneficial interest in the Trust. In the
event that exchangeable shares issued in conjunction with a Special Voting Unit
cease to be outstanding, such Special Voting Unit shall be deemed to be
cancelled.
A Special Voting Unit was issued in connection with the Internalization
Transaction to Petro Assets, which company was issued PC Exchangeable Shares
pursuant to the Internalization Transaction.
Trustee
The Trust Indenture provides that the Trustee is required 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, will exercise that degree of care, diligence and skill
that a reasonably prudent trustee would exercise in comparable circumstances.
The Trustee, where it has met its standard of care, will be indemnified
out of the assets of the Trust for any actions, suits or proceedings commenced
against the Trustee in respect of the Trust and for costs, taxes and other
liabilities incurred by the Trustee in respect of the administration or
termination of the Trust but will have no additional recourse against
Unitholders. In addition, the Trust Indenture contains other customary
provisions limiting the liability of the Trustee.
Issuance of Trust Units
The Trust Indenture provides that Trust Units may be issued whether
fully paid or in the context of an offering, on an instalment basis, subject to
the approval of the PC Board of Directors, for the purposes of, among other
things, acquiring, or raising capital to acquire, net royalty interests,
securities of oil and gas companies and oil and gas properties and related
assets. The Trust Indenture also provides that the PC Board of Directors may
also authorize the creation and issuance from time to time of rights, warrants
or options to subscribe for Trust Units or other securities convertible or
exchangeable into Trust Units.
Distributions
The Trust makes monthly cash distributions of the distributable cash
flow received by the Trust in each month. Distributions are made on the last
business day of each month to Unitholders of record as at the close of business
on the tenth business day preceding each such distribution date.
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Retraction Right in Respect of Trust Units
Trust Units are retractable at any time on demand by the holders
thereof upon delivery to the Trust of the certificate or certificates
representing such Trust Units, accompanied by a duly completed and properly
executed notice requesting retraction. Upon receipt of the retraction request by
the Trust, all rights to and under the Trust Units tendered for retraction shall
be surrendered and the holder thereof shall be entitled to receive a price per
Trust Unit (the "Retraction Price") equal to the lesser of: (i) 85% of the
"market price" of the Trust Units on the principal market on which the Trust
Units are quoted for trading during the 10 trading day period commencing
immediately after the date on which the Trust Units were surrendered for
retraction (the "Retraction Date"); and (ii) the "closing market price" on the
principal market on which the Trust Units are quoted for trading on the
Retraction Date.
The aggregate Retraction Price payable by the Trust in respect of any
Trust Units surrendered for retraction during any calendar month shall be
satisfied by way of a cash payment on the last day of the following month;
provided that the entitlement of Unitholders to receive cash upon the retraction
of their Trust Units is subject to the limitations that: (i) the total amount
payable by the Trust in respect of such Trust Units and all other Trust Units
tendered for retraction in the same calendar month shall not exceed $100,000
(provided that such limitation may be waived in the discretion of the Trustee;
(ii) at the time such Trust Units are tendered for retraction the outstanding
Trust Units shall be listed for trading on a Canadian exchange or traded or
quoted on any other market which the Trustee considers, in its sole discretion,
provides representative fair market value prices for the Trust Units; and (iii)
the normal trading of Trust Units is not suspended or halted on any stock
exchange on which the Trust Units are listed (or, if not listed on a stock
exchange, on any market on which the Trust Units are quoted for trading) on the
Retraction Date or for more than five trading days during the 10 day trading
period commencing immediately after the Retraction Date.
If a Unitholder is not entitled to receive cash upon the retraction of
Trust Units as a result of the foregoing limitations, then the Retraction Price
shall, subject to any applicable regulatory approvals, be paid and satisfied by
way of a distribution in specie of debt securities of PC then held by the Trust
(the "PC Notes") having a rate of interest which is no less than the highest
rate of interest charged by the Trust to PC. If the Trust does not hold PC Notes
having a sufficient principal amount outstanding to effect such payment, the
Trust will be entitled to create and, subject to any applicable regulatory
approvals, issue in satisfaction of the Retraction Price its own debt securities
(the "Trust Retraction Notes") having such terms and conditions as the Trustee
may determine and with recourse of the holder limited to the assets of the
Trust.
The retraction right described above will not be the primary mechanism
for holders of Trust Units to dispose of their Trust Units. The PC Notes, Trust
Retraction Notes or other assets which may be distributed in specie to
Unitholders in connection with a retraction will not be listed on any stock
exchange and no market is expected to develop in such PC Notes or Trust
Retraction Notes.
Meetings of Unitholders
The Trust Indenture provides that the following must be approved by
Special Resolution: (i) removing or appointing the Trustee (subject to
exceptions such as the Trustee failing to qualify to act as trustee and
insolvency-related events); (ii) amendments to the Trust Indenture (except as
described under "Governance of the Trust and PC - Trust Indenture - Amendments
to the Trust Indenture"); (iii) amendments to the Royalty Agreement; (iv)
subdivisions or consolidations of Trust Units; (v) the termination of the Trust;
(vi) any matter required to be approved by Special Resolution under the Royalty
Agreement, (vii) the sale of the property of the Trust as an entirety or
substantially as an entirety; (viii) directing the Trustee to exercise, or
refrain from exercising, any power under the Trust Indenture; (ix) directing the
Trustee with respect to legal proceedings in connection with the Trust; and (x)
approving the disposition of properties having a value in excess of 35% of the
asset value of the properties of the Trust.
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The Trust holds meetings of Unitholders on an annual basis for the
purposes of electing the directors of PC.
A meeting of Unitholders may be convened at any time and for any
purpose by the Trustee and must be convened if requested by the holders of not
less than 25% of the Trust Units then outstanding by a written requisition. A
requisition must specify the purpose for which the meeting is to be called.
Amendments to the Trust Indenture
Except as specifically provided otherwise, the Trust Indenture may only
be amended by Special Resolution.
The Trustee is entitled to make certain amendments to the Trust
Indenture without the approval of the Unitholders. These include amendments for
the purposes of ensuring compliance with applicable laws, ensuring the Trust
satisfies the requirements of the Tax Act to be a unit trust and mutual fund
trust, providing additional protection for Unitholders, removing conflicts or
inconsistencies (if such amendment is not detrimental to the interests of the
Unitholders) and correcting ambiguities or errors (provided the rights of the
Trustee and the Unitholders are not prejudiced thereby).
Limitation of Non-Resident Ownership
Under the Trust Indenture, PC may require declarations as to the
jurisdictions in which beneficial holders of Trust Units are resident. It may
also make a public announcement advising that it 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 of Canada. If, notwithstanding the foregoing, PC determines that a
majority of the Trust Units are held by non residents, PC may send a notice to
non resident holders of Trust Units, chosen in inverse order to the order of
acquisition or registration or in such other manner as PC may consider equitable
and practicable, requiring them to sell their Trust Units or a specified portion
thereof within a specified period of not less than 60 days. If the Unitholders
receiving such notice have not sold the specified number of Trust Units or
provided PC with satisfactory evidence that they are non residents within such
period, PC may on behalf of such Unitholders sell such Trust Units and in the
interim, may suspend the voting and distribution rights attached to such Trust
Units. Any such sale shall be made on any stock exchange on which the Trust
Units are listed and, upon such sale, the affected holders shall cease to be
holders of Trust Units and their rights shall be limited to receiving the net
proceeds of sale upon surrender of the certificates representing such Trust
Units.
Termination of the Trust
Unless the Trust is terminated earlier, the Trustee will commence to wind up the
affairs of the Trust on December 31, 2066. If, in the opinion of the Board of
Directors of PC, it would be in the best interests of the Unitholders to wind up
the Trust, the Trust will be wound up. In addition, the Unitholders may, by
Special Resolution, decide to terminate the Trust. Upon a decision to terminate
the Trust, the Trustee will sell the assets of the Trust and distribute the net
proceeds to Unitholders, or wind up the Trust as otherwise directed by the
Unitholders or the Board of Directors.
Borrowing
The Trust and PC may finance the acquisition of securities and
royalties of oil and gas companies, oil and gas properties and related assets
and capital expenditures in respect thereof through the issuance of equity or
debt securities.
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The Trust and PC are also permitted to borrow funds and to grant
security in respect of their assets, in priority to the royalty granted by PC,
for the purposes of financing the purchase of oil and gas properties and related
assets, capital expenditures in respect thereof or the purchase of securities
and royalties of oil and gas companies or to facilitate the repurchase of Trust
Units.
The maximum amount which may be borrowed for such purposes shall not
exceed 40% of the aggregate Asset Value of all properties and other resource
assets (including, where applicable, those being acquired) held by Petrofund, PC
and their subsidiaries and 40% of the net asset value of non-reserve based
assets. "Asset Value" is defined as the present worth of all of the estimated
pre-tax net cash flow from the proved reserves and 50% of the estimated pre-tax
net cash flow from the probable reserves shown in the most recent engineering
report relating thereto, discounted at an annual rate equal to the then current
annual yield of long term (10 year) Government of Canada bonds plus 400 basis
points, subject to a maximum rate of 10% and using escalating price and cost
assumptions.
In calculating the 40% borrowing restriction, amounts borrowed by the
Trust or PC which the Trust or PC has the right to effectively repay or cause to
be repaid through the issuance of Trust Units will not form part of the 40%
borrowing restriction provided the Trust or PC, as applicable, has agreed to
cause payment of such indebtedness to be made through the issuance of Trust
Units prior to the maturity of such indebtedness to the extent necessary to
ensure that the aggregate borrowings of the Trust and PC do not then exceed the
40% borrowing restriction.
PC Unanimous Shareholder Agreement
On the completion of the Internalization Transaction, the Unanimous
Shareholder Agreement was terminated. As a result of such termination the
Unitholders now have the right to designate all of the nominees to be elected to
the Board of Directors of PC.
The Trust is to hold meetings on an annual basis for the purposes of
implementing the appointment of such directors.
The Unanimous Shareholder Agreement provided for the establishment of
the Executive Committee of the Board of Directors of PC comprised of three
members, two of whom will be directors of PC nominated by Unitholders and one of
whom will be a director nominated by NCEP Management. Any decision with respect
to the following matters were to be approved by the Board of Directors and the
Executive Committee to be effective:
(a) any acquisition or disposition of oil and gas properties or other
assets by the Trust or PC in excess of $10 million;
(b) any borrowing of funds or granting of security in oil and gas
properties or other assets held by the Trust or PC; and
(c) any related party transaction proposed to be entered into by the
Trust or PC, including any amendment to or other matter involving
the Management Agreement.
On the completion of the Internalization Transaction, the Executive
Committee was terminated and the above matters have to be approved by the board
of Directors.
Royalty Agreement
Under the Royalty Agreement, PC grants net royalties to the Trust of
99% of the revenue received in respect of each property held by PC net of
certain related costs and expenses.
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The net royalty consists of a 99% share of the royalty income from PC's
properties. Net royalty income is gross production revenue less the following
amounts:
o operating costs;
o debt service charges;
o general and administrative costs;
o management fees;
o taxes or other charges payable by PC; and
o amounts paid into the cash reserve established by PC to fund the
payment of operating costs, capital expenditures, reclamation
obligations, general and administrative costs, management fees
and debt service charges.
Gross production revenues essentially consist of cash proceeds from the
sale of oil, natural gas and other substances produced from PC's properties, any
drilling credits resulting from any expenditures made on the properties (other
than drilling credits applied to capital expenditures), amounts arising out of
"take or pay" contracts for oil, gas and other products and any other
consideration received by PC as a result of its ownership of the properties with
the exception of revenues from the rental, sale or exchange of tangible assets
and the proceeds from any unitization or pooling equalization payments relating
to tangible assets and excluding the proceeds from the sale of any properties.
Operating costs are all expenditures from or allocated to a property
made in connection with the maintenance of a property or any activities related
to producing, gathering, treating, storing, compressing, processing and
transporting oil, gas and other substances including, without limitation,
overriding royalties and lessors' royalties.
PC is required to pay the royalty on the last business day of each
month.
The properties in respect of which the Trust has net royalties may be
encumbered by security granted by PC to secure its loan obligations. The
obligations of PC to pay net royalties to the Trust are not secured. Borrowings
are subject to the 40% borrowing restriction referred to under "Governance of
the Trust and PC - Trust Indenture - Borrowing".
The Royalty Agreement provides that the sale of a property and the
royalty thereto shall be approved by the PC Board of Directors, if the sale
proceeds exceed $10,000,000.
Management Agreement
The Unitholders approved the Internalization Transaction at the annual
and special meeting held on April 16, 2003, and in connection with the
Internalization Transaction, PC acquired all of the shares of NCEP Management
and the external management contract of Petrofund as described below and all
related fees were eliminated.
Pursuant to the Management Agreement, NCEP Management was compensated
for providing services to PC and Petrofund. As a result of the completion of the
Internalization Transaction, no fees were payable to the NCEP Management under
the Management Agreement in respect of the period commencing on January 1, 2003
to the closing date, April 29, 2003. The NCEP Management received a quarterly
fee paid on the last business day of each quarter of each year equal to 3.25%
(reduced from 3.75%, effective January 1, 2002) of the sum of net production
revenue less Crown royalties and other Crown charges attributable to PC's
properties for the applicable quarterly period. In addition the NCEP Management
received acquisition fees equal to 1.5% (reduced from 1.75%, effective January
1, 2002) of the purchase costs of all oil and gas properties, oil and gas
companies and other related assets acquired by PC, other than replacement
properties. In the event that PC properties were
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sold, NCEP Management also received disposition fees of 1.25% (reduced from
1.5%, effective January 1, 2002) of the sale price of the properties sold.
PC is entitled to a residual 1% interest in the properties. The
management fee and investment fee were paid in part, firstly, by applying any
income received by PC in respect of its residual interest in the properties and,
secondly, by applying any interest income of PC relating to the proceeds or
revenue from the properties.
NCEP Management was also entitled to be reimbursed by PC for general
and administrative costs and by Petrofund for trust expenses. PC was not
responsible for the payment in any fiscal year of Petrofund of general and
administrative costs in excess of the greater of (a) 5% of the gross production
revenue for such fiscal year and (b) $240,000. To the extent that general and
administrative costs paid by PC for any fiscal year of Petrofund exceed such
maximum amount, PC was entitled to set off and deduct such excess amount from
its liability to pay management fees to NCEP Management.
UNITHOLDER PROTECTION RIGHTS PLAN
The Trust has entered into an agreement with Computershare Trust
Company of Canada dated May 14, 1999 creating a unitholder protection rights
plan (the "Rights Plan"). The Rights Plan was approved by the Unitholders at a
meeting held on November 12, 1999.
The Rights Plan utilizes the mechanism of the Permitted Bid (as
hereinafter described), to ensure that a person seeking control of the Trust
gives the Trust sufficient time in which to evaluate the bid, negotiate with the
initial bidder and encourage competing bids to emerge. The purpose of the Rights
Plan is to protect Unitholders by requiring all potential bidders to comply with
the conditions specified in the Permitted Bid provisions failing which such
bidders will become subject to the dilutive features of the Rights Plan.
Generally, to qualify as a Permitted Bid, a bid must be made to all of
the Unitholders of the Trust and must be open for 60 days after the bid is made.
If more than 50% of the Units held by Independent Unitholders (being Unitholders
other than the bidder, its affiliates and persons acting jointly or in concert
with it) are deposited or tendered to the bid and not withdrawn, the bidder may
take up and pay for such Units. The take-over bid must then be extended for a
further period of 10 business days on the same terms to allow those Unitholders
who did not initially tender their Units to tender to the take-over bid if they
so choose. Thus, there is no coercion to tender during the initial 60-day period
because the bid must be open for acceptance for at least 10 days after the
expiry of the initial tender period.
The term of the Rights Plan is May 14, 2004, which date is five years
from the date of the Rights Plan, May 14, 1999, at which time the right to
exercise a right will terminate, unless it is previously terminated in
accordance with the terms of the Rights Plan.
On May 14, 1999, one right (a "Right") was issued for each Unit
outstanding which is, until the Separation Time (as defined below), evidenced by
a legend imprinted on a certificate for the Units. One Right will also attach to
any subsequently issued Units. The initial exercise price of the Rights is
$60.00 per Unit (the "Exercise Price"), subject to appropriate anti-dilution
adjustments.
The Rights will separate from the Units to which they are respectively
attached and will become exercisable at the time (the "Separation Time") which
is 10 days after the earlier of (i) the announcement that a person has become
the beneficial owner of 20% or more of the Units, other than by an acquisition
pursuant to a Permitted Bid, or (ii) the commencement or announcement date, or
such later date as may be determined by the directors of NCEP Management in
respect of a take-over bid to acquire 20% or more of the Units, other than by an
acquisition pursuant to a Permitted Bid. After the Separation Time and prior to
the occurrence of a Flip-in
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60
Event (as defined below), each Right will entitle the holder thereof to
purchase, upon payment of the Exercise Price, one Unit, subject to anti-dilution
adjustments.
The acquisition by a person (an "Acquiring Person"), including others
acting in concert, of 20% or more of the Units, other than by way of a Permitted
Bid, is referred to as a "Flip-in Event". Any Rights held by an Acquiring Person
on or after the earlier of the Separation Time or the first date of public
announcement by the Trust or an Acquiring Person that an Acquiring Person has
become such, will become void upon the occurrence of a Flip-in Event. Ten
trading days after the occurrence of the Flip-in Event, the Rights (other than
those held by the Acquiring Person) will permit the holder to purchase, upon
payment of the Exercise Price of $60.00, Units with a total market value of
$120.00 (i.e., at a 50% discount).
Until a Right is exercised, the holder of such Right, as such, will
have no rights as a Unitholder of the Trust.
DISTRIBUTION REINVESTMENT AND UNIT PURCHASE PLAN
The Trust has a distribution reinvestment and unit purchase plan (the
"Plan"). The Plan allows Unitholders resident in Canada to acquire additional
Trust Units by reinvesting their cash distributions or by making optional cash
payments. Only Unitholders who are resident in Canada and hold in excess of 100
Trust Units may participate in the Plan. The Plan is not available to
Unitholders who are residents of the United States or other foreign
jurisdictions.
Under the Plan, Unitholders may direct the Trust to reinvest cash
distributions on the Trust Units to acquire, in the discretion of NCEP
Management, existing Trust Units through the facilities of the TSX or newly
issued Trust Units from treasury. In addition, Unitholders may purchase newly
issued Trust Units directly from the Trust by making cash payments to the Trust,
subject to a minimum of $100 and a maximum of $1,000 per calendar quarter.
Cash distributions will be applied to the purchase of Trust Units on
the TSX at prevailing market prices for a period of 10 trading days following
the distribution date. The cost of such Trust Units to participants will be the
average cost of the Trust Units purchased. If insufficient Trust Units are
purchased during the said 10 trading day period, the uninvested portion will be
applied to purchase Trust Units from treasury.
Optional cash payments will be applied to the purchase of newly-issued
Trust Units on the cash distribution date following receipt.
In 2003, the Trust issued 316,785 Trust Units under the Plan.
DIRECTORS AND OFFICERS
Information concerning the directors and officers of PC as of the date hereof is
set out below:
Name and Municipality of Residence Position Director Since
---------------------------------- -------- --------------
John F. Driscoll Chairman and Director July 15, 1988
Toronto, Ontario
Jeffery E. Errico President, Chief April 16, 2003
Calgary, Alberta Executive Officer and
Director
B-60
Name and Municipality of Residence Position Director Since
---------------------------------- -------- --------------
Glen C. Fischer Senior Vice-President,
Calgary, Alberta Operations
Vince P. Moyer Senior Vice-President,
Calgary, Alberta Finance and Chief
Financial Officer
Jeffrey D. Newcommon Executive Vice President
Calgary, Alberta
Noel Cronin Vice-President,
Calgary, Alberta Production
James E. Allard(1)(4) Director April 16, 2003
Calgary, Alberta
Sandra S. Cowan(2)(3) Director January 17, 2002
Toronto, Ontario
Wayne M. Newhouse(3)(4) Director April 16, 2003
Calgary, Alberta
Frank Potter(1)(2)(3) Director November 1, 2000
Toronto, Ontario
Peter N. Thomson(1)(2)(4) Director November 1, 2000
Nassau, Bahamas
Notes:
(1) Member of the Audit Committee.
(2) Member of the Governance Committee.
(3) Member of the Human Resources and Compensation Committee.
(4) Member of the Reserves Audit Committee.
Set forth below are the particulars of the principal occupations of
each director and officer of PC for the past several years.
John F. Driscoll is the Chairman, President, Chief Executive Officer
and a director of Sentry Select Capital Corp. He also founded and has been
Chairman of NCE Resources group since 1984 and Chairman of Petrofund since 1988.
He has also been Chairman of Inter Pipeline Fund and strategic Energy Fund since
October 2002 and May 2002 respectively. He specializes in closed-end funds and
mutual funds and related advisory, management and consulting services. Mr.
Driscoll received his Bachelor of Science degree from the Boston College
Business School in 1964 and in 1967 attended the New York Institute of Finance.
During the last 20 years, issuers of which Mr. Driscoll was responsible as an
officer and/or director or in respect of which he was an officer and/or director
of their managers have raised gross proceeds of approximately $4.0 billion. Mr.
Driscoll also founded and has been President, since 1981, of J.F. Driscoll
Investment Corp., a company specializing in investment management.
B-61
62
Jeffery E. Errico is a Professional Engineer who received a Bachelor of
Science degree in Chemical Engineering from the University of British Columbia
in 1973. He has over 20 years experience in the oil and gas industry, serving as
Vice-President, Operations of Deminex Canada Limited prior to joining NCE
Resources Group in April, 1995.
Glen C. Fischer is a Professional Engineer who received a Degree in
Mechanical Engineering from the University of Calgary. He has over 20 years of
engineering and management experience in the oil and gas industry and from 1984
to 1996 was Manager, Engineering & Operations for ATCOR Ltd. and its successor
Canadian Forest Oil Ltd. Mr. Fischer joined the NCE Resources Group in July,
1996.
Vince P. Moyer received his Chartered Accountant's designation in 1975
and a Master of Business Administration degree in 1972 from the University of
Manitoba, majoring in finance. From 1981 to 1991 he held various positions with
Enron Oil Canada Ltd., including most recently as Vice-President, Finance and
Administration from 1986 to 1991. Mr. Moyer joined the NCE Resources Group in
June, 1991.
Jeffrey D. Newcommon received his Bachelor of Arts degree in Finance
and Economics from the University of Western Ontario in 1983. From 1984 to 1995
he held various positions with Canadian Hunter Exploration Ltd., including, most
recently, Land Manager. He joined the NCE Resources Group in April, 1995.
Noel Cronin is a Professional Engineer with over 20 years of
diversified experience in the petroleum industry in western Canada, including
reservoir management/exploitation, economic evaluations, joint interests and
production operations. He has worked for various Calgary-based oil and gas
producers during his career and joined the NCE Resources Group as Production
Manager in 1997.
James E. Allard has focused his career in international finance and the
petroleum industry for the past 40 years serving as CEO, CFO and director of a
number of publicly traded and private companies during that period. During the
past five years he has continued to serve on the board of the Alberta Securities
Commission, act as the sole external trustee and advisor to a mid-sized pension
plan and serve as a director and advisor to several companies. From 1981 to
1995, he served as a senior executive officer of Amoco Corporation as well as a
director of Amoco Canada, then Canada's largest natural gas producer.
Sandra S. Cowan is Partner and General Counsel of EdgeStone Capital
Partners, an independent private equity firm managing over $1 billion of private
capital. Prior to joining EdgeStone in 2001, Ms. Cowan practiced law for over 15
years, most recently as a senior partner of Goodman and Carr LLP. Her practice
specialized in private equity and corporate finance transactions, including fund
formation, mergers, acquisitions and divestitures, cross-border and public
market transaction. Ms. Cowan has an LLB from the University of Western Ontario
and serves on a number of private and public boards.
Wayne M. Newhouse is a Professional Engineer and Oil and Gas Executive
with over 40 years of broad industry experience. Since 1995 Mr. Newhouse has
served as President of Newhouse Resources Management Ltd. and subsequently
Morgas Ltd., both private oil and gas production companies, as well as being a
director of several publicly traded companies. From 1989 to 1994, Mr. Newhouse
served as Senior Vice President, Production and Senior Vice President,
Exploration and International Development with Norcen Energy Resources Ltd.
Frank Potter has been the Chairman since 1995 of Emerging Markets
Advisors, Inc., a Toronto-based consultancy that assists corporations in making
and managing direct investments internationally. Prior thereto, Mr. Potter was
executive director of The World Bank Group in Washington, and was subsequently
senior advisor at the federal Department of Finance. Mr. Potter is a director of
a number of public and private corporations and public service organizations.
B-62
63
Peter Nesbitt Thomson has been the Chairman of the Board of the West
Indies Power Corporation Limited for over 10 years. He attended Lower Canada
College and Sir George Williams College. He received an honorary Doctorate of
Laws Degree from St. Thomas University, Fredericton, New Brunswick. Beginning
his professional career in Montreal with investment dealer Nesbitt Thomson, he
later was Chairman, President and Chief Executive Officer of Power Corporation
of Canada. He has served as a director of numerous Canadian companies, including
Petrofina Canada Limited and Norcen Energy Resources Ltd.
Ownership of Trust Units by Directors and Officers
As at December 31, 2003, the directors and executive officers of PC
beneficially owned, directly or indirectly, 596,166 Trust Units representing
less than 1% of the issued and outstanding Trust Units and 851,471 PC
Exchangeable Shares representing 100% of the issued and outstanding PC
Exchangeable Shares.
ESCROWED SECURITIES
There are 85,244 Trust Units in escrow which were issued to executive
management in connection with the internalization of management. They are
released evenly each quarter to March 31, 2008. The escrow agent is Goodman and
Carr LLP.
MARKET FOR SECURITIES
The Trust Units are listed and posted for trading on the TSX under the
symbol "PTF.UN" and the American Stock Exchange under the symbol "PTF".
CONFLICTS OF INTEREST
Many of the directors and officers of PC are directors and officers of
other entities which may be in competition to the interests of PC and the Trust.
In the ordinary course of business, these other entities may acquire properties
or explore other business opportunities that may be suitable for Petrofund. No
assurances can be given that opportunities identified by such board members will
be provided to PC and the Trust.
ADDITIONAL INFORMATION
Additional financial information is available on Sedar at www.sedar.com
and on the Trust's website at www.petrofund.ca.
The Trust will provide to any person, upon request to PC:
(a) when the 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 its securities,
(i) one copy of the annual information form of the Trust,
together with one copy of any document, or the pertinent
pages of any document, incorporated by reference therein,
(ii) one copy of the comparative financial statements of the
Trust for its most recently completed financial year
together with the accompanying report of the auditor and
one copy of any interim financial statements of the Trust
subsequent to the financial statements for its most
recently completed financial year,
B-63
64
(iii) one copy of the information circular of the Trust in
respect of its most recent annual meeting of Unitholders
that involved the election of directors or one copy of any
annual filing prepared in lieu of that information
circular, as appropriate, and
(iv) one copy of any other documents that are incorporated by
reference into the preliminary short form prospectus or
the short form prospectus and are not required to be
provided under (i) to (iii) above; or
(b) at any other time, one copy of any other documents referred to in
(a)(i), (ii) and (iii) above, provided the Trust may require the
payment of a reasonable charge if the request is made by a person
who is not a security holder of the Trust.
Additional information including directors' and officers' remuneration
and indebtedness, principal holders of the issuer's securities, options to
purchase securities and interests of insiders in material transactions, if
applicable, is contained in the issuer's information circular for its most
recent annual meeting of Unitholders that involved the election of directors,
and additional financial information is provided in the issuer's comparative
financial statements for its most recently completed financial year.
For additional copies of this annual information form please contact:
Petrofund Corp.
444 - 7th Avenue, S.W.
Suite 600
Calgary, Alberta
T2P 0X8
Attention: Investor Relations
B-64
MANAGEMENT DISCUSSION &ANALYSIS
-------------------------------
NAME CHANGE AND REVISED TRADING SYMBOL
--------------------------------------
This is the first annual report that reflects the name change of the Trust to
Petrofund Energy Trust ("Petrofund" or the "Trust") from NCE Petrofund. The name
change was announced on October 23, 2003, and became effective November 1, 2003.
On the same date, the name of the Trust's 100% owned subsidiary was changed to
Petrofund Corp. ("PC") from NCE Petrofund Corp. As a result of the name change,
the Trust adopted the new trading symbols PTF.UN on the Toronto Stock Exchange
and PTF on the American Stock Exchange. The Trust units commenced trading under
the new symbols on November 3, 2003.
The name change reflects the restructuring of the Trust. The restructuring began
with the internalization of management early in 2003 and the consolidation of
the remaining activities in the Calgary office over the year. Petrofund has an
experienced and competent team of oil and gas professionals and support groups
who have assembled an excellent portfolio of quality assets. This team has been
an instrumental part of the significant growth of the entity which had an
enterprise value of $1.5 billion as at December 31, 2003.
SPECIAL NOTES
-------------
The following discussion and analysis of financial results should be read in
conjunction with the audited consolidated financial statements of the Trust for
the fiscal years ended December 31, 2003 and 2002 presented later in this
report. This commentary is based on information available to February 15, 2004.
All amounts are stated in Canadian dollars unless otherwise noted. Where amounts
and volumes are expressed on a barrel of oil equivalent basis, gas volumes have
been converted to barrels of oil at 6,000 cubic feet per barrel (6 mcf/bbl).
Management uses cash flow (before changes in non-cash working capital) to
analyze operating performance and leverage. Cash flow as presented does not have
any standardized meaning prescribed by Canadian GAAP and may not be comparable
with the calculation of similar measures for other entities. Cash flow as
presented is not intended to represent operating cash flows or operating profits
for the period, nor should it be viewed as an alternative to cash flow from
operating activities, net earnings or other measures of financial performance
calculated in accordance with Canadian GAAP. All references to cash flow
throughout this report are based on cash flow before changes in non-cash working
capital.
Reserves at December 31, 2003, are based on total proved plus probable company
interest reserves prior to royalties as defined in National Instruments 51-101
("NI 51-101"). Reserves volumes and values for 2003 have been calculated and
disclosed in accordance with this standard. Reserve numbers for other years and
previously announced acquisitions for the current year, are based on established
company interest (proved plus 50% probable) reserves prior to royalties. Under
those definitions, probable reserves were adjusted by a factor to account for
the risk associated with their recovery. The Trust previously applied a risk
factor of 50% in reporting probable reserves. Under current NI 51-101 reserves
definitions, estimates are prepared such that the full proved plus probable
reserves are estimated to be recoverable (proved plus probable reserves are
effectively a "best estimate").
B-65
FORWARD-LOOKING STATEMENTS
--------------------------
This disclosure includes statements about expected future events and/or
financial results that are forward-looking in nature and subject to substantial
risks and uncertainties. For those statements, Petrofund claims the protection
of the safe harbor for forward-looking statements provisions contained in the
U.S. Private Securities Litigation Reform Act of 1995. Petrofund cautions that
actual performance will be affected by a number of factors, many of which are
beyond its control. These include general economic conditions in Canada and the
United States; industry conditions including changes in laws and regulations;
changes in income tax regulations; increased competition; and fluctuations in
commodity prices, foreign exchange and interest rates. In addition, there are
numerous risks and uncertainties associated with oil and natural gas operations
and the evaluation of oil and natural gas reserves. As a result, future events
and results may vary substantially from what Petrofund currently foresees.
A more complete discussion of the various factors that may affect future results
is contained in Petrofund's recent filings with the Securities and Exchange
Commission and Canadian securities regulatory authorities.
CRITICAL ACCOUNTING ESTIMATES
-----------------------------
The preparation of financial statements in accordance with GAAP requires
management to make certain judgments and estimates. Changes in these judgments
and estimates could have a material impact on the Trust's financial results and
financial condition. The Trust has determined that the process of estimating
reserves is critical to several accounting estimates. The process of estimating
reserves is complex and requires significant judgments and decisions based on
available geological, geophysical, engineering and economic data. These
estimates may change substantially as additional data from ongoing development
and production activities becomes available, and as economic conditions
impacting oil and natural gas prices, operating costs, and royalty burdens
change. Reserve estimates impact net income through depletion, the provision for
site reclamation and abandonment and in the application of the ceiling test,
whereby the value of the oil and natural gas assets are subjected to an
impairment test. The reserve estimates are also used to asses the borrowing base
for the Trust's credit facilities. Revision or changes in the reserve estimates
can have either a positive or a negative impact on net income or the borrowing
base of the Trust.
2003 HIGHLIGHTS
---------------
The Trust paid out cash distributions of $127.3 million or $2.09 per unit, an
increase of 22% over the $1.71 per unit paid in 2002.
The Trust's payout ratio for the year was 70% (87% for the fourth quarter).
Net income increased 252% to $85.8 million.
The Trust generated cash flow of $187.6 million, an increase of 67% over 2002.
Production on a boe basis increased 10% to 28,418 boepd.
Average prices were relatively strong, up 32% on a boe basis from the prior
year.
B-66
The Canadian dollar strengthened in the second half of the year more than
offsetting the increase in the West Texas Intermediate ("WTI") U.S. oil prices.
The average WTI price in the second half of 2003 was up 9% to $30.16 a barrel
from the same period in 2002, however, the Canadian par price at Edmonton was
down 6% or $2.77 per bbl over the same period.
The internalization of management transaction was completed resulting in the
elimination of management fees and lower general and administrative costs.
Petrofund acquired interests in various long-life oil and gas properties for
$115.6 million (excluding the non-cash future income tax adjustment of $4.7
million on the purchase of Solaris Oil and Gas Inc.). The properties added
proved plus probable reserves of 19.4 million boe.
Petrofund continued an active development drilling and farmout program,
investing $71.4 million on development drilling, facilities and other costs.
During the year 254 wells were drilled at an overall success rate greater than
90%. These activities added production at $28,600 per boepd. The combined result
of the acquisition and development programs was to add 20.3 million boe's of
reserves and replace 200% of 2003 production.
Petrofund ended 2003 with a very strong balance sheet with long-term debt
outstanding equivalent to 59% of 2003 cash flow.
The Trust completed two equity offerings, raising net proceeds of $193.4
million.
The Trust had a balanced production profile consisting of 49% gas and 51% oil
and liquids.
The Trust reached a milestone with market capitalization exceeding $1.3 billion.
Corporate governance was strengthened including the establishment of Governance,
Reserve Audit, and Human Resources and Compensation committees all consisting of
independent directors. The Audit committee previously consisted of all
independent directors. Petrofund meets all governance guidelines prescribed by
the TSX and the AMEX.
Internalization of Management
-----------------------------
One of the key achievements in the first half of 2003 was the elimination of the
external management contract and all related fees.
At the Annual and Special Meeting held on April 16, 2003, unitholders of the
Trust voted over 90% in favour of the proposed internalization of management
resolution, and on April 29, 2003, the transaction was closed. As a result of
the internalization, NCE Petrofund Management Corp. ("NCEP Management"), the
Previous Manager of the Trust and NCE Management Services Inc. ("NMSI"), which
employed all of the Calgary-based personnel who provided services to the Trust
and PC, became wholly-owned subsidiaries of PC. Effective January 1, 2004 all
the Calgary employees became direct employees of PC, the operating company.
As a result of the transaction, all management, acquisition and disposition fees
payable to the Previous Manager were eliminated effective January 1, 2003, and
the Trust's operations were consolidated in Calgary. To ensure an orderly
transition of the services previously provided by NCEP Management through its
office in Toronto, PC entered into an agreement with Sentry Select Corp.
("Sentry") to provide certain services to the Trust and PC until December 31,
2003. The cost decreased from $1 million in the first quarter to $500,000 in the
second quarter and to
B-67
$250,000 in each of the third and fourth quarters,
after which Sentry no longer provides any services to Petrofund. Sentry was an
affiliate of NCEP Management and is a company in which John Driscoll, the
Chairman of the Board of Directors, owns a controlling interest.
The elimination of management fees and the reduction in general and
administrative costs resulting from the streamlining and consolidation of
on-going management in Calgary improved the operating structure of the Trust.
The internalization was accretive to Petrofund's net asset value, distributions
and cash flow per unit.
The elimination of management fees and the increased management ownership
further aligned the interests of the unitholders and management and improved
Petrofund's competitiveness for acquisitions as a result of the elimination of
acquisition and disposition fees. The completion of the internalization is also
expected to enhance the attractiveness of the units to a wider range of
potential investors, expand the investor base, and may result in a lower cost of
capital.
The cost of the internalization to Petrofund was $30.9 million, consisting of
the issue of 1,939,147 exchangeable shares, 100,244 Trust units, and cash of
$8.0 million, including $3.4 million to repay indebtedness owing to NCEP
Management. Initially, each Exchangeable Share was exchangeable into one Trust
unit. The exchange rate is adjusted from time to time to reflect distributions
paid on each Trust unit after the closing date. The purchase price was based on
numerous factors, including a fairness opinion by CIBC World Markets, who were
retained by a special committee of the Board of Directors formed to consider
this transaction and negotiate the terms of the internalization.
CASH DISTRIBUTIONS
------------------
Trust unitholders who held their units throughout 2003 received cash
distributions of $2.09 per unit as compared to $1.71 per unit in 2002 and $4.24
in 2001. During each of the first two months of 2004, the Trust distributed
$0.16 per unit.
The Trust generated cash flow available for distributions of $180.7 million in
2003. A total of $30 million of this cash flow was allocated to capital
expenditures during the year in accordance with the Trust's policy to use a
portion of the cash flow generated to offset production decline and enhance
long-term unitholder returns. The $30 million represents 17% of cash flow for
the year. A total of $127.3 million was paid out in distributions representing a
payout ratio of 70%. In the fourth quarter, the Trust generated cash flow
available for distribution of $41.6 million before deducting $7.5 million of
capital and paid out $36.3 million in distributions for a payout ratio of 87%.
For a detailed analysis of cash flow available for distribution and
distributions paid refer to Note 12 to the Consolidated Financial Statements.
At December 31, 2003, the Trust had $53.5 million available to pay future
distributions, capital and other costs, of which $23.6 million was used to pay
the January and February 2004 distributions.
RESULTS OF OPERATIONS
---------------------
PRODUCTION
In accordance with Canadian practice, production volumes and reserves are
reported on a working interest basis, before deduction of Crown and other
royalties, unless otherwise indicated.
B-68
Production volumes averaged 28,418 boe/d, an increase of 10% over average
production volumes of 25,782 boe/d in the previous year. The majority of the
increase is due to the additional properties purchased for $62 million in the
second quarter of 2003, the additional Swan Hills Unit interest purchased in the
third quarter of 2003 and the acquisition of NCE Energy Trust on May 31, 2002.
Production from the second quarter acquisition is included in this report
effective June 1, 2003, and the additional Swan Hills interest is included
effective September 1, 2003.
For the years ended December 31, 2003 2002 2001
--------------------------------------------------------------------------------
Daily Production
Oil (bbls) 12,454 11,162 8,156
Gas (mmcf) 83.3 76.9 67.2
Natural gas liquids (bbls) 2,079 1,808 1,452
--------------------------------------------------------------------------------
Total (boe 6:1) 28,418 25,782 20,810
--------------------------------------------------------------------------------
PRICING & PRICE RISK MANAGEMENT
Revenues from the sale of crude oil, natural gas, and natural gas liquids and
sulphur increased 45% to $393.1 million in 2003 from $270.7 million in 2002 due
to a 10% increase in production and 32% increase in prices on a boe basis.
Crude oil sales increased to $172.3 million in 2003 from $141.3 million in 2002
due to a 12% increase in production from 11,162 bbl/d in 2002 to 12,454 bbl/d in
2003. The average WTI U.S. oil price increased from $26.08 per bbl in 2002 to
$31.04 in 2003 or 19%, however, the Canadian par price at Edmonton increased
only 8% from $39.91 per bbl to $43.14 bbl due to the significant strengthening
of the Canadian dollar relative to the U.S. dollar, especially in the last half
of the year. The average Canadian wellhead price increased from $34.68 per
barrel in 2002 to $37.91 per barrel in 2003. Hedging losses reduced the price by
$1.00 per bbl in 2003 and $2.10 per bbl in 2002. About 72% of the Trust's crude
production is sold directly to refiners, up from 62% a year ago and nearly
double the level of 2001. This reflects Petrofund's strategy of reducing sales
to marketers and middlemen to achieve higher levels of security for both credit
and the actual physical delivery of the crude. The balance of the crude is
delivered to marketers. Crude differentials were relatively stable and tight
during 2003 with Petrofund's actual differentials from Edmonton postings before
hedging at $4.23/bbl versus $3.16/bbl the previous year. Western Canadian crude
differentials for 2004 are expected to be similar to those seen in 2003. Heavy
oil differentials, to which Petrofund has little exposure, may be weaker and the
bias is for tighter differentials for the lighter and medium sour crudes
comprising the bulk of the Trust's portfolio. Petrofund's crude portfolio is
over 97% light and medium crudes.
Natural gas sales increased to $194.2 million in 2003 from $110.7 million in
2002 due to an 8% increase in production in addition to a 62% increase in
average prices from $3.95 per mcf in 2002 to $6.39 per mcf in 2003 net of a
hedging loss of $0.11 per mcf. The monthly AECO price increased from $4.07 per
mcf in 2003 to $6.71 per mcf in 2003. Production volumes were 83.3 mmcf/d in
2003 compared to 76.9 mmcf/d in 2002. Petrofund sold 34% of its production in
2003 to aggregators at netback pricing, down slightly from 38% in 2002 and
similar to volumes delivered in 2001. The Trust sold the remaining 66% on daily
and monthly spot market pricing in Alberta, Saskatchewan and British Columbia.
B-69
Sales of natural gas liquids increased to $26.6 million in 2003 from $18.7
million in 2002 as production increased to 2,079 bbl/d in 2003 from 1,808 bbl/d
in 2002. The average price increased from $28.30 per barrel in 2002 to $34.66
per barrel in 2003. The majority of the Trust's NGL is sold to two buyers under
one-year contract terms at market sensitive pricing. NGL netbacks lagged the
recovery in crude oil prices during the year owing to mid-year weakness in
natural gas prices. Petrofund expects NGL's to continue to return attractive
pricing for 2004 with very strong pricing for condensate.
Crude oil sales accounted for 44% of total production in 2003 (2002 - 43%, 2001
- 39%), while natural gas sales contributed 49% of production in 2003 (2002 -
50%, 2001 - 54%). Natural gas liquid volumes accounted for 7% of total
production in all three years. The Trust continues to maintain an excellent
balance between oil and gas production.
Sales Prices
Average prices for the year ended December 31, 2003 2002 2001
---------------------------------------------------------------------------------------------
Oil (1) $ 37.91 $ 34.68 $ 34.37
Gas (2) 6.39 3.95 5.09
Natural gas liquids 34.66 28.30 32.57
---------------------------------------------------------------------------------------------
Weighted average (6:1) $ 37.87 $ 28.77 $ 32.19
---------------------------------------------------------------------------------------------
(1) The oil price was increased (decreased) per bbl due to
hedging $ (1.00) $ (2.10) $ 1.05
(2) The gas price was decreased per mcf due to hedging $ (0.11) $ - $ (0.13)
Production Revenue (millions)
Oil $ 172.3 $ 141.3 $ 102.3
Gas 194.2 110.7 125.0
Natural gas liquids 26.6 18.7 17.2
---------------------------------------------------------------------------------------------
Total $ 393.1 $ 270.7 $ 244.5
---------------------------------------------------------------------------------------------
The Trust implemented a formal risk management policy which provides the Risk
Management Committee with the ability to use specified price risk management
strategies up to 50% of crude oil, natural gas and NGL production including:
fixed price contracts; costless collars; the purchase of floor price options;
and other derivative financial instruments to reduce price volatility and ensure
minimum prices for a maximum of two years beyond the current date. The program
is designed to provide price protection on a portion of the Trust's future
production in the event of adverse commodity price movement, while retaining
significant exposure to upside price movements. In this way the Trust seeks to
provide a measure of stability to cash distributions as well as ensure Petrofund
realizes positive economic returns from its capital development and acquisition
activities.
As at December 31, 2003, Petrofund has hedged 26 mmcf/d of gas and 5,328 bbl/d
of crude oil for 2004. The Trust increased its gas hedges for 2004 by 7 mmcf/d
and its crude oil hedges by
B-70
1,569 bbl/d over the third quarter. Petrofund's 2004 gas hedges include: 18.5
mmcf/d collared between $5.42/mcf-$7.90/mcf and 7.5 mmcf/d fixed at $6.15/mcf.
The Trust will lose its floor protection on about 9% of the collared volumes if
AECO drops below $4.74/mcf but will receive a premium of $1.06/mcf in this
event. Petrofund's 2004 crude hedges include 1,995 bbl/d fixed at $38.59/bbl in
the first half and 668 bbl/d fixed at $36.41 in the second half of the year. The
Trust has also collared 4,000 bbl/d in 2004 between $31.20/bbl-$36.86/bbl. The
Trust will lose its floor protection on 50% of the collared volume in the event
WTI averages less than $27.40/bbl ($21.13 US. Under these transactions
Petrofund will receive a premium of $3.89/bbl ($3.00 US) to the actual price.
For the first quarter of 2005, the Trust has 9.5 mmcf/d of gas hedged under a
$5.80/mcf-$8.97/mcf three way collar. At year end, the Petrofund's 2005 crude
hedges include 1,000 bbl/d in a three way collar between $31.12/bbl-$37.60/bbl.
Petrofund also fixed the price on approximately 50% of its power consumption at
$44.50/MWh for 2004 and 2005 to control future costs. During 2003, the monthly
average power costs ranged from $44.47/MWh to $89.80/MWh.
In early January 2004, Petrofund entered into the following additional hedge
transactions:
1) 1,000 bbl/d of crude oil was fixed for March-May 2004 at $41.92/bbl;
2) 1,000 bbl/d of crude oil was fixed for November-December 2004 at
$37.73/bbl;
3) 2,000 bbl/d of crude oil for 2005 under a three way WTI collar between
$34.75 and $43.18/bbl ($26.81-$33.30 US). Under this transaction, if WTI
averages less than $30.46 ($23.50 US), Petrofund will lose the floor
protection, but will still receive a $4.54/bbl ($3.50 US) premium to the
actual price.
The Trust also increased its AECO gas hedges subsequent to year end by collaring
an additional 1.9 mmcf/d between $5.28/mcf and $7.65/mcf for the period April 1,
2004 to October 31, 2004.
All foreign exchange calculations in this section of the report incorporate the
Bank of Canada US dollar rate at the close on December 31, 2003, ($1.2965
C$:US$). For a complete listing of all hedge transaction details please see Note
14 to the Consolidated Financial Statements.
Royalties 2003 2002 2001
--------------------------------------------------------------------------------
Royalties (millions) $ 84.8 $ 50.4 $ 54.7
Average royalty rate (%) 21.6% 18.6% 22.4%
$/boe $ 8.18 $ 5.36 $ 7.21
Royalties, which include crown, freehold and overrides paid on oil and natural
gas production, increased to $84.8 million in 2003 from $50.4 million in 2002,
net of the Alberta Royalty Credit. Royalties increased to 21.6% of revenues in
2003 from 18.6% of revenues in 2002 and 22.4% in 2001. The variation in the
average rates is mainly due to the fluctuations in natural gas prices as the gas
royalty rate changes with natural gas prices.
B-71
Expenses 2003 2002 2001
--------------------------------------------------------------------------------
Expenses (millions)
Lease operating $ 91.3 $ 74.8 $ 48.2
General & administrative 13.0 15.5 14.4
Management fee - 4.7 5.3
Net interest 8.7 8.3 7.8
--------------------------------------------------------------------------------
Expenses per boe
Lease operating $ 8.80 $ 7.95 $ 6.35
General & administrative 1.26 1.65 1.90
Management fee - 0.50 0.70
Net interest 0.84 0.88 1.03
--------------------------------------------------------------------------------
Lease Operating
---------------
Oil and gas operating expenses increased to $91.3 million in 2003 from $74.8
million in 2002 (2001 - $48.2 million) due to the additional wells on production
and the increase in costs on a boe basis. Operating costs on a boe basis
increased to $8.80 in 2003 from $7.95 in 2002 (2001 - $6.35).
The most significant contributor to the higher operating costs in 2003 was the
increased costs for workover activities. These activities included rate
acceleration projects, well repair, facility turnarounds and other facility
maintenance work. There are two components to the increased costs. Firstly,
costs in general have risen due to high industry activity levels. Secondly, more
workover projects were undertaken for production enhancement because the return
on these projects is very good in the current product price environment.
GENERAL & ADMINISTRATIVE
------------------------
General and administrative costs decreased to $13.0 million in 2003 from $15.5
million in 2002 (2001 - $14.4 million). Costs decreased 24% to $1.26 per boe in
2003 from $1.65 per boe in 2002 as a result of the consolidation of all
activities in Calgary and the increased production volumes.
MANAGEMENT FEES
---------------
No management fees were payable in 2003 and no future fees will be paid due to
the internalization of management. Fees of $4.7 million were paid in 2002 to the
Previous Manager (2001 - $5.3 million).
INTEREST
--------
Interest expense increased to $8.7 million in 2003 from $8.3 million in 2002
(2001 - $7.8 million), due to the increase in the average loan balance
outstanding.
The bank loan outstanding at December 31, 2003, was $109.7 million as compared
to $212.3 million at the end of the previous year.
B-72
DEPLETION AND DEPRECIATION &
----------------------------
PROVISION FOR RECLAMATION AND ABANDONMENT
-----------------------------------------
Depletion and depreciation is provided on the unit-of-production method based on
total estimated proved reserves. Depletion and depreciation expense was $113.9
million in 2003 compared to $98.8 million in 2002 (2001 - $68.5 million). The
depletion rate per boe increased to $10.98 in 2003 from $10.50 in 2002 (2001 -
$9.01). The $0.48 increase in the depletion rate from 2002 to 2003 was mainly
due to the negative reserve revisions at the end of 2002. Unproved properties
are included in the depletion and depreciation rate. The provision for
reclamation and abandonment per boe in 2003 was $0.60, compared to $0.62 in 2002
(2001 - $0.48).
RECLAMATION & ABANDONMENT RESERVE
---------------------------------
At the end of the year, PC had $3.8 million set aside in cash to fund future
abandonment costs. This cash fund is increased by $0.075 per boe produced on an
ongoing basis. This cash fund is in place to fund significant future reclamation
costs, such as the decommissioning of a major facility.
PC is committed to conducting its operations in a safe and environmentally
responsible manner and has an established program in place to manage
environmental liabilities. The Trust performs well reclamation and abandonments,
flare pit remediation work, etc. on a routine basis to proactively address
environmental concerns. Petrofund's activities in this area in 2003 were
significant as $4.7 million was spent on these types of projects. This compares
to $2.2 million in 2002 and $0.4 million in 2001. PC expects to spend a further
$3 million on reclamation and abandonment work in 2004.
NET INCOME
----------
Net income increased to $85.8 million, up 252% from the $24.4 million reported
in 2002 (2001 - $54.0). The increase was mainly due to the 35% improvement in
operating netbacks as prices were up 32% on a boe basis. In addition, production
was up 10% over the prior year.
Net income for the year ended December 31, 2003, was impacted by the costs of
the internalization of the management contract and the reduction of income taxes
for the decrease in future income tax rates. Net income was reduced by $30.9
million for management internalization costs and increased by $36.7 million for
future income tax reductions.
B-73
QUARTERLY FINANCIAL DATA
Net Oil and Net Net income per Unit (2)
($millions, except per Unit amounts) Natural Gas Sales(1) Income Basic Diluted
------------------------------------------------------------------------------------------------
2003
First quarter $ 84.9 $ 32.2 $ 0.59 $ 0.59
Second quarter 74.8 15.1 0.26 .26
Third quarter 73.4 14.9 0.23 0.23
Fourth quarter 75.2 23.6 0.33 0.33
------------------------------------------------------------------------------------------------
$ 308.3 $ 85.8 $ 1.41 $ 1.40
------------------------------------------------------------------------------------------------
2002
First quarter $ 42.7 $ 0.9 $ 0.02 $ 0.02
Second quarter 53.1 8.5 0.17 0.17
Third quarter 55.8 9.6 0.18 0.18
Fourth quarter 68.6 5.4 0.10 0.10
------------------------------------------------------------------------------------------------
$ 220.2 $ 24.4 $ 0.49 $ 0.49
------------------------------------------------------------------------------------------------
2001
First quarter $ 54.4 $ 26.3 $ 1.19 $ 1.19
Second quarter 46.9 16.4 0.60 0.60
Third quarter 45.4 7.7 0.20 0.20
Fourth quarter 43.0 3.6 0.09 0.09
------------------------------------------------------------------------------------------------
$ 189.7 $ 54.0 $ 1.71 $ 1.71
------------------------------------------------------------------------------------------------
(1) Net after royalties
(2) Net income per unit numbers are calculated quarterly and therefore do not
add.
Discussion of Results for the Fourth Quarter of 2003
----------------------------------------------------
Production for the fourth quarter of 2003 was 29,211 boe/d as compared to 27,362
boe/d for the same period in the prior year. Oil was up 13% from 12,096 boe/d to
13,645 boe/d. Natural gas was up marginally to 80.3 mmcf/d from 79.9 mmcf/d and
natural gas liquids increased to 2,185 boe/d from 1,946 boe/d. Oil revenues
increased to $44.0 million from $40.6 million due to the increase in volumes as
the oil price decreased to $35.06 per bbl from $36.48 per bbl. Natural gas
revenue was up to $43.1 million from $37.9 million mainly due to the natural gas
price which increased 13% from $5.15 per mcf to $5.84 per mcf. Revenues from
natural gas liquids increased to $6.9 million from $6.0 million due to volumes
and prices. The average price was $34.46 per bbl in the fourth quarter of 2003,
as compared to $33.34 per bbl in the fourth quarter of 2002.
Royalties increased from $15.8 million in 2002 to $19.0 million in 2003.
Royalties were 19% of revenue in the fourth quarter of 2002 and 20% in the same
period in 2003, mainly due to the increased natural gas prices.
Operating costs increased to $24.8 million in 2004 from $21.3 million in 2003,
due to the additional wells on production and a general increase in costs
experienced by the oil and gas industry.
B-74
General and administrative costs decreased from $3.6 million, or $1.43 per boe,
in the fourth quarter of 2002 to $2.9 million or $1.10 per boe for the same
period in 2003.
Depletion and site reclamation and abandonment expenses increased from $28.6
million in 2002 to $33.7 million in 2003 or $1.20 per boe.
Income before income taxes was $11.4 million in the fourth quarter of 2003 as
compared to $10.2 million in the fourth quarter of 2002. Net income, however,
was up to $23.6 million from $5.4 million due to a future income tax recovery in
2003 of $12 million as compared to a future tax expense of $5.0 million in 2002.
The future tax liability at December 31, 2002 included a provision for income
taxes for entities that were acquired by the Trust. These entities were under
audit at the time and the CCRA (Canada Customs and Revenue Agency) had made
large proposed adjustments. The Trust was successful in having these adjustments
reversed to a minimal amount. As a result, the Trust has taken the provision
back into income in 2003.
CAPITAL EXPENDITURES
--------------------
Acquisitions
During the year, PC incurred $115.6 million for property acquisitions, excluding
the non-cash future tax adjustment of $4.7 million recognized on the Solaris Oil
and Gas Inc. ("Solaris") acquisition, and acquired 19.4 million boe of
Established Reserves. The properties were heavily weighted to oil and had a
reserve life index of 14.4 years.
Effective January 1, 2003, PC acquired 100% of the outstanding common share of
Solaris, and on February 7, 2003, amalgamated Solaris into PC. PC paid $7.4
million in cash, and assumed debt and negative working capital of $1.2 million,
for a total cost of the oil and gas properties of $8.6 million. The acquisition
added 720,000 boe of Established Reserves and approximately 200 boe/d of
production.
In the second quarter of 2003, PC closed the acquisition of a diverse group of
oil and natural gas properties for $61.7 million after adjustment. The
properties added Established Reserves of 9.7 million boe as estimated by the
independent engineering firm, Gilbert Laustsen Jung Associates Ltd. At the time
of acquisition, production from the properties was approximately 2,300 boe/d of
which 42% was natural gas. Production and cash flow has been included in this
report effective from June 1, 2003. The properties contained a large percentage
of unit production, and had a reserve life index on an Established basis of 11.6
years.
On August 21, 2003, PC purchased a 7.22% interest in Swan Hills Unit #1 for
$37.1 million from a private Canadian company. This acquisition increased PC's
interest in the unit, bringing PC's total interest in the unit to 9.87%. This
acquisition added 8.5 mmboe of Established Reserves and approximately 1,100
boe/d of production. The Established reserve life index of the property was over
20 years.
Finding & Development Costs
During the year PC incurred $71.4 million on drilling and development activities
as compared to $40.8 million in 2002. A total of 214 wells were drilled, of
which 115 were gas, 84 oil and 15 dry and abandoned for an overall success rate
of 93%. These activities added 2,500 boepd of production at an average cost of
$28,600 per boepd and offset more than half of the decline in existing
production.
B-75
Farmout Activities
During 2003, Petrofund entered into farmout agreements with various industry
partners which resulted in 40 wells being drilled in 2003 on Petrofund's
undeveloped land base. This drilling yielded 32 natural gas wells, 3 oil wells
and 5 abandoned wells.
Although terms are slightly different for each farmout, they are generally
structured such that Petrofund is carried for the costs of each well and
receives a gross overriding royalty before payout of such costs and an after
payout working interests for each well which generally equates to 50% of it
pre-farmout interest.
Disposition of Properties
During 2003, Petrofund disposed of approximately 5 million boe of Established
Reserves for $33.5 million. Eighty percent of these reserves were sold as a
package of non-core east central Alberta properties marketed publicly late in
the year. All of the properties disposed of were non-core to Petrofund's ongoing
operations, had high operating costs and high decline rates. These dispositions
are an integral part of Petrofund's ongoing portfolio management process.
The properties sold are expected to reduce 2004 production by approximately
1,500 boepd.
A summary of capital expenditures for the last three years is as follows (in
millions):
For the years ended December 31, 2003 2002 2001
--------------------------------------------------------------------------------
Property acquisitions (1) $ 115.6 $ 218.5 $ 222.4
Property dispositions (33.5) (30.0) (3.7)
--------------------------------------------------------------------------------
Net acquisitions 82.1 188.5 218.7
--------------------------------------------------------------------------------
Finding & development costs:
Land & seismic 2.5 2.8 2.1
Drilling & completion 42.5 22.2 17.0
Well equipping 7.9 6.7 2.1
Tie-ins 5.2 2.7 2.2
Facilities 8.4 3.2 3.5
Other 4.9 3.2-
--------------------------------------------------------------------------------
Total 71.4 40.8 26.9
--------------------------------------------------------------------------------
Total net capital expenditures $ 153.5 $ 229.3 $ 245.6
--------------------------------------------------------------------------------
(1) The property acquisition totals exclude non-cash future income tax
adjustments for the difference between the cost and tax bases of assets acquired
by way of corporate acquisitions.
DEBT
----
The borrowing base was increased to $265 million, in conjunction with the
closing of the second quarter 2003 property acquisition. As at December 31,
2003, the amount outstanding on the credit facility was $110 million with $155
million available to finance future activities.
The revolving period on the syndicated facility was scheduled to end on May 30,
2003; however, it has been extended for an additional 364-day period ending May
28, 2004.
B-76
WORKING CAPITAL
---------------
The working capital deficit was $30 million at December 31, 2003, an increase of
$23.1 from the $6.9 million deficit at the end of the prior year. The primary
reason for this change is a corresponding increase in distributions payable to
unitholders of $23 million. This amount represents the cash flow available for
distribution generated during the year in excess of distributions paid.
LIQUIDITY AND CAPITAL RESOURCES
-------------------------------
Total long-term debt and capital leases decreased $108.9 million from $219.2
million at December 31, 2002 to $110.3 million at the end of the current year.
The major changes in total long term debt were due to:
$000's
--------------------------------------------------------------------------------
Net proceeds from the May and December equity issues $ 193.4
Proceeds received from the exercise of options 20.5
Proceeds received from the sale of properties 33.5
Increases in working capital deficit 23.1
Cash flow available for distributions in excess of distributions paid 23.4
Property acquisitions (115.6)
Expenditures on oil and gas properties (71.4)
Miscellaneous 2.0
--------------------------------------------------------------------------------
$ 108.9
--------------------------------------------------------------------------------
Capitalization Analysis
($ thousands, except per unit and percent amounts) 2003 2002 2001
--------------------------------------------------------------------------------------------------
Working capital (deficiency) $ (30,006) $ (6,909) $ (20,564)
Bank debt 109,707 212,253 128,783
Capital lease obligation 608 6,965 16,168
--------------------------------------------------------------------------------------------------
Net debt obligation $ 140,321 $ 226,127 $ 165,515
--------------------------------------------------------------------------------------------------
Units outstanding and issuable for exchangeable shares 73,628 54,108 41,916
Market Price at December 31, $ 18.79 $ 10.85 $ 11.97
Market capitalization $1,383,465 $ 587,069 $ 501,731
--------------------------------------------------------------------------------------------------
Total capitalization $1,523,786 $ 813,196 $ 667,246
--------------------------------------------------------------------------------------------------
Net debt as a percentage of total capitalization 9.2% 27.8% 24.8%
--------------------------------------------------------------------------------------------------
Cash flow $ 187,585 $ 112,570 $ 110,176
--------------------------------------------------------------------------------------------------
Net debt to cash flow 0.7:1.0 2.0:1.0 1.5:1.0
--------------------------------------------------------------------------------------------------
Long-term debt will increase in 2004 due to the capital expenditure program
which is expected to be in the $60 million range. If the Trust is successful in
completing one or more significant acquisitions in 2004 these would be financed
by further utilization of the credit facility or a combination of additional
bank borrowing and a possible equity issue of treasury units.
B-77
UNITHOLDERS' EQUITY
-------------------
The Trust had 72,688,577 trust units outstanding at December 31, 2003, compared
to 54,108,420 trust units at the end of 2002. In April 2003, 1,939,147
exchangeable shares and 100,244 Trust units were issued in connection with the
internalization transaction. During the year, 906,635 Exchangeable Shares were
converted to 1,000,000 Trust units and 181,041 were redeemed for cash leaving
851,471 exchangeable shares outstanding at year end which can be converted, at
the option of the unitholder into 939,147 trust units. The weighted average
number of trust units outstanding including those issuable on the exchange of
exchangeable shares, was 61,010,105 trust units for 2003 as compared to
49,921,523 for 2002.
During 2003, the Trust completed two equity offerings. In May 2003, the Trust
issued 9.2 million units at a price of $10.60 per unit for net proceeds of $92.3
million. In December 2003, 6.6 million units were issued at a price of $16.20
per unit for net proceeds of $101.1 million.
During the year, 1,673,404 options were exercised for the same number of trust
units generating proceeds of $20.5 million. (For complete details of options
exercised and outstanding at the end of the year refer to note 11 of the
Consolidated Financial Statements).
Under the Distribution Reinvestment Plan ("DRIP") unitholders can elect to
receive distributions or make optional cash payments to acquire trust units from
treasury or in the open market. Under the DRIP plan 316,785 trust units were
issued at an average price of $13.21 for total proceeds of $4.2 million. In
2002, 288,981 units were issued under the DRIP plan at an average price of
$12.16 per trust unit.
TAXES
-----
Current taxes consist of the Federal Large Corporations Tax and some minor
amounts relating to income taxes of corporate entities acquired. The Federal
Large Corporations Tax is based primarily on the debt and equity balances of PC
at the end of the year. The Federal Large Corporations Tax rate is proposed in
the Federal Budget of 2003 to be reduced in stages over a period of five years
so that by 2008, the tax will be eliminated.
Capital taxes of $2.5 million in 2003 and $2.1 million in 2002 are primarily the
Saskatchewan Capital Tax and Resource Surcharge, which is based upon
Saskatchewan gross revenues.
Future income tax liabilities arise due to the differences between the tax basis
of PC's assets and their respective accounting carrying cost. Future income
taxes were increased by $4.7 million due to the purchase of Solaris. This
liability arose as the purchase price of Solaris's assets was in excess of its
tax pools. In the Trust's structure, payments are made between PC and the Trust
which thereby transfers both income and future tax liability to the individual
unitholders. Accordingly, it is the opinion of management that no cash income
taxes will be paid by PC in the future and, as such, the future income tax
liability recorded on the balance sheet will be recovered through earnings over
time. Future income tax recoveries of $44.5 million in 2003 and $14.3 million in
2002 have resulted in a remaining future income tax liability of $77.0 million
at December 31, 2003. The future income tax liability was reduced by
approximately $36.7 million to reflect reductions in the Federal and Alberta
income tax rates in 2003.
Cash distributions paid to unitholders resident in Canada or the United States
have differing tax consequences depending on each unitholder's circumstances.
The Trust sets out some brief comments regarding the taxability of the
distributions but does not intend to provide legal or tax advice. Unitholders or
potential investors should seek their own legal or tax advice in this regard.
B-78
Generally, Canadian unitholders include in their income the portion of the
distribution that is taxable income earned by the Trust. The portion that is a
return of capital reduces the adjusted cost base of the Trust unit of the
unitholder. In 2003, 51.223% of distributions paid to unitholders was ordinary
income and 48.777% was a return of capital.
Generally, United States unitholders include in their income the portion of the
distribution that is taxable income earned by the trust. Such amount is
considered a dividend for U.S. purposes and is subject to Canadian withholding
tax. The portion that is a return of capital and not taxable reduces the tax
basis of the Trust unit. In 2003, 83.346% of distributions to United States
unitholders was dividend income and 16.654% was a return of capital.
BUSINESS RISKS
--------------
The success of the Trust in meeting its objective of stable distributions over
the long term depends mainly on management's ability to:
1) Identify and acquire oil and gas properties and/or companies at
prices that add value to the Trust.
2) Cost effectively add or extend reserves with internal development
and drilling or farmouts.
3) Manage and control costs.
There are numerous factors beyond management's control that have a major
influence on distribution levels including product prices, unforeseen production
declines and cost increases from major suppliers. (A detailed assessment of risk
factors and offsetting strategies appears elsewhere in this report).
Below is a table that shows sensitivities to pre-hedging cash flow as a result
of product price and operational changes. The table is based on actual 2003
prices received and production volumes of 27,000 boepd. These sensitivities are
approximations only and are not necessarily valid at other price and production
levels. As well, hedging activities can significantly affect these
sensitivities.
Sensitivity Analysis
$/unit
Change $000's per year
--------------------------------------------------------------------------------
Price per barrel of oil* $ 1.00 U.S. $ 5,331 $ 0.072
Price per mcf of natural gas* $ 0.25 Cdn. $ 5,585 $ 0.076
US/Cdn exchange rate $ 0.01 $ 2,650 $ 0.036
Interest rate on debt ($125 million) 1% $ 1,250 $ 0.017
Oil production volumes* 100 bbl/day $ 1,131 $ 0.015
Gas production volumes* 1 mmcf/day $ 1,784 $ 0.024
--------------------------------------------------------------------------------
* After adjustment for estimated royalties.
OUTLOOK FOR 2004
----------------
The level of cash flow for 2004 will be affected by oil and gas prices, the
Canadian - US dollar exchange rate and the Trust's ability to add reserves and
production in a cost effective manner. Both product prices and the exchange rate
showed significant volatility in 2003 and this trend is expected to continue in
2004.
B-79
The acquisition market is expected to continue to be active and supply should
increase with the recent announcement by three large producers of their
intention to dispose of their Canadian properties in 2004. Nevertheless,
competition for these assets is expected to be fierce due to increased demand
resulting from the increasing number of oil and gas companies that have
converted to a trust structure. We expect prices for quality, long life assets
to be at or near record levels. Petrofund expects to be an active participant in
this market but success will be tempered by a commitment to maintain historic
discipline and bid only at levels consistent with the best long term interest of
our unitholders.
Acquisition activities will be complemented by an extensive drilling and farmout
program that will be conducted on our existing land base.
Although product prices have remained at high levels, the strengthening of the
Canadian dollar in the second half of 2003 significantly moderated the net
effect of these prices on Petrofund's cash flow. We expect the Canadian dollar
to remain very strong in the short term with a possible decrease toward the end
of 2004.
Petrofund pursues a well defined risk management program to help offset the
effect of price fluctuations. This program utilizes collars as the main hedging
tool but Petrofund also enters into fixed price transactions when commodity
prices approach historic highs. To date, the Trust has not entered into any
currency related transactions. A discussion of the risk management strategies
and hedged position appears elsewhere in this report.
CONTRACTUAL OBLIGATIONS
-----------------------
For details on contractual obligations refer to note 17 of the Consolidated
Financial Statements.
OFF-BALANCE SHEET ARRANGEMENTS/ VARIABLE INTEREST ENTITIES
----------------------------------------------------------
The Trust has no off-balance sheet arrangements or variable interest entities.
IMPACT OF NEW CANADIAN ACCOUNTING PRONOUNCEMENTS
------------------------------------------------
In September 2002, the CICA approved Section 3063, "Impairment of Long-Lived
Assets" (S.3063). S.3063 establishes standards for the recognition, measurement
and disclosure of the impairment of longlived assets, and applies to long-lived
assets held for use. An impairment loss is recognized when the carrying amount
of a long-lived asset is not recoverable and exceeds its fair value. The new
Section is effective for fiscal years beginning on or after April 1, 2003. The
application of the impairment test for companies following the full cost method
of accounting for oil and natural gas activities has been included in Accounting
Guideline 16, "Oil and Gas Accounting - Full Cost" AcG-16 issued in September
2003. The new guideline limits the carrying value of oil and natural gas
properties to their fair value. The fair value is equal to estimated future cash
flows from proved and risked probable reserves using future price forecasts and
costs discounted at a risk-free rate. This differs from the current cost
recovery ceiling test that uses undiscounted cash flows and constant prices and
costs less general and administrative and financing costs. There is no
write-down of the Trust's oil and gas royalty and property interests under
either method at December 31, 2003. AcG-16 also adopted the reserve evaluation
and disclosure requirements of NI 51-101 which have been followed in the
preparation of this report.
In December 2001, the Canadian Institute of Chartered Accountants (CICA) issued
Accounting Guideline 13, "Hedging Relationships" (AcG-13) originally effective
for fiscal years commencing on or after July 1, 2002. Implementation was then
postponed to the fiscal years commencing on or after July 1, 2003. AcG-13
established certain conditions for when hedge accounting may be applied. If
hedge accounting is not
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applied, the fair values of derivative financial instruments are recorded as an
asset or a liability on the balance sheet. As the guideline is effective for
fiscal years beginning on or after July 1, 2003, Petrofund will be adopting the
guideline effective January 1, 2004. Petrofund enters into numerous derivative
financial instruments to reduce price volatility and establish minimum prices
for a portion of its oil and natural gas production. These contracts are
effective economic hedges, however, a number do not qualify for hedge accounting
due to the very detailed and complex rules outlined in AcG-13. Petrofund has
elected to use the fair value method of accounting for all derivative
transactions as we believe it would be confusing to the reader if the Trust were
to use hedge accounting for some of its hedging contracts and fair value
accounting for others. Also the additional costs to use hedge accounting would
be significant as detailed documentation requirements must be met and each
individual contract would need to be analyzed to determine which method of
accounting to use. Effective January 1, 2004, Petrofund will record the fair
value of the derivative financial instruments as at December 31, 2003, in the
amount of $6.8 million as a liability on the balance sheet. The change in the
fair value from period to period will be recorded in the income statement on a
separate line as unrealized gains/losses. This line item will also include
realized gains and losses on the derivative financial instruments which
currently are recorded in oil and gas sales.
In December 2002, the CICA approved Section 3110, "Asset Retirement Obligations"
which requires liability recognition for retirement obligations associated with
our property, plant and equipment. The obligations are initially measured at
fair value, which is the discounted future value of the liability. The fair
value is capitalized as part of the cost of the related assets and amortized to
expense over their useful lives. The liability accretes until the retirement
obligations are settled. S.3110 is effective for fiscal years beginning on or
after January 1, 2004. The accrued reclamation and abandonment liabilities on
the balance sheet which have been calculated on a unit of production basis will
be reversed January 1, 2004. Oil and gas properties will be increased and a
liability set up for the amount calculated under the new standard. In 2004 the
accounting will follow the new standard and the comparative numbers for 2003 and
prior periods will be restated.
The impact of this standard will be to increase oil and gas royalty and property
interests on the balance sheet by $18.6 million at December 31, 2003, and by
$18.5 million at December 31, 2002. The accrued reclamation and abandonment
liability (asset retirement obligation) will increase to $34.4 million at
December 31, 2003, from $16.8 million and the liability at December 31, 2002
will increase to $34.5 million from $15.3 million. The effect on the income
statement will be to increase (decrease) net income before income taxes by $ 1.5
million in 2003, (2002 - $1.1 million, 2001 - $ (0.9) million).
Effective March 31, 2004, the Trust and all reporting issuers in Canada will be
subject to new disclosure requirements as per National Instrument 51-102
"Continuous Disclosure Obligations". This new instrument is effective for fiscal
years beginning on or after January 1, 2004. The Instrument proposes shorter
reporting periods for filing of annual and interim financial statements, MD&A
and the Annual Information Form ("AIF"). The Instrument also proposes enhanced
disclosure in the annual and interim financial statements, MD&A and AIF. Under
this new instrument, it will no longer be mandatory for the Trust to mail annual
and interim financial statements and MD&A to unitholders, but rather these
documents will be provided on an "as requested" basis. The Trust continues to
assess the implications of this new instrument which will be implemented in
2004.
Other accounting standards issued by the CICA during the year ended December 31,
2003, are not expected to impact the Trust at this time.
CONTROLS AND PROCEDURES
-----------------------
Evaluation of disclosure controls and procedures. The Trust's principal
executive officer and its principal financial officer, after evaluating the
effectiveness of the Trust disclosure controls and
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procedures (as defined in U.S. Exchange Act Rules 13a - 15 (e) and 15d - 15(e))
the end of the period covered by this annual report, have concluded that, as of
such date, the Trust's disclosure controls and procedures were adequate and
effective to ensure that material information relating to the Trust and its
subsidiaries would be made known to them by others within those entities.
Changes in internal control over financial reporting. There was no change in the
Trust's internal control over financial reporting that occurred during the
period covered by this annual report that has materially affected, or is
reasonably likely to materially affect, the Trust's internal control over
financial reporting.
Changes in internal controls. There were no significant changes in the Trust's
internal controls or in other factors that could significantly affect the
Trust's internal controls subsequent to the date of their evaluation nor were
there any significant deficiencies or material weaknesses in the Trust's
internal controls. As a result, no corrective actions were required or
undertaken.
STATEMENT OF CORPORATE GOVERNANCE
---------------------------------
Petrofund adheres to all required regulatory and security commission guidelines
as required by the TSX and the AMEX at December 31, 2003. This has resulted in
Petrofund's acceptance of a 'best practices' corporate governance structure. To
this end, four sub-committees of the Board, all composed of independent
directors, act in the best interests of the Trust. Additional information about
the board and the committee compositions are detailed in the annual report and
within Petrofund's annual information form.
The President and Chief Executive Officer and Senior Vice-President, Finance and
Chief Financial Officer have signed a code of ethics which is posted on the
Trust's website.
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AUDITORS' REPORT
TO THE DIRECTORS OF PETROFUND CORP.:
We have audited the consolidated balance sheet of Petrofund Energy Trust (an
Ontario open-ended investment Trust) as at December 31, 2003 and 2002 and the
consolidated statements of operations, unitholders' equity and cash flows for
the years then ended. These financial statements are the responsibility of the
management of Petrofund Corp. Our responsibility is to express an opinion on
these financial statements based on our audits.
We conducted our audits in accordance with Canadian generally accepted auditing
standards. Those standards require that we plan and perform an audit to obtain
reasonable assurance whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
In our opinion, these consolidated financial statements present fairly, in all
material respects, the financial position of Petrofund Energy Trust as at
December 31, 2003 and 2002 and the results of its operations and its cash flows
for the years then ended in accordance with Canadian generally accepted
accounting principles.
The consolidated financial statements of Petrofund Energy Trust for the year
ended December 31, 2001 were audited by other auditors who have ceased
operations. Those auditors expressed an opinion without reservation on those
financial statements in their report dated February 14, 2002. As described in
Note 18, the Trust adopted the new accounting standards with respect to asset
retirement obligations for United States reporting purposes and Note 18 includes
certain additional disclosures related thereto. We have audited the adjustments
described in Note 18 that were applied to provide the additional disclosures for
2001. In our opinion, such adjustments are appropriate and have been properly
applied. However, we were not engaged to audit, review or apply any procedures
to the 2001 consolidated financial statements of the Trust other than with
respect to such additional disclosures and, accordingly, we do not express an
opinion or any other form of assurance on the 2001 financial statements taken as
a whole.
(signed) Deloitte & Touche LLP
Chartered Accountants
Calgary, Alberta
February 6, 2004
(except as to Note 19 which
is as of April 30, 2004)
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THIS AUDITORS' REPORT IS A COPY OF THE REPORT PREVIOUSLY ISSUED BY ARTHUR
ANDERSEN LLP AND HAS NOT BEEN REISSUED IN CONNECTION WITH ITS INCLUSION HEREIN.
Auditors' Report
To the Unitholders of NCE Petrofund:
We have audited the consolidated balance sheet of NCE Petrofund (an Ontario
open-ended investment trust) as at December 31, 2001 and 2000 and the
consolidated statements of operations, unitholders' equity, cash flows and
distributions accruing to unitholders for each of the years in the three-year
period ended December 31, 2001. These financial statements are the
responsibility of the management of NCE Petrofund Management Corp. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with Canadian generally accepted auditing
standards. Those standards require that we plan and perform an audit to obtain
reasonable assurance whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
In our opinion, these consolidated financial statements present fairly, in all
material respects, the financial position of NCE Petrofund as at December 31,
2001 and 2000 and the results of its operations and its cash flows for each of
the years in the three-year period ended December 31, 2001 in accordance with
Canadian generally accepted accounting principles.
Calgary, Alberta (Signed) Arthur Andersen LLP
February 15, 2002 Chartered Accountants
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Consolidated Balance Sheet
(thousands of dollars)
As at December 31, 2003 2002
----------------------------------------------------------------------------------------
Assets
Current assets
Cash $ 2,182 $ -
Accounts receivable 48,268 41,953
Due from affiliates - 164
Prepaid expenses 10,036 10,090
----------------------------------------------------------------------------------------
Total current assets 60,486 52,207
Reclamation and abandonment reserve (Note 7) 3,779 3,001
Oil and gas royalty and property interests,
at cost less accumulated depletion and depreciation
of $468,208 (2002 - $354,309) (Notes 2 and 3) 879,633 835,366
----------------------------------------------------------------------------------------
$ 943,898 $ 890,574
----------------------------------------------------------------------------------------
Liabilities and unitholders' equity
Current liabilities
Bank overdraft $ - $ 1,572
Accounts payable and accrued liabilities 36,684 22,007
Payable to affiliates (Note 4) - 2,168
Current portion of capital lease obligations (Note 6) 356 3,304
Distributions payable to Unitholders 53,452 30,065
----------------------------------------------------------------------------------------
Total current liabilities 90,492 59,116
Long-term debt (Note 5) 109,707 212,253
Capital lease obligations (Note 6) 608 6,965
Future income taxes (Notes 2 and 15) 77,005 116,845
Accrued reclamation and abandonment costs 16,846 15,298
----------------------------------------------------------------------------------------
Total liabilities 294,658 410,477
Unitholders' equity (Notes 8 and 9) 649,240 480,097
----------------------------------------------------------------------------------------
$ 943,898 $ 890,574
----------------------------------------------------------------------------------------
Signed on behalf of Petrofund Energy Trust by Petrofund Corp.:
(signed) Jeffery E. Errico, Director (signed) James E. Allard, Director
The accompanying notes to consolidated financial statements are an integral part
of this consolidated balance sheet.
B-85
Consolidated Statement of Operations
(thousands of dollars)
For the years ended December 31, 2003 2002 2001
----------------------------------------------------------------------------------------------
Revenues
Oil and gas sales $ 393,109 $ 270,669 $ 244,512
Royalties, net of incentives (84,804) (50,427) (54,746)
----------------------------------------------------------------------------------------------
308,305 220,242 189,766
----------------------------------------------------------------------------------------------
Expenses
Lease operating 91,251 74,774 48,237
Management fee (Note 4) - 4,728 5,307
Interest on long-term debt (Note 5) 8,748 8,291 7,806
General and administrative (Note 4) 13,047 15,514 14,436
Capital taxes 2,454 2,137 1,719
Depletion and depreciation 113,899 98,777 68,453
Provision for reclamation and abandonment 6,199 5,856 3,680
Internalization of management contract (Note 9) 30,850 - -
----------------------------------------------------------------------------------------------
266,448 210,077 149,638
----------------------------------------------------------------------------------------------
Income before provision for income taxes 41,857 10,165 40,128
----------------------------------------------------------------------------------------------
Provision for (recovery of) income taxes (Note 15)
Current 569 38 1,701
Future (44,516) (14,252) (15,561)
----------------------------------------------------------------------------------------------
(43,947) (14,214) (13,860)
----------------------------------------------------------------------------------------------
Net income $ 85,804 $ 24,379 $ 53,988
----------------------------------------------------------------------------------------------
Net income per trust unit (Notes 2 and 16)
Basic $ 1.41 $ 0.49 $ 1.71
Diluted $ 1.40 $ 0.49 $ 1.71
----------------------------------------------------------------------------------------------
The accompanying notes to consolidated financial statements are an integral part
of these consolidated statements.
B-86
Consolidated Statement of Unitholders'
Equity
(thousands of dollars)
For the years ended December 31, 2003 2002 2001
----------------------------------------------------------------------------------------------
Balance, beginning of year $ 480,097 $ 398,702 $ 136,812
Units issued, net of issue costs (Note 8) 226,325 154,460 318,548
Exchangeable shares issued/ converted to Trust
units (Note 10) 10,518 - -
Redemption of exchangeable shares (Note 10) (2,792) - -
Net income 85,804 24,379 53,988
Distributions accruing to Unitholders (Note 12) (150,712) (97,444) (110,646)
----------------------------------------------------------------------------------------------
Balance, end of year $ 649,240 $ 480,097 $ 398,702
----------------------------------------------------------------------------------------------
The accompanying notes to consolidated financial statements are an integral part
of these consolidated statements.
B-87
Consolidated Statement of Cash Flows
(thousands of dollars)
For the years ended December 31, 2003 2002 2001
-----------------------------------------------------------------------------------------------
Cash provided by (used in):
Operating activities
Net income $ 85,804 $ 24,379 $ 53,988
Add items not affecting cash:
Depletion and depreciation 113,899 98,777 68,453
Provision for reclamation and abandonment 6,199 5,856 3,680
Future income taxes (44,516) (14,252) (15,561)
Actual abandonment costs incurred (Note 7) (4,651) (2,190) (384)
Internalization of management contract (Note 9) 30,850 - -
-----------------------------------------------------------------------------------------------
Cash flow 187,585 112,570 110,176
Net change in non-cash operating working capital
balances 6,410 (30,938) 18,334
-----------------------------------------------------------------------------------------------
Cash provided by operating activities 193,995 81,632 128,510
-----------------------------------------------------------------------------------------------
Financing activities
Bank loan (102,546) 83,470 14,216
Distributions paid (127,325) (85,218) (126,883)
Redemption of exchangeable shares (2,792) - -
Capital lease repayments (9,305) (11,366) (2,629)
Issuance of Trust units (Note 8) 214,002 55,821 161,409
Advances to affiliates (Note 4) - 948 -
-----------------------------------------------------------------------------------------------
Cash provided by (used in) financing activities (27,966) 43,655 46,113
-----------------------------------------------------------------------------------------------
Investing activities
Reclamation and abandonment reserve (Note 7) (776) (706) (447)
Acquisition of property interests (186,956) (158,516) (177,729)
Proceeds on disposition of properties 33,466 30,019 3,736
Cash acquired on acquisition (Note 3b) - 427 -
Internalization of management contract (Note 9) (8,009) - -
-----------------------------------------------------------------------------------------------
Cash used in investing activities (162,275) (128,776) (174,440)
-----------------------------------------------------------------------------------------------
Net change in cash 3,754 (3,489) 183
-----------------------------------------------------------------------------------------------
Cash (bank overdraft), beginning of year (1,572) 1,917 1,734
-----------------------------------------------------------------------------------------------
Cash (bank overdraft), end of year $ 2,182 $ (1,572) $ 1,917
===============================================================================================
Interest paid during the year $ 8,885 $ 8,016 $ 7,806
Income taxes paid during the year $ 842 $ 1,281 $ 1,065
The accompanying notes to consolidated financial statements are an integral part
of these consolidated statements.
B-88
Notes to consolidated financial statements
December 31, 2003, 2002 and 2001
1. ORGANIZATION
Petrofund Energy Trust ("Petrofund" or the "Trust") is an open-ended investment
trust created under the laws of the Province of Ontario pursuant to a trust
indenture, as amended from time to time (the "Trust Indenture"), between
Petrofund Corp. ("PC") and Computershare Trust Company of Canada (the
"Trustee"). Active operations commenced March 3, 1989. The beneficiaries of the
Trust are the holders of the trust units ("Unitholders").
PC, a wholly-owned subsidiary of the Trust, acquires oil and gas properties for
its own account and sells a royalty interest (the "Royalty") to the Trust. The
Royalty acquired from PC effectively transfers substantially all of the economic
interest in the oil and gas properties to the Trust. The Trust is entitled to
99% of the production revenue from properties purchased by PC, less operating
costs, general and administrative expenses, management fees (prior to 2003),
debt service charges (including principal and interest) and taxes payable by PC.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The consolidated financial statements have been prepared by the management of PC
following Canadian generally accepted accounting principles. The preparation of
financial statements requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities and disclosures of
contingencies at the date of the financial statements and the reported amounts
of revenues and expenses during the reporting period. Actual results could
differ from those estimated. The following significant accounting policies are
presented to assist the reader in evaluating these consolidated financial
statements.
(a) Basis of consolidation
The consolidated financial statements include the accounts of the Trust and its
wholly-owned subsidiaries, PC, 1518274 Ontario Ltd., NCE Management Services
Inc. ("NMSI"), which employed all of the personnel who provided services to the
Trust, and NCE Petrofund Management Corp. ("NCEP Management", the "Previous
Manager") collectively, the "Subsidiaries". NMSI and NCEP Management were
acquired to effect the internalization of management and the shares of 1518274
Ontario Limited are exchangeable into Trust units (see Notes 9 and 10).
(b) Oil and gas royalty and property interests
Oil and gas royalty and property interests are accounted for using the full cost
method of accounting whereby all costs of acquiring oil and gas royalty and
property interests and equipment are capitalized. General and administrative
costs and interest are not capitalized.
The provision for depletion and depreciation and the provision for site
reclamation and abandonment costs are computed using the unit-of-production
method based on the estimated gross proven oil and gas reserves. Proceeds on
sale or disposition of oil and gas royalty and property interests are credited
to oil and gas royalty and property interests, unless this results in a change
in the depletion and depreciation rate by 20% or more, in which case a gain or
loss is recognized in the consolidated statement of operations. The provision
for reclamation and abandonment costs is accumulated as a long-term liability,
which is reduced as actual expenditures are made.
The carrying value of the oil and gas royalty and property interests, net of
accumulated depletion and depreciation, accrued reclamation and abandonment
costs and future income taxes is limited to an amount equal to the estimated
future net revenue, net of production-related general and administrative costs,
B-89
reclamation and abandonment costs, and income taxes. Future net revenue was
calculated using year end oil and gas prices and costs.
Effective January 1, 2004, the carrying value of the oil and gas royalty and
property interests is limited to their fair value determined by the expected
discounted future revenue from the properties.
(c) Distributions payable to Unitholders
Distributions payable to Unitholders are equal to amounts received or receivable
by the Trust on the cash distribution date. Income earned, but not received, is
distributed on the cash distribution date following receipt.
(d) Future income taxes
The Trust follows the liability method of accounting for income taxes. Under
this method, income tax liabilities and assets are recognized for the estimated
tax consequences attributable to differences between the amounts reported in the
financial statements of the Subsidiaries and their respective tax bases, using
enacted income tax rates. The effect of a change in income tax rates on future
tax liabilities and assets is recognized in income in the period in which the
change occurs. Temporary differences arising on acquisitions result in future
income tax assets or liabilities.
The Trust is a taxable entity under the Income Tax Act (Canada) and is taxable
only on income that is not distributed or distributable to the Unitholders. As
the Trust distributes all of its taxable income to the Unitholders and meets the
requirements of the Income Tax Act (Canada) applicable to the Trust, no
provision for future income taxes in the Trust has been made.
(e) Net income per Trust unit
Basic net income per Trust unit is computed by dividing net income by the
weighted average number of Trust units outstanding for the period. Diluted per
unit amounts reflect the potential dilution that would occur if options to issue
Trust units were exercised and Trust units were issued. The treasury stock
method is used to determine the effect of dilutive instruments.
(f) Hedging activity
The Trust uses derivative instruments to reduce its exposure to commodity price
fluctuations. Gains and losses on contracts, all of which constitute effective
hedges, are deferred and recognized as a component of the price of the related
transaction.
(g) Trust unit incentive plan
A Trust Unit Incentive Plan (the "Unit Incentive Plan") was established
authorizing the issuance of options to acquire Trust units to directors, senior
officers, employees and consultants of NCEP, Management, NCE Petrofund Advisory
Corp., NMSI and certain other related parties, all of whom are deemed to be
employees of the Trust. No options have been issued since 2002.
The Trust has elected to prospectively adopt amendments to the recommendations
of the CICA on accounting for stock based compensation in accordance with the
transitional provisions contained therein. Under the amended recommendations,
the Trust must account for compensation expense based on the fair value of the
options at the grant date. As the Trust has not granted any options since
December 31, 2002, this change in accounting policy has no impact on the
consolidated financial statements.
For options granted in 2002, the Trust elected to continue accounting for
compensation expense based on the intrinsic value of the options at the grant
date and disclose pro forma net income and pro forma net income per Trust unit
as if the fair value method had been adopted retroactively. The exercise price
of options granted under the Unit Incentive Plan may be reduced in future
periods in accordance with the
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terms of the Unit Incentive Plan. The amount of the reduction cannot be
reasonably determined as it is dependent upon a number of factors including, but
not limited to, future prices received on the sale of oil and natural gas,
future production of oil and gas, and the determination of the amount to be
withheld from future distributions to fund capital expenditures. Therefore, it
is not possible to determine a fair value for the options granted under the Unit
Incentive Plan and compensation expense has been determined based on the excess
of the unit price over the reduced exercise price at the date of the financial
statements and recognized in income over the vesting period of the options with
a corresponding increase or decrease in contributed surplus. After the options
have vested, compensation expense is recognized in income in the period in which
a change in the market price of the Trust units or the exercise of the options
occurs. The compensation expense under this method in 2003 for the options
issued in 2002 is $2.0 million. Net income would have been reduced by this
amount and net income per Trust unit would have decreased by $0.03. For 2002,
net income would have been reduced by $60,000 with negligible impact on net
income per Trust unit.
Consideration paid upon the exercise of the options together with any amount
previously recognized in contributed surplus is recorded as an increase in
unitholders' capital.
3. ACQUISITIONS
(a) Solaris Oil & Gas Inc.
On February 7, 2003, PC acquired 100% of the outstanding common shares of
Solaris Oil & Gas Inc. for $7.4 million in cash and assumed $1.2 million of debt
including negative working capital and the outstanding bank loan.
The acquisition was accounted for using the purchase method. A summary of the
net assets acquired is as follows:
$000's
----------------------------------------------
Working capital $ (813)
Oil and gas properties 13,219
Bank loan (370)
Future income taxes (4,676)
----------------------------------------------
$ 7,360
----------------------------------------------
(b) NCE Energy Trust
On May 30, 2002, Petrofund Energy Trust acquired NCE Energy Trust for 0.2325 of
a Trust unit for each Trust unit on a tax-free rollover basis. The value
assigned to the Trust units of $13.024 per unit issued on the acquisition was
based on the average market value of the Trust units five days before and after
the acquisition was announced.
The acquisition was accounted for using the purchase method. A summary of the
net assets acquired is as follows:
$000's
----------------------------------------------
Working capital $ (39,518)
Oil and gas properties 165,254
Future income taxes (27,097)
----------------------------------------------
$ 98,639
----------------------------------------------
Prior to the acquisition, Petrofund advanced $37.3 million to NCE Energy Trust
to pay down the bank debt of NCE Energy Trust.
B-91
(c) Magin Energy Inc. ("Magin")
On June 25, 2001, PC acquired 93.6% of the outstanding common shares of Magin
and on July 3, 2001 acquired the remaining shares. Magin was amalgamated into PC
on July 3, 2001.
In total, PC acquired 38,338,535 Magin common shares for $58.6 million in cash,
8.5 million trust units with a deemed value of $18.56 per unit and the
assumption of $43.7 million of debt including negative working capital, the
outstanding bank loan and capital leases. In addition, other transaction costs
of $11.8 million were incurred.
The acquisition was accounted for using the purchase method. A summary of the
net assets acquired is as follows:
$000's
----------------------------------------------
Working capital $ (4,749)
Oil and gas properties 381,043
Bank loan (21,569)
Capital leases (17,359)
Future income taxes (109,790)
----------------------------------------------
$ 227,576
----------------------------------------------
4. RELATED PARTY TRANSACTIONS
(a) Management, advisory and administration agreement
PC, NCEP Management, the Previous Manager, and the Trust had entered
into an agreement which was amended from time to time, whereby the
Previous Manager was to provide management, advisory and administrative
services to PC and the Trust. During 2002 the Previous Manager was paid
a management fee equal to 3.25% of net operating income plus Alberta
Royalty Credit (2001- 3.75%). In addition the Previous Manager received
an investment fee of 1.5% (1.75% prior to January 1, 2002) of the
purchase cost of all properties purchased by PC other than replacement
properties, and a disposition fee equal to 1.25% (1.5% prior to January
1, 2002) of the sale price of properties sold. During 2002, the Previous
Manager received a management fee from PC of $4.7 million (2001 - $5.3
million). In addition, the Previous Manager received investment fees of
$1.3 million (2001 - $5.2 million), which were capitalized as part of
the acquisitions, and disposition fees of $116,000 (2001 - $3,000),
which reduced the proceeds of disposition. No management fees have been
charged directly to the Trust.
Due to the internalization of management, no fees were payable in 2003.
(See Note 9)
Under the terms of the agreement, the Previous Manager was entitled to
be reimbursed by PC for general and administrative expenses. In any
year, PC was to reimburse the Previous Manager no less than $240,000 and
no more than 5% of gross production revenue for general and
administrative expenses. To the extent that general and administrative
expenses exceed 5% of gross production revenue, PC was entitled to set
off and deduct the excess from its liability to pay management fees to
the Previous Manager.
(b) Management agreement
The Previous Manager had entered into an agreement with NMSI to provide
oil and gas investment, consulting, administrative and management
services to PC. An officer and director of the Previous Manager is the
sole beneficial shareholder of NMSI. During 2002 PC paid NMSI $11.7
million (2001 - $9.3 million) for accounting and administrative
services, which is included in general and administrative expenses and
$838,000 (2001 - $1.4 million) for project sourcing and evaluation
services, which have been capitalized to oil and gas properties. In
addition, PC reimbursed NMSI $300,000 (2001 - $600,000) for marketing
and other related equity issue costs. No amounts for
B-92
these services have been charged directly to the Trust. The amounts for
general and administrative expenses paid to NMSI are subject to the same
limitations noted for the Previous Manager in (a) above. Due to the
internalization of management, no amounts were paid to NMSI in 2003.
5. LONG-TERM DEBT
Under the loan agreements, PC has a revolving working capital operating facility
of $25 million and a syndicated facility of $240 million. Interest on the
working capital loan is at prime and interest on the syndicated facility varies
with PC's debt to cash flow ratio from prime to prime plus 75 basis points or,
at the Trust's option, banker's acceptances rates plus stamping fees. As at
December 31, 2003, there was no amount outstanding under the working capital
facility and $110 million outstanding under the syndicated facility.
The revolving period on the syndicated facility ends on May 28, 2004, unless
extended for a further 364 day period. In the event that the revolving bank line
is not extended at the end of the 364 day revolving period, no payments are
required to be made to non-extending lenders during the first year of the term
period. However, Petrofund will be required to maintain certain minimum balances
on deposit with the syndicate agent.
The limit of the syndicated facility is subject to adjustment from time to time
to reflect changes in PC's asset base.
The credit facility is secured by a debenture in the amount of $350 million
pursuant to which a Canadian chartered bank (the "Lender"), as principal and as
agent for the other lender, received a first ranking security interest on all of
PC's assets.
The loan is the legal obligation of PC. While principal and interest payments
are allowable deductions in the calculation of royalty income, the Unitholders
have no direct liability to the bank or to PC should the assets securing the
loan generate insufficient cash flow to repay the obligation.
Substantially all of the credit facility is financed with Bankers' Acceptances,
resulting in a reduction in the stated bank loan interest rates.
6. CAPITAL LEASE OBLIGATIONS
The future minimum lease payments under the capital leases are as follows:
$000's
--------------------------------------------------------------------------------
2004 $ 423
2005 621
--------------------------------------------------------------------------------
Total minimum lease payments 1,044
Less imputed interest at rates ranging from 7.37% to 8.425% (80)
--------------------------------------------------------------------------------
Obligation under capital leases 964
Current portion (356)
--------------------------------------------------------------------------------
Long-term portion $ 608
--------------------------------------------------------------------------------
7. RECLAMATION AND ABANDONMENT RESERVE
PC maintains a cash reserve to finance large and unusual oil and gas property
reclamation and abandonment costs by withholding distributions accruing to
Unitholders. At December 31, 2003, the cash reserve was $3.8 million (2002 -
$3.0 million, 2001 - $2.1 million). In 2003, PC increased the cash reserve by
withholding $776,000 (2002 - $706,000, 2001 - $447,000) from distributions
accruing to Unitholders.
In addition, routine ongoing reclamation and abandonment costs of $4.7 million
in 2003 (2002 - $2.2 million, 2001 - $384,000) were incurred and deducted from
distributions accruing to Unitholders.
B-93
8. TRUST UNITS
Number
Authorized: unlimited number of Trust units of Units $000's
-----------------------------------------------------------------------------------------
Issued
December 31, 2000 21,914,079 $ 321,344
Issued for cash 11,183,334 167,350
Issued for Magin acquisition (Note 3(c)) 8,464,399 157,139
Commissions and issue costs - (11,781)
Options exercised 341,305 5,620
Unit purchase plan 13,279 220
-----------------------------------------------------------------------------------------
December 31, 2001 41,916,396 639,892
Issued for cash 4,600,000 59,800
Issued for NCE Energy acquisition (Note 3(b)) 7,573,874 98,639
Commissions and issue costs - (4,190)
Options exercised 7,966 85
Unit purchase plan 10,184 126
-----------------------------------------------------------------------------------------
December 31, 2002 54,108,420 794,352
Issued for cash 15,800,000 204,440
Issued for internalization of management contract (Note 9) 100,244 1,123
Exchangeable shares converted 1,000,000 11,200
Commissions and issue costs - (11,001)
Options exercised 1,673,404 20,474
Unit purchase plan 6,509 89
-----------------------------------------------------------------------------------------
December 31, 2003 72,688,577 $ 1,020,677
-----------------------------------------------------------------------------------------
The Trust has a Distribution Reinvestment and Unit Purchase Plan (the "Plan")
for Canadian residents. Under the terms of the Plan, Unitholders can elect,
firstly, to reinvest their cash distributions and obtain either newly issued
units of the Trust directly from the Trust or previously issued units of the
Trust purchased in the open market and, secondly, to purchase for cash newly
issued units directly from the Trust.
For the years ended December 31, 2003 2002 2001
-------------------------------------------------------------------------------------
Distributions reinvested to acquire
previously issued units (000's) $ 4,095 $ 3,387 $ 6,979
Price per unit $ 13.20 $ 12.15 $ 16.61
Number of units acquired 310,276 278,797 420,100
Distributions reinvested
to acquire newly issued units (000's) $ 89 $ 126 $ 220
Price per unit $ 13.65 $ 12.36 $ 16.59
Number of units acquired 6,509 10,184 13,279
The weighted average Trust units/exchangeable shares outstanding are as follows:
For the twelve months ended December 31, 2003 2002 2001
-------------------------------------------------------------------------------------
Basic 61,010,105 49,921,523 31,593,378
Diluted 61,153,027 49,967,648 31,635,976
-------------------------------------------------------------------------------------
B-94
Trust units/exchangeable shares:
For the years ended December 31, 2003 2002 2001
--------------------------------------------------------------------------------------------
Trust units outstanding 72,688,577 54,108,420 41,916,396
Trust units issuable on exchangeable shares (Note 10) 939,147 - -
--------------------------------------------------------------------------------------------
73,627,724 54,108,420 41,916,396
--------------------------------------------------------------------------------------------
9. INTERNALIZATION OF MANAGEMENT
On April 29, 2003, PC purchased 100% of the outstanding shares of NCEP
Management, and NMSI. As a result of these transactions, all management
acquisition and disposition fees payable to the Previous Manager were eliminated
retroactive to January 1, 2003.
The total consideration paid was $30.9 million as detailed below.
Total Consideration $000's
---------------------------------------------------------------------------------------------------
Issuance of 1,939,147 exchangeable shares to the shareholder of the Previous Manager $ 21,718
Cash payment to Trust for the repayment of indebtedness owing by the Previous Manager 3,400
Issuance of 100,244 units to executive management 1,123
Cash payment to executive management 780
Cash payment for distributions on exchangeable shares and trust units from
January 1 to April 30, 2003, 1,326
Transaction costs 2,503
---------------------------------------------------------------------------------------------------
Total Purchase Price $ 30,850
---------------------------------------------------------------------------------------------------
To ensure an orderly transition of the services that were provided by the
Previous Manager through its offices in Toronto, PC entered into an agreement
with Sentry Select Capital Corp. ("Sentry") to provide certain services to the
Trust and PC until December 31, 2003, for a maximum cost of $2 million. The
amount incurred decreased from $1 million in the first quarter of 2003 to
$500,000 in the second quarter and to $250,000 in each of the third and fourth
quarters. As of December 31, 2003, Sentry no longer provides any services to
Petrofund or to any of its subsidiaries. Sentry is a company in which John
Driscoll, the Chairman of the Board of Directors of PC, owns a controlling
interest.
Prior to the acquisition, the Previous Manager was paid a management fee equal
to 3.25% of net operating income plus Alberta Royalty Credit, an investment fee
equal to 1.50% of the purchase price of all properties purchased by PC and a
disposition fee of 1.25% of properties sold, except replacement properties.
10. EXCHANGEABLE SHARES
The number of Exchangeable Shares to be issued in connection with the
internalization of the management contract was determined based on a negotiated
value of $12.17 per share as set out in the Information Circular dated March 10,
2003. For accounting purposes, the 1,939,147 Exchangeable Shares were deemed to
be issued at a value of $11.20 per share, being the average trading value of the
Trust units for the last ten days prior to the closing date. Initially, each
Exchangeable Share was exchangeable into one Trust Unit. The exchange ratio is
adjusted from time to time to reflect the per unit distributions paid to
unitholders after the closing date. Under the terms of the Exchangeable Share
Agreement, the holder of the Exchangeable Shares is entitled to redeem for cash
the number of shares equal to the cash distributions that would have been
received had the Exchangeable Shares been converted to Trust units. As a result
of the redemption feature, the number of Trust units issuable upon conversion is
expected to remain constant over time. As the substance of this feature is to
allow the holder of the Exchangeable Shares to receive cash distributions, the
redemption has been accounted for as a distribution of earnings rather than a
return of capital. In 2003, 181,041 Exchangeable Shares were redeemed for $2.8
million in cash.
B-95
On December 17, 2003, 906,635 Exchangeable Shares were converted to 1,000,000
Trust units at a rate of 1.10298. At December 31, 2003, 851,471 Exchangeable
Shares were outstanding, at an exchange ratio of 1.10298 per Trust unit.
Issued and Outstanding Number of Shares $000's
--------------------------------------------------------------------------------------
Issued for Internalization of Management Contract 1,939,147 $ 21,718
Redemption of shares (181,041) -
Exchanged for Trust units (906,635) (11,200)
---------------------------------------------------------------------------------
Balance, December 31, 2003 851,471 10,518
Exchange ratio, end of period 1.10298 -
---------------------------------------------------------------------------------
Trust units issuable upon conversion 939,147 $ 10,518
---------------------------------------------------------------------------------
11. UNIT INCENTIVE PLAN
A total of 5,200,000 units have been reserved for issuance under the Unit
Incentive Plan of which 2,254,100 have been issued as at December 31, 2003.
A summary of the status of the Unit Incentive Plan as of December 31, 2003, 2002
and 2001, and changes during the years then ended is presented below:
For the years ended
December 31, 2003 2002 2001
-----------------------------------------------------------------------------------------------------------
Weighted Weighted Weighted
Average Average Average
Exercise Exercise Exercise
Units Price Units Price Units Price
----- ----- ----- ----- ----- -----
Options outstanding,
beginning of year 3,028,280 $ 13.21 1,840,190 $ 15.92 941,278 $ 16.71
Issued - - 1,468,100 10.65 1,477,800 17.65
Forfeited (555,754) 16.82 (272,044) 16.66 (237,583) 18.38
Exercised (1,673,404) 12.88 (7,966) 10.65 (341,305) 16.47
-----------------------------------------------------------------------------------------------------------
Options outstanding before
reduction of exercise
price 799,122 $ 14.74 3,028,280 $ 13.31 1,840,190 $ 17.29
Reduction of exercise price - (1.81) - (0.10) - (1.37)
-----------------------------------------------------------------------------------------------------------
Options outstanding,
end of year 799,122 $ 12.93 3,028,280 $ 13.21 1,840,190 $ 15.92
-----------------------------------------------------------------------------------------------------------
Options exercisable,
end of year 440,656 $ 15.36 1,593,681 $ 14.10 745,565 $ 16.08
-----------------------------------------------------------------------------------------------------------
The options granted in 2002 and 2001 are exercisable at the original option
prices, which were the market prices of the units on the date of the grants, or
if so elected by the participant, at reduced prices as described below. The
option prices are reduced for each calendar quarter ending after the date of the
grant by the positive amount, if any, equal to the amount by which the aggregate
distributions made by the Trust in any calendar quarter ending after the date of
the grant exceed 2.5% of the oil and gas royalty and property interests on the
Trust's consolidated balance sheet at the beginning of the applicable calendar
quarter divided by the issued and outstanding units at the beginning of the
applicable quarter.
The following table summarizes the options outstanding at December 31, 2003:
Number Exercise Reduced Exercise
of Units Price Price Expiry Date
------------------------------------------------------------------------------
4,689 $ 15.00 N/A May 8, 2005
280,666 $ 19.35 $ 16.23 January 30, 2006
109,067 $ 17.25 $ 14.78 April 4, 2006
21,800 $ 14.71 $ 13.31 July 20, 2006
382,900 $ 10.65 $ 9.93 July 25, 2007
B-96
12. Distributions accruing to unitholders
Under the terms of the Trust Indenture, the Trust makes monthly distributions
within a specified period following the end of each month ("Cash Distribution
Date"). Distributions are equal to amounts received by the Trust on the Cash
Distribution Date less permitted expenses. Distributions to Unitholders coincide
with cash receipts of royalty income from PC. An overall analysis is as follows:
For the period ended Cash Distribution Date 2003 2002 2001
-----------------------------------------------------------------------------------------------
November 30 January 31 $ 0.15 $ 0.15 $ 0.42
December 31 February 28 0.16 0.15 0.42
January 31 March 31 0.17 0.13 0.42
February 28 April 30 0.17 0.13 0.42
March 31 May 31 0.18 0.14 0.45
April 30 June 30 0.18 0.14 0.45
May 31 July 31 0.18 0.14 0.36
June 30 August 31 0.18 0.14 0.32
July 31 September 30 0.18 0.14 0.25
August 31 October 31 0.18 0.15 0.25
September 30 November 30 0.18 0.15 0.25
October 31 December 31 0.18 0.15 0.23
-----------------------------------------------------------------------------------------------
Cash Distributions per Trust unit $ 2.09 $ 1.71 $ 4.24
-----------------------------------------------------------------------------------------------
Reconciliation of Distributions Accruing to Unitholders
(thousands of dollars except per unit amounts)
For the years ended December 31, 2003 2002 2001
-----------------------------------------------------------------------------------------------
Distributions payable, beginning of year $ 30,065 $ 12,188 $ 28,425
-----------------------------------------------------------------------------------------------
Distributions accruing during the year
Cash flow from operating activities 187,585 112,570 110,176
Redemption of exchangeable shares (2,792) - -
Proceeds on disposition of property interests - 946 3,546
Reclamation and abandonment reserve (776) (706) (447)
Less capital lease repayment (2) (3) (3,305) (5,366) (2,629)
Capital expenditures (30,000) (10,000) -
-----------------------------------------------------------------------------------------------
Total distributions accruing during the year 150,712 97,444 110,646
NCE Energy Trust cash flow (1) - 5,651 -
-----------------------------------------------------------------------------------------------
Total distributable income for the year 150,712 103,095 110,646
-----------------------------------------------------------------------------------------------
Distributions paid (127,325) (85,218) (126,883)
-----------------------------------------------------------------------------------------------
Distributions payable, end of year (4) $ 53,452 $ 30,065 $ 12,188
-----------------------------------------------------------------------------------------------
Distributions accruing to Unitholders per Trust unit
Basic $ 2.47 $ 2.07 $ 3.50
Diluted $ 2.46 $ 2.06 $ 3.49
(1) Remaining undistributed cash flow of NCE Energy Trust on May 30, 2002 (see
Note 3b).
(2) Net of $6 million refinanced by increased bank loan in 2002.
(3) Net of $6 million refinanced by increased bank loan in 2003.
(4) It is expected that a portion of this amount will be used to fund capital
expenditures.
13. FINANCIAL INSTRUMENTS
The Trust's financial instruments consist of cash, accounts receivable and
payable, long-term debt, capital lease obligations and derivative instruments.
As at December 31, 2003, the carrying value of the cash and accounts receivable
and payable approximated their fair value due to their short-term nature. The
carrying
B-97
value of the long-term debt approximated its fair value due to the floating rate
of interest charged under the facilities. The carrying value of the capital
lease obligations is not significantly different from their fair values.
The derivative instruments have no carrying value (see Note 14). The derivative
instruments at December 31, 2003, had a negative fair value of $6.8 million
based on quotes provided by brokers. This fair value represents an approximation
of amounts that would be paid to counterparties to settle these instruments at
the balance sheet date. The Trust plans to hold all derivative instruments
outstanding at December 31, 2003, to maturity.
14. DERIVATIVE FINANCIAL INSTRUMENTS AND PHYSICAL CONTRACTS
The Trust enters into various pricing mechanisms to reduce price volatility and
establish minimum prices for a portion of its oil and gas production. These
include fixed-price contracts and the use of derivative financial instruments.
The outstanding derivative financial instruments, all of which constitute
effective hedges, and the related unrealized gains or losses, and physical
contracts as at December 31, 2003, are summarized separately below:
Unrealized
Volume Price Delivery Gain (Loss)
Natural Gas Term mcf/d $/mcf Point $000's
----------------------------------------------------------------------------------------------
Collar November 1, 2003 to 9,475 $6.23-$8.34 AECO $ 118
March 31, 2004
Collar November 1, 2003 to 9,475 $5.80-$10.98 AECO 164
March 31, 2004
Fixed January 1, 2004 to 4,737 $6.07 AECO (316)
March 31, 2004
Fixed January 1, 2004 to 4,737 $6.23 AECO (246)
March 31, 2004
Fixed January 1, 2004 to 4,737 $6.81 AECO 18
March 31, 2004
Fixed January 1, 2004 to 4,737 $7.39 AECO 255
March 31, 2004
Collar April 1, 2004 to 9,475 $5.17-$7.28 AECO 268
October 31, 2004
Collar April 1, 2004 to 9,475 $5.07-$6.81 AECO (66)
October 31, 2004
Collar April 1, 2004 to 1,895 $5.28-$7.39 AECO 56
October 31, 2004
Fixed April 1, 2004 to 4,737 $5.33 AECO (550)
October 31, 2004
Collar November 1, 2004 to 9,475 *(1) AECO 54
March 31, 2005
----------------------------------------------------------------------------------------------
Total $ (245)
----------------------------------------------------------------------------------------------
*(1) At Prices above $8.97/mcf Petrofund receives $8.97/mcf.
At Prices between $5.80/mcf and $8.97/mcf receives the market
price. At Prices below $4.74/mcf Petrofund receives a premium
of $1.06/mcf.
B-98
Unrealized
Volume Price Delivery Gain (Loss)
Oil Term bb/d $/bbl Point $000's
-----------------------------------------------------------------------------------------------------
Fixed Price January 1, 2004 to 1,995 $38.59 Edmonton $ (897)
June 30, 2004
Fixed Price July 1, 2004 to 668 $36.41 Edmonton (186)
December 31, 2004
Collar January 1, 2004 to 2,000 $31.12-$35.98 Edmonton (999)
March 31, 2004
Three Way Collar January 1, 2004 to 2,000 *(1) Edmonton (1,478)
June 30, 2004
Collar April 1, 2004 to 2,000 $31.12-$36.56 Edmonton (768)
June 30, 2004
Three Way Collar July 1, 2004 to 2,000 *(2) Edmonton (892)
December 31, 2004
Collar July 1, 2004 to 2,000 $31.12-$36.30 Edmonton (591)
September 30, 2004
Collar October 1, 2004 to 2,000 $31.12-$36.30 Edmonton (505)
December 31, 2004
Three Way Collar January 1, 2005 to 1,000 *(3) Edmonton (516)
December 31, 2005
-----------------------------------------------------------------------------------------------------
Total $ (6,832)
-----------------------------------------------------------------------------------------------------
*(1) At Prices above $37.27 Petrofund receives $37.27/bbl.
At Prices between $31.12 and $37.27/bbl Petrofund receives the
market price. At Prices below $27.55 Petrofund receives a
premium of $3.89/bbl.
*(2) At Prices above $37.60 Petrofund receives $37.60/bbl.
At Prices between $31.45 and $37.60/bbl Petrofund receives the
market price. At Prices below $27.87 Petrofund receives a
premium of $3.89/bbl.
*(3) At Prices above $37.60 Petrofund receives $37.60/bbl.
At Prices between $31.12 and $37.60/bbl Petrofund receives the
market price. At Prices below $25.93 Petrofund receives a
premium of $5.19/bbl.
All the oil hedges are at U.S. WTI prices and have been converted to Canadian
dollars at the year end exchange rate of $1.2965 C$:US$.
Unrealized
Volume Price Delivery Gain (Loss)
Electricity Term MW/h $/MWh Point $000's
-----------------------------------------------------------------------------------------------------
Fixed Price January 1, 2004 to 3.0 $ 44.50 Alberta Power $ 303
December 31, 2005 Pool
-----------------------------------------------------------------------------------------------------
B-99
The gains or losses are recognized on a monthly basis over the terms of the
contracts and adjust the prices received.
Derivative financial instruments and physical hedge contracts involve a degree
of credit risk, which the Trust controls through the use of financially sound
counterparties. Market risk relating to changes in value or settlement cost of
the Trust's derivative financial instruments is essentially offset by gains or
losses on the underlying physical sales.
15. INCOME TAXES
The future income tax liability (asset) includes the following temporary
differences (thousands of dollars):
As at December 31, 2003 2002 2001
--------------------------------------------------------------------------------------------------
Oil and gas properties $ 77,005 $ 119,825 $ 106,961
Resource allowance - (2,980) (2,961)
--------------------------------------------------------------------------------------------------
$ 77,005 $ 116,845 $ 104,000
--------------------------------------------------------------------------------------------------
The provision for current and future income taxes differs from the result which
would be obtained by applying the combined federal and provincial statutory tax
rates to income before income taxes. This difference results from the following:
For the years ended December 31, 2003 2002 2001
--------------------------------------------------------------------------------------------------
Income before income tax provision $ 41,857 $ 10,165 $ 40,128
--------------------------------------------------------------------------------------------------
Income tax provision computed at statutory rates $ 17,052 $ 4,294 $ 17,304
Effect on income tax of:
Income attributed to the Trust (41,468) (24,435) (32,665)
Internalization of management contract 12,568 - -
Non-deductible crown charges,
net of Alberta Royalty Credit 24,190 17,055 19,276
Resource allowance (20,730) (15,045) (16,661)
Capital taxes 1,000 831 1,130
Income tax rate reductions on opening balances (36,688) - (329)
Temporary differences in resource allowance - (19) (2,427)
Other 129 3,105 512
--------------------------------------------------------------------------------------------------
Provision for (recovery of) income taxes $ (43,947) $ (14,214) $ (13,860)
--------------------------------------------------------------------------------------------------
The petroleum and natural gas properties and facilities owned by the
Subsidiaries have a tax basis of $232.7 million ($212 million - 2002, $153.3
million - 2001) available for future use as deductions from taxable income.
Included in this tax basis are non-capital loss carry forwards of $43.6 million
($34.0 million - 2002, $33.6 million - 2001), which could expire in various
years through 2010.
16. NET INCOME PER TRUST UNIT
Basic per unit calculations are based on the weighted average number of Trust
units and exchangeable shares outstanding. Diluted calculations include
additional Trust units for the dilutive impact of options. There were no
adjustments to net income in calculating diluted per Trust unit amounts.
The weighted average units/exchangeable shares outstanding are as follows:
For the years ended December 31, 2003 2002 2001
--------------------------------------------------------------------------------------------------
Basic 61,010,105 49,921,523 31,593,378
Diluted 61,153,027 49,967,648 31,635,976
B-100
17. LONG TERM COMMITMENTS
PC has the following long term commitments for the years indicated:
(thousands of dollars) 2004 2005 2006 2007 2008
-------------------------------------------------------------------------------------------
Capital leases (Note 6) $ 0.4 $ 0.6 $ - $ - $ -
Office lease 1.1 0.8 - - -
Processing & transportation agreement 1.8 1.8 2.0 2.1 2.2
CO2 purchases 3.9 4.7 4.1 3.5 3.3
-------------------------------------------------------------------------------------------
$ 7.2 $ 7.9 $ 6.1 $ 5.6 $ 5.5
-------------------------------------------------------------------------------------------
18. DIFFERENCES BETWEEN CANADIAN AND UNITED STATES
GENERALLY ACCEPTED ACCOUNTING PRINCIPLES ("GAAP")
The Trust's consolidated financial statements have been prepared in accordance
with Canadian generally accepted accounting principles ("Canadian GAAP"). These
principles, as they pertain to the Trust's consolidated financial statements,
differ from United States generally accepted accounting principles ("U.S. GAAP")
as follows:
(a) The Canadian GAAP ceiling test is comparable to the Securities
and Exchange Commission ("SEC") method using constant prices,
costs and tax legislation except that the SEC requires the
resulting amounts to be discounted at 10%. In addition, the SEC
does not require the inclusion of any general and administrative
or interest expenses in the calculation.
(b) U.S. GAAP utilizes the concept of comprehensive income, which
includes items not included in net income. At the current time,
there is no similar concept under Canadian GAAP.
(c) Effective January 1, 2001, for U.S. reporting purposes, the Trust
adopted Statement of Financial Accounting Standards ("SFAS") No.
133, "Accounting for Derivative Instruments and Hedging
Activities." SFAS 133 establishes accounting and reporting
standards requiring that all derivative instruments (including
derivative instruments embedded in other contracts), as defined,
be recorded in the balance sheet as either an asset or a
liability measured at fair value and requires that changes in
fair value be recognized currently in income unless specific
hedge accounting criteria are met. There are no similar standards
under Canadian GAAP at this time.
Hedge accounting treatment allows unrealized gains and losses to
be deferred in other comprehensive income (for the effective
portion of the hedge) until such time as the forecasted
transaction occurs and requires that an entity formally
document, designate and assess effectiveness of derivative
instruments that receive hedge accounting treatment. Upon
adoption, the Trust formally documented and designated all
hedging relationships and verified that its hedging instruments
are effective in offsetting changes in actual prices received by
the Trust. Such effectiveness is monitored at least quarterly
and any ineffectiveness is reported in other revenues (losses)
in the consolidated statement of operations. In 2003, the Trust
has elected to use fair value accounting for its derivative
instruments for U.S. GAAP and the change in fair value of these
contracts has been reported in income.
(d) Prior to January 1, 2003, for Canadian GAAP purposes,
compensation expense for options granted under the Unit Incentive
Plan was measured based on the intrinsic value of the award at
the grant date. For the years ended December 31, 2003, and 2002,
pro forma disclosures are included in the notes to the financial
statements of the impact on net income and net income per Trust
unit had the Trust accounted for compensation expense based on
the fair value of options granted during 2002. Effective January
1,
B-101
2003, the Trust accounts for compensation expense for options
granted on or after January 1, 2003, based on the fair value
method of accounting as described in Note 2g.
For U.S. GAAP purposes, the Unit Incentive Plan is a variable
compensation plan as the exercise price of the options is
subject to downward revisions from time to time. Accordingly,
compensation expense is determined as the excess of the market
price of the Trust units over the adjusted exercise price of the
options at each financial reporting date and is deferred and
recognized in income over the vesting period of the options.
After the options have vested, compensation expense is
recognized in income in the period in which a change in the
market price of the Trust units or the exercise price of the
options occurs.
At December 31, 2001, the exercise price of the options granted
under the Unit Incentive Plan exceeded the market price of the
Trust units. Therefore, no compensation expense was recorded in
2001. No options have been granted subsequent to December 31,
2002.
(e) In June 2001, the U.S. Financial Accounting Standards Board
issued Statement No. 143, "Accounting for Asset Retirement
Obligations" (FAS 143). FAS 143 requires recognition of a
liability for the future retirement obligations associated with
property, plant and equipment. These obligations are initially
measured at fair value, which is the discounted future value of
the liability. The liability is accreted each period for the
change in present value and the accretion expense is charged to
income. The fair value of the liability is capitalized as part of
the cost of the related asset and amortized to expense over its
useful life. The Trust adopted FAS 143 effective January 1, 2003,
for U.S. reporting purposes and the cumulative effect adjustment
from initial application has been charged to net income in the
current year. Under current Canadian GAAP prior to asset
retirement obligations are accrued using the unit-of-production
method based on the undiscounted value of the liability.
Effective January 1, 2004, the Trust must adopt new Canadian
accounting standards for accounting for asset retirement
obligations which are expected to eliminate this difference in
future years.
Under the old accounting rules, the Trust's net income under the
US GAAP would have been:
($000's) 2003
----------------------------------------------------------------
Net income under US GAAP, as reported $ 94,697
Cumulative effect of change in accounting principle 2,419
Depletion and depreciation 2,164
Asset retirement obligation (3,955)
Future income taxes 320
----------------------------------------------------------------
Net income under US GAAP, as adjusted $ 95,645
----------------------------------------------------------------
Net income per unit, as adjusted, - basic $ 1.57
- diluted $ 1.56
Had FAS 143 been applied during all periods presented, the asset
retirement obligation would have been reported as follows:
($000's) As reported Pro Forma
-----------------------------------------------------------------
January 1, 2002 $ 11,631 $ 33,771
December 31, 2002 $ 15,298 $ 34,496
December 31, 2003 $ 34,363 $ 34,363
The change in the asset retirement obligation since the
beginning of the year is as follows:
B-102
($000's) 2003
-----------------------------------------------------------------
Asset retirement obligation at January 1 $ 34,496
Obligation incurred 2,274
Abandonment expenditures (4,651)
Accretion 2,244
-----------------------------------------------------------------
Asset retirement obligation at December 31 $ 34,363
-----------------------------------------------------------------
Had FAS 143 been applied during all periods presented, the
December 31, 2002 and 2001 results would have been reported as
follows:
($000's, except per unit amounts) 2002 2003
-----------------------------------------------------------------
Net income - US GAAP
As reported $ 38,598 $ (98,924)
DD&A and accretion (4,408) (4,475)
-----------------------------------------------------------------
Adjusted $ 34,190 $(103,399)
-----------------------------------------------------------------
Earnings per unit ($/unit)
Basic as reported $ 0.77 $ (3.16)
Adjusted 0.68 (3.27)
Diluted as reported $ 0.77 $ (3.16)
Adjusted 0.68 (3.27)
(f) In November 2002, the FASB issued Interpretation No. 45,
"Guarantors' Accounting and Disclosure Requirements for
Guarantees, Including Indirect Guarantees of Indebtedness of
Others" (FIN 45). FIN 45 elaborates on the disclosures that must
be made regarding obligations under certain guarantees issued by
the Trust. It also requires that the Trust recognize, at the
inception of a guarantee, a liability for the fair value of the
obligations undertaken in issuing the guarantee. The initial
recognition and initial measurement provisions are to be applied
to guarantees issued or modified after December 31, 2002. There
are no guarantees outstanding at December 31, 2003.
(g) The Trust presents cash flow before changes in non-cash operating
working capital as a subtotal in the Consolidated Statement of
Cash Flows. This line item would not be presented in a cash flow
statement prepared in accordance with U.S. GAAP. This difference
does not result in an adjustment to the financial results as
reported under the Canadian GAAP.
Under US GAAP, the Trust's bank overdraft would be presented as
a financing activity rather that as a component of cash.
Therefore, cash provided by (used in) financing activities under
US GAAP would be $(29,538) in 2003 (2002 - $45,227; 2001 -
$46,113).
The net change in non-cash operating working capital balances is
comprised of the following:
($000's) 2003 2002 2001
------------------------------------------------------------------------------
Accounts receivable $ (6,315) $ (28,987) $ 3,290
Due from affiliates 164 - -
Prepaids and deposits 54 (5,506) 428
Accounts payable and accrued liabilities 14,677 687 15,157
Payable to affiliates (2,168) - -
------------------------------------------------------------------------------
$ 6,410 $ 33,806 $ 18,875
------------------------------------------------------------------------------
(h) Under US GAAP, interest expense would be classified as a
non-operating expense in the statement of operations.
B-103
(i) Accounts payable and accrued liabilities is comprised of the
following:
($000's) 2003 2002
-----------------------------------------------------------------
Accounts payable $ 20,959 $ 9,959
Accrued capital expenditures 12,295 10,099
Other accrued liabilities 3,430 1,949
-----------------------------------------------------------------
$ 36,684 $ 22,007
-----------------------------------------------------------------
(j) The following pro forma amounts would have been realized by the Trust in
2002 and 2001 had the acquisition of NCE Energy Trust occurred on January 1,
2001:
$000's, except per unit amounts) 2003 2002
-----------------------------------------------------------------
(Unaudited)
Net revenues after royalties $ 238,700 $ 280,100
Net income 26,200 61,500
Net income per Trust unit 0.50 1.42
(k) Under US GAAP, the number of authorized and issued Trust units
and Exchangeable Shares would be disclosed on the face of the
balance sheet. This information is disclosed in Notes 8 and 10.
The following presents the consolidated statement of
Unitholders' Equity for the three years ended December 31, 2003
under US GAAP:
B-104
Petrofund Energy Trust
Consolidated Statement of Unitholders' Equity (US GAAP)
For the Three Years Ended December 31, 2003
Accumulated
Other
Unitholder's Exchangeable Accumulated Retained Comprehensive
(000's) Capital Shares Distributions Earnings Income Total
-------------------------------------------------------------------------------------------------------------------------
December 31, 2000 $ 321,344 $ - $ (219,505) $ 32,106 $ - $ 133,945
Units issued 324,489 - - - - 324,489
Commissions & issue costs (11,781) - - - - (11,781)
Options exercised 5,620 - - - - 5,620
Unit purchase plan 220 - - - - 220
Net Income - - - (99,956) - (99,956)
Comprehensive income - unrealized
gain (loss) on derivatives - - - - 1, 032 1,032
Distribution accruing to unitholders - - (110,646) - - (110,646)
-------------------------------------------------------------------------------------------------------------------------
December 31, 2001 639,892 - (330,151) (67,850) 1,032 242,923
-------------------------------------------------------------------------------------------------------------------------
Units issued 158,439 - - - - 158,439
Commissions & issue costs (4,190) - - - - (4,190)
Options exercised 85 - - - - 85
Unit purchase plan 126 - - - - 126
Net Income - - - 40,081 - 40,081
Comprehensive income - unrealized
gain (loss) on derivatives - - - - (1,483) (1,483)
Stock based compensation expense 59 - - - - 59
Distribution accruing to unitholders - - (94,444) - - (97,444)
-------------------------------------------------------------------------------------------------------------------------
December 31, 2002 794,411 - (427,595) (27,796) (451) 338,596
-------------------------------------------------------------------------------------------------------------------------
Units issued 205,563 - - - - 205,563
Exchangeable shares issued - 21,718 - - - 21,718
Exchangeable shares converted 11,200 (11,200) - - - -
Redemption of exchangeable shares - - (2,792) - - (2,792)
Commissions & issue costs (11,001) - - - - (11,001)
Options exercised 20,474 - - - 20,474
Unit purchase plan 89 - - - - 89
Net Income - - - 94,697 - 94,697
Comprehensive income - unrealized
gain (loss) on derivatives - - - - 451 451
Stock based compensation expense 3,144 - - - - 3,144
Distribution accruing to unitholders - - (150,712) - - (150,712)
-------------------------------------------------------------------------------------------------------------------------
December 31, 2003 $ 1,023,880 $ 10,518 $ (581,099) $ 66,928 $ - $ 520,227
-------------------------------------------------------------------------------------------------------------------------
B-105
(l) The following standards issued by the FASB do not have an impact
on the Trust, at the current time:
o FAS 150 "Accounting for Certain Instruments with
Characteristic of Book Liabilities and Equity".
o FIN 46 and FIN 46-R "Consolidation of Variable Interest
Entities".
The Trust will continue to assess the applicability of these
standards in the future.
The application of U.S. GAAP would have the following effects on net income as
reported:
For the years ended December 31, ($000's) 2003 2002 2001
-----------------------------------------------------------------------------------------------------------
Net income as reported in consolidated
statement of operations $ 85,804 $ 24,379 $ 53,988
Adjustments:
Unrealized loss on derivatives (6,774) (563) -
Compensation expense (3,144) (59) -
Depletion and depreciation 21,098 24,552 1,550
Asset retirement obligation 3,955 - -
Ceiling test write down - - (221,886)
Deferred income taxes (3,823) (8,228) 66,392
-----------------------------------------------------------------------------------------------------------
Net income, as adjusted, before cumulative
effect of a change in accounting principle 97,116 40,081 (99,956)
Cumulative effect of a change in accounting
principle, net of income taxes (2,419) - -
-----------------------------------------------------------------------------------------------------------
Net income, as adjusted, after cumulative effect 94,697 40,081 (99,956)
Unrealized gain (loss) on derivatives, net of income tax
expense (recovery) of $330 (2002 -$(1,113), 2001 - $783) 451 (1,483) 1,032
-----------------------------------------------------------------------------------------------------------
Comprehensive income $ 95,148 $ 38,598 $(98,924)
Net income (loss) per unit, as adjusted
before accumulative effect
Basic $ 1.59 $ 0.77 $ (3.16)
Diluted $ 1.59 $ 0.77 $ (3.16)
Net income (loss) per unit, as adjusted
after cumulative effect
Basic $ 1.55 $ 0.77 $ (3.16)
Diluted $ 1.55 $ 0.77 $ (3.16)
Accumulated other comprehensive income:
For the years ended December 31, ($000's) 2003 2002 2001
-----------------------------------------------------------------------------------------------------------
Opening balance at January 1 $ (451) $ 1,032 $ -
Unrealized gain (loss) on derivatives, net of income tax
expense (recovery) of $330 (2002 - $(1,113), 2001 - $783) 451 (1,483) 1,032
-----------------------------------------------------------------------------------------------------------
Closing balance at December 31 $ - $ (451) $ 1,032
B-106
The application of US GAAP would have the following effects on the consolidated
balance sheet as reported:
Increase
As at ($000's) As reported (Decrease) US GAAP
---------------------------------------------------------------------------------------------------
December 31, 2003
Oil and gas derivative instruments $ - $ (6,774) $ (6,774)
Oil and gas royalty and property interests, net 879,633 (157,172) 722,461
Future income taxes 77,005 (52,450) 24,555
Accrued reclamation and abandonment costs 16,846 17,517 34,643
Unitholders' equity 649,240 (129,013) 520,227
December 31, 2002
Oil and gas derivative instruments $ - $ (1,194) $ (1,194)
Oil and gas royalty and property interests, net 835,366 (198,651) 632,715
Future income taxes 116,845 (58,344) 58,501
Unitholders' equity 480,097 (141,501) 338,596
19. SUBSEQUENT EVENT
On March 29, 2004, Petrofund and Ultima Energy Trust ("Ultima") announced that
they had entered into an agreement providing for the combination of Petrofund
and Ultima. Under the terms of the agreement, each Ultima unit will be exchanged
for 0.422 of a Petrofund unit on a tax-deferred rollover basis. Subject to
regulatory approval and the approval of Ultima unitholders by a majority vote of
at least two-thirds at a meeting to be held on or about June 4, 2004, the
transaction is expected to close on or about June 16, 2004.
B-107
ADDITIONAL INFORMATION
The following information has been prepared utilizing information contained in
the Information Circular of Petrofund Energy Trust dated February 27, 2004 (the
"Information Circular") which was prepared in connection with the annual and
special meeting of holders of trust units of Petrofund Energy Trust held April
14, 2004 (the "Meeting") and updating such information to reflect, among other
things, the result of voting on certain matters which were placed before such
Meeting.
GLOSSARY OF TERMS
The following terms used in the discussion that follows shall have the
meanings set out below:
"Board of Directors" or "Board" means the Board of Directors of PC;
"Business Day" means a day which is not (i) a Saturday or a Sunday; or (ii) a
day observed as a holiday under the laws of the Province of Ontario, the
Province of Alberta or the federal laws of Canada applicable therein;
"HR&C Committee" means the Human Resources and Compensation Committee of the
Board of Directors;
"Internalization" or "Internalization Transaction" means Petrofund's indirect
purchase of all of the shares of the Previous Manager and related transactions
which were completed in April, 2003. Pursuant to the Internalization, Petrofund
acquired all of the shares of the Previous Manager, a party to the Management
Agreement, and all of the shares of NCE Services, which employed all of the
Calgary-based personnel who provided management, operational and administrative
services to PC and Petrofund;
"Management Agreement" means the amended and restated management, advisory and
administration agreement dated as of January 1, 2002 among PC, the Trustee and
the Manager;
"Manager" means the Previous Manager;
"Meeting" means the annual and special meeting of Unitholders to be held on
Wednesday, April 14, 2004 at 2:00 p.m. MST (Calgary time), and any adjournment
thereof;
"NCE Services" means NCE Management Services Inc.;
"Ordinary Resolution" means a resolution approved in writing by Unitholders
holding not less than 50% of the outstanding Units or a resolution passed at a
meeting of Unitholders (including an adjourned meeting) duly convened for the
purpose and held in accordance with the provisions of the Trust Indenture and
passed by the affirmative votes either in person or by proxy of the holders of
not less than 50% of the Units represented at the meeting;
"PC" means Petrofund Corp.;
"PC Exchangeable Shares" means non-voting exchangeable shares in the capital of
PC;
"Petrofund" or the "Trust" means Petrofund Energy Trust;
B-108
"Petrofund Incentive Plan" means the former incentive plan established on May 3,
1996, authorizing the issuance of options to acquire Units to directors, senior
officers, employees and consultants of PC and certain related parties;
"Petrofund Unit Rights Incentive Plan" means the incentive plan established on
January 30, 2001, and approved by the Unitholder at that annual and special
meeting held on June 11, 2001, authorizing the issuance of options to acquire
Units to directors, senior officers, employees and consultants of PC and certain
related parties;
"Previous Manager" means NCE Petrofund Management Corp.;
"Royalty Agreement" means the amended and restated royalty agreement made as of
April 16, 2003 between PC and Petrofund;
"Special Resolution" means a resolution approved in writing by Unitholders
holding not less than 66-2/3% of the outstanding Units or a resolution passed
as a special resolution at a meeting of Unitholders (including an adjourned
meeting) duly convened for the purpose and passed by the affirmative votes
either in person or by proxy of the holders of not less than 66-2/3% of the
Units represented at the meeting and voted on a poll upon such resolution.
"Trust Indenture" means the amended and restated trust indenture governing
Petrofund made as of April 16, 2003 between PC and the Trustee;
"Trustee" means Computershare Trust Company of Canada, the trustee of Petrofund;
"TSX" means the Toronto Stock Exchange;
"Units" means the trust units of Petrofund, each trust unit representing an
equal undivided beneficial interest in Petrofund; and
"Unitholders" means holders of Units.
PRINCIPAL UNITHOLDERS
To the best of the knowledge of the directors and senior officers of PC,
no person beneficially owns, directly or indirectly, or exercises control or
direction over, Units carrying more than 10% of the voting rights attached to
the issued and outstanding Units.
CERTAIN MATTERS VOTED ON AT MEETING
Approval of Issuance of Units Under Restricted Unit Plan
On February 17, 2004, the Board of Directors approved the adoption of a
restricted unit plan (the "Restricted Unit Plan") which authorizes the Trust to
grant restricted units ("Restricted Units") to directors, officers, employees or
consultants of the Trust or any of its subsidiaries which will vest over time
and which, upon vesting, may be redeemed by the holder for cash or Units. The
Restricted Unit Plan is an alternative to the incentive bonus plans and unit
right incentive plans employed by many other trusts. At the Meeting, Unitholders
were asked to consider and, if thought fit, to pass a resolution authorizing the
issuance of up to a maximum of 1,200,000 Units from treasury, over the life of
the plan, pursuant to the terms of the Restricted Unit Plan. For a description
of the Restricted Unit Plan, see "- Description of the Restricted Unit Plan"
below.
B-109
The issuance of Units from treasury under the Restricted Unit Plan is
subject to the approval of the TSX, which approval has been obtained.
At the Meeting, Unitholders approved the following Ordinary Resolution
in relation to the Restricted Unit Plan:
"BE IT RESOLVED as an ordinary resolution of the unitholders of
Petrofund Energy Trust (the "Trust") that the Trust be and is
hereby authorized to issue up to a maximum of, subject to
adjustment as provided in the Restricted Unit Plan, 1,200,000
trust units of the Trust from treasury pursuant to the terms of
the Restricted Unit Plan as described in the Information
Circular of the Trust dated February 27, 2004."
Description of the Restricted Unit Plan
A considerable amount of time has been spent by management and the HR&C
Committee, in consultation with independent third party consultants, reviewing
the compensation packages of other similar trusts in both the oil and gas
industry and other industries. The goal of this effort was to design a
compensation package that will both provide an effective incentive compensation
mechanism and more closely align the interests of management of the Trust with
the interests of the Unitholders.
Generally speaking, many trusts in the oil and gas industry typically
have in place both an incentive bonus plan and a unit rights incentive plan.
Typically, the incentive bonus plan sets aside a non-discretionary bonus pool of
approximately 2.0% to 2.5% of net operating income. This bonus pool is
distributed annually, or semi-annually, to participants and payment is typically
made in cash, trust units or a combination thereof. The existing unit rights
incentive plan is very similar to a stock option plan, under which participants
are granted rights to purchase trust units at a predetermined price.
Upon completion of its review, management, the HR&C Committee and the
Board of Directors concluded that the unit rights incentive plan was not
particularly effective in achieving either of the goals outlined above. As an
alternative to this plan, on February 17, 2004, the Board of Directors approved
the Restricted Unit Plan for directors, officers, employees, or consultants of
the Trust and of its subsidiaries, including PC.
Under the terms of the Restricted Unit Plan, any director, officer,
employee or consultant of the Trust, or any of its subsidiaries who, in each
case, in the opinion of the directors of PC, holds an appropriate position with
the Trust, or any of its subsidiaries, to warrant participation in the
Restricted Unit Plan (collectively, the "Participants") may be granted
Restricted Units which vest over time and, upon vesting, can be redeemed by the
holder, at the election of PC and subject to certain restrictions, for cash or
Units. The Restricted Unit Plan is administered by the HR&C Committee.
The Restricted Unit Plan is intended to replace the existing Petrofund
Unit Rights Incentive Plan which will be terminated should the Restricted Unit
Plan receive all necessary approvals. This termination is not conditional on
approval of the LTIP. Rights that have been previously issued under the
Petrofund Unit Rights Incentive Plan which remain outstanding will not be
affected by the termination of the plan. The Restricted Unit Plan will operate
independently of the LTIP and STIP made available to the Senior Executives (see
"Approval of Issuance of Units Under the Long Term Incentive Plan" below);
however, such persons will be eligible to participate in the Restricted Unit
Plan.
The Restricted Unit Plan authorizes the issuance of 1,200,000
Restricted Units (subject to adjustments, including adjustments resulting from
cash distributions paid to holder of Units) of which no greater than 200,000
Restricted Units (subject to adjustments, including adjustments resulting from
cash
B-110
distributions paid to holders of Units) may be granted to the directors of the
Trust or its subsidiaries who are not officers or employees of the Trust or its
subsidiaries.
The purpose of the Restricted Unit Plan is to provide incentive
compensation to Participants which is calculated based on a grant of Restricted
Units and the appreciation in value of the Units (including distributions
payable in respect thereof) from the date of the grant to the date of redemption
by the Participant. In this way, Participants will be rewarded for their efforts
in the year in which the Restricted Units are granted and are also provided with
additional incentive for their continued efforts in promoting the growth and
success of the business of the Trust.
The number of Restricted Units granted to a Participant will be
increased on the second Business Day following each date on which a cash
distribution is paid to holder of Units by an amount equal to the product of the
number of Restricted Units granted to the Participant which have not been
redeemed and the fraction which has as its numerator the cash distribution paid,
expressed as an amount per Trust Unit and which has as its denominator the
weighted average of the prices at which the Units traded on the TSX for the 20
trading days immediately preceding the record date for such distribution.
Essentially, the Restricted Unit Plan provides for the granting of
Restricted Units to Participants at the discretion of the Board of Directors,
based on recommendations received from the HR&C Committee. Unless otherwise
determined by the Board of Directors at the time of a particular grant of
Restricted Units, Restricted Units will vest and become available for redemption
as to 33-1/3% on each of the first, second and third anniversaries of the grant
date. The number of Restricted Units which can be granted from time to time and
which have a vesting date which occurs earlier than the foregoing vesting
schedule is limited to 5% of the number of Restricted Units which are authorized
for issuance pursuant to the Restricted Unit Plan; provided, however, that the
proposed grant by the Board of Directors of approximately 65,000 Restricted
Units to employees and consultants of PC, which will vest as to 33-1/3% on each
of January 1, 2004, January 1, 2005, and January 1, 2006, will be considered to
have been granted in accordance with the normal vesting schedule set forth
above.
The Restricted Unit Plan provides that any grant of Restricted Units to
a Participant who is a director of the Trust or a subsidiary of the Trust will
be subject to the restrictions that: (i) the Restricted Units will not vest and,
accordingly, will not become available for redemption until the third
anniversary of the date of grant; and (ii) upon redemption of the Restricted
Units the Payout Amount (as defined below) will only be satisfied by PC
delivering Units issued from treasury. Accordingly, directors of the Trust or of
subsidiaries of the Trust could not be granted Restricted Units under the
Restricted Unit Plan unless and until approval of Unitholders of the issuance of
Units from treasury pursuant to the Restricted Unit Plan was obtained at the
Meeting.
The Restricted Unit Plan also provides that at the time of a grant of
Restricted Units to a Participant who is an officer, employee or consultant of
the Trust or a subsidiary of the Trust the Participant has the right to elect
that the grant of Restricted Units will be subject to the restrictions that:
(i) the Restricted Units will not vest and, accordingly, will not become
available for redemption until the third anniversary of the date of grant; and
(ii) upon redemption of the Restricted Units the Payout Amount will only be
satisfied by PC delivering Units issued from treasury. Accordingly, the
foregoing election could be made unless and until Unitholder approval of the
issuance of Units from treasury pursuant to the Restricted Unit Plan was
obtained at the Meeting.
Upon redemption of Restricted Units which have vested, Participants
will be required to pay $0.10 in cash for each Restricted Unit which is
redeemed. Upon redemption, the Trust is required to pay to the Participant the
fair market value of the redeemed Restricted Units based on the weighted average
of the price at which the Units traded on the TSX for the 20 trading days
immediately preceding the
B-111
redemption date (the "Payout Amount"). Subject to the restrictions noted above,
the Payout Amount shall be satisfied at the discretion of the Board of Directors
by making a cash payment, purchasing Units in the market and delivering such
Units to the Participant or, subject to the approval of the Unitholders as
contemplated herein, by issuing Units from treasury. In the event that the
approval of Unitholders of the issuance of Units from treasury pursuant to the
Restricted Unit Plan had not been obtained at the Meeting, the Restricted Unit
Plan provided that the Payout Amount may be satisfied through the payment of
cash or by way of open market purchases of Units.
The Restricted Unit Plan provides that no Units may be issued to a
Participant under the Restricted Unit Plan if such issuance could result, at any
time, in (i) the number of Units reserved for issuance pursuant to issuances
under the Restricted Unit Plan in respect of Restricted Units granted to
insiders of the Trust exceeding 3% of the aggregate issued and outstanding Units
(including Units issued on the exercise of outstanding PC Exchangeable Shares),
(ii) the issuance to insiders of the Trust, within a one-year period, of a
number of Units exceeding 3% of the aggregate issued and outstanding Units
(including Units issued on the exercise of outstanding PC Exchangeable Shares),
or (iii) the issuance to any one insider of the Trust, or such insider's
associates, within a one year period, of a number of Units exceeding 0.5% of the
aggregate issued and outstanding Units (including Units issued on the exercise
of outstanding PC Exchangeable Shares).
In the event of a change in control of the Trust, as defined in the
Restricted Unit Plan, the vesting provisions attaching to the Restricted Units
shall be accelerated and all unexercised Restricted Units shall become available
for redemption by the Participant for a period of 90 days following the
effective date of such change of control.
The Restricted Unit Plan also provides for the vesting and/or
termination of Restricted Units in the event of the cessation of employment or
death of a Participant.
Approval of Issuance of Units Under Long Term Incentive Plan
On February 17, 2004, the Board of Directors approved a long term
incentive plan (the "LTIP") for the President and Chief Executive Officer, the
Executive Vice President, the Senior Vice President, Finance and Chief Financial
Officer and the Senior Vice President, Operations of PC (collectively, the
"Senior Executives") and other employees of PC who may, in the future, be
designated as participants under the LTIP.
At the Meeting, Unitholders were asked to consider and, if thought fit,
to pass a resolution authorizing the issuance of up to 800,000 Units from
treasury, over the life of the LTIP, pursuant to the terms of the LTIP. For a
description of the LTIP, see "- Description of the Long Term Incentive Plan"
below.
The issuance of Units from treasury under the LTIP is subject to the
approval of the TSX, which approval has been obtained.
At the Meeting, Unitholders approved the following Ordinary Resolution
in relation to the LTIP:
"BE IT RESOLVED as an ordinary resolution of the unitholders of
Petrofund Energy Trust (the "Trust") that the Trust be and is
hereby authorized to issue up to a maximum of, subject to
adjustment as provided in the long term incentive plan, 800,000
Units of the Trust from treasury pursuant to the terms of the
long term incentive plan as described in the Information
Circular of the Trust dated February 27, 2004."
B-112
The Board believes that the issuance of Units from treasury under the
LTIP (as opposed to the payment of cash to the Senior Executives) better aligns
the interests of the Senior Executives with the interests of the Unitholders.
Description of the Long Term Incentive Plan
The LTIP is intended to encourage and reward outstanding performance by
participants, and if certain performance measures are met, participants may
receive a significant portion of their annual cash compensation through the
LTIP. As awards under the LTIP are paid out to the participants over time, the
LTIP is also designed to act as a participant retention tool as well as
encouraging outstanding performance.
The LTIP was approved by the Board of Directors subject to obtaining
the approval of Unitholders of the issuance of Units from treasury under the
LTIP at the Meeting. The Board believes that the issuance of Units from treasury
under the LTIP (as opposed to the payment of cash to the Senior Executives)
better aligns the interests of the Senior Executives with the interests of the
Unitholders. If the issuance of the Units to the Senior Executives under the
LTIP is not approved, the HR&C Committee will work in good faith with the Senior
Executives to implement an alternative compensation plan which, failing a
satisfactory agreement with respect to such alternative plan, may require PC to
compensate the Senior Executives with cash. Such cash payments could result in a
reduction of the aggregate sum of distributions available for Unitholders or may
result in an increase in the debt of PC and the Trust. Accordingly, the Board
recommends that Unitholders vote in favour of the proposed issuance of Units
under the LTIP.
The LTIP is administered by the HR&C Committee. From time to time the
HR&C Committee will review the objectives of the LTIP to ensure that the LTIP
continues to properly encourage outstanding participant performance and
retention, and to help achieve PC's and the Trust's strategies and value
creation. After such review, reasonable adjustments and amendments may be made
to the LTIP in the sole discretion of the HR&C Committee, provided that the HR&C
Committee acts in a reasonable manner.
Subject to the discretion of the HR&C Committee and future changes to
the roles of the participants, the LTIP establishes threshold, target, and
maximum opportunities for each of the participants. The amount of the award for
any given year which is given to a participant under the LTIP depends upon the
degree to which performance levels, as described below, and individual
performance, where applicable, have been met in that year. The size of the LTIP
award for any given year is expressed as a percentage of the participant's base
salary (not including any bonus, incentive or LTIP compensation, or the value of
benefits or perquisites).
The LTIP presently has two financial and operational performance
measures: (i) total unitholder return ("TUR"); and (ii) reserve life index
("RLI"). TUR is measured relative to the total unitholder return of relevant
peer oil and gas trusts. RLI is measured relative to the prior year's RLI of the
Trust. It is considered at the present time by the Committee that it is
important for the fund to maintain an RLI of 10.0 years or greater. An RLI of
10.0 years is presently considered the "Optimum RLI" under the LTIP. The HR&C
Committee may, in its discretion, but only after consultation with the Senior
Executives, review from time to time what the Optimum RLI should be and may
change the performance milestones for the RLI based on such review and
consultation.
Subject to the discretion and judgement of the HR&C Committee, the two
performance measures are weighted equally. The HR&C Committee may, however,
change the weighting of such measures from time to time in order to achieve the
objectives of the LTIP. In addition to the above two
B-113
performance measures, the HR&C Committee will take into account in certain
circumstances the individual performance of the LTIP participants in determining
the LTIP award.
As at the date hereof, and subject to individual performance
considerations, the two performance measures at the following percentiles would
result in the following awards under the LTIP.
TUR Component:
o a TUR that equals or exceeds the 25th percentile, but is less
than the 50th percentile, of the peer group for total unitholder
return would result in a threshold LTIP calculation equal to 50%
of the target incentive for this component;
o a TUR that equals or exceeds the 50th percentile (median), but is
less than the 75th percentile, of the peer group for total
unitholder return would result in a LTIP calculation equal to the
target incentive for this component; and
o a TUR that is at or above the 75th percentile of the peer group
for total unitholder return would result in a maximum LTIP
calculation equal to 200% of the target incentive for this
component.
RLI Component:
Should the RLI equal or exceed the Optimum RLI, the calculation will be
200% of the target incentive.
Where the RLI falls below the Optimum RLI:
o a change in the RLI at or above the 25th percentile, but less
than the 50th percentile, would result in a threshold LTIP
calculation equal to 50% of the target incentive for this
component;
o a change in the RLI at or above the 50th percentile, but less
than the 75th percentile, would result in a LTIP calculation
equal to the target incentive for this component; and
o a change in the RLI at or above the 75th percentile would result
in a maximum LTIP calculation equal to 200% of the target
incentive for this component.
Subject to the discretion of the HR&C Committee and future changes to
the roles of the participants, the following are the present threshold, target
and maximum opportunities for each of the Senior Executive participants in the
following positions:
Level 1 - President and Chief Executive Officer
Level 2 - Executive Vice President
Level 3 - Senior Vice Presidents
Annual Long Term Incentive (as a % of base salary)
-----------------------------------------------------
Threshold Maximum
Participation Level (50% of Target) Target (200% of Target)
------------------- ----------------- ---------- ----------------
1 50% 100% 200%
2 37.5% 75% 150%
3 32.5% 65% 130%
B-114
As an example, for a participant at participation level 1 whose base
salary is equal to $100,000, where the target incentive of the participant is
100% of the participant's base salary (which amount is equal to $100,000) then,
subject to individual performance considerations, the payment under the LTIP to
the participant would be: nil if the Trust did not meet the threshold
performance measures; $50,000 (50% of $100,000) if the Trust met but did not
exceed the threshold performance measures; $100,000 (100% of $100,000) if the
Trust met but did not exceed the target performance measures; and $200,000 (200%
of $100,000) if the Trust met or exceeded the maximum performance measures.
The awards under the LTIP will be based on the participant's base
salary earned during the LTIP year with respect to which the award was made.
LTIP awards will be made in the form of a grant of restricted Units. The number
of restricted Units awarded under the LTIP will be calculated as follows:
o as determined by the HR&C Committee, the percentage of base
salary to be awarded to the specific participant will be applied
to the base salary for the LTIP year to arrive at a dollar value
for the LTIP award;
o the dollar value for the LTIP award will be divided by the
average of the closing price of Units on the TSX during the 20
days immediately preceding the award date to arrive at the number
of restricted Units to be awarded to the participant;
o the restricted Units will vest one-third on January 1 of the year
following the LTIP year with respect to which the award was made
and one-third on January 1 of each of the two subsequent years
(notwithstanding the foregoing, however, in the existing
employment agreements for each of the Senior Executives, it has
been agreed that the vesting schedule for the distribution of
awards to such persons under the LTIP shall be: (i) for any LTIP
award for 2003 performance, two-thirds of the LTIP award shall be
vested on the grant date and the remaining one-third of the LTIP
award will be vested on the first anniversary of the grant date;
and (ii) for any LTIP award for 2004 or 2005 performance,
one-third of the LTIP award would be vested on the grant date,
one-third of the LTIP award shall be vested on the first
anniversary of the grant date and the remaining one-third of the
LTIP award shall be vested on the second anniversary of the grant
date;
o prior to vesting, distributions on the account balance will be
credited and notionally reinvested; and
o on vesting, the balance of the account representing the vested
portion of the LTIP award will be issued in Units from treasury
to the credit of the participant.
Provided the LTIP receives the necessary Unitholder and regulatory
approval, the dollar value of the Units which will be issued from treasury
pursuant to the LTIP to each of the Senior Executives will depend on each
executive meeting certain individual and corporate performance targets, and is
expected to be at the maximum for 2003 of: $610,000 for the President and Chief
Executive Officer; $337,500 for the Executive Vice President; $266,500 for the
Senior Vice President, Finance and Chief Financial Officer; and $240,000 for the
Senior Vice President, Operations. The actual number of Units which will be
issued is determined by dividing each dollar amount by an amount equal to the
average closing market price of the Units over the 20 trading days preceding the
date of the award. The initial grant of Units under the LTIP, based on the
foregoing, was approved by the Board of Directors on February 17, 2004, subject
to the receipt of all necessary regulatory and Unitholders approvals. Vesting of
these Units is two-thirds of the LTIP award on December 31, 2003, and the
remaining one-third of the LTIP award on December 31, 2004. If necessary
regulatory and Unitholder approval is not obtained it is intended that
alternative compensation will be awarded which is equivalent to the award under
the LTIP.
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Subject to any employment agreement that is in place with the Senior
Executives, PC and the HR&C Committee have the right and discretion, provided
they act reasonably, to amend the LTIP, in whole or in part, or to terminate the
LTIP at any time. Upon termination of the LTIP, all rights to the participants
under the LTIP shall cease as of the date of termination, except with respect to
LTIP awards that have been declared by the HR&C Committee but not yet paid to
the participants.
Amendments to Trust Indenture and Royalty Agreement
Management presented to the Board of Directors a number of proposed
amendments to the Trust Indenture and the Royalty Agreement and, after
considering such amendments, the Board of Directors placed before Unitholders at
the Meeting a Special Resolution approving amendments to the Trust Indenture and
the Royalty Agreement as follows.
Additional Resource Assets
As at the date of the Information Circular, the Trust Indenture
provided that any funds within the Trust Fund (as defined in the Trust
Indenture) are to be used for certain purposes, which purposes include, among
others, acquiring, holding and investing, directly or indirectly, in "Additional
Resource Assets".
As at the date of the Information Circular, the Trust Indenture and the
Royalty Agreement defined "Additional Resource Assets" as "securities of
Resource Issuers, royalties or other interests of Resource Issuers and
properties and related assets of Resource Issuers" and also define a "Resource
Issuer" as "any company, partnership, limited partnership, trust or other entity
whose principal business activity is or relates to the exploration, production,
drilling, recovery, removal, disposal, production, processing or transportation
of Petroleum Substances (as defined in the Trust Indenture and the Royalty
Agreement) or related activities".
The business environment is continually changing in the energy sector
and, as such, the Board of Directors believed it would be prudent to expand the
scope of the Trust's business to include all business related to the energy
business rather than only business related to oil and gas assets. While the
primary focus of the Trust shall continue to be oil and gas assets, the Board of
Directors feels it is prudent to permit investments in the future by the Trust
in other energy related investments such as electricity or power generating
assets.
Accordingly, at the Meeting it was proposed to amend the definition of
"Resource Issuer" in each of the Trust Indenture and the Royalty Agreement to
read as follows:
"Resource Issuer" means any company, partnership, limited partnership,
trust or other entity whose principal business activity is or relates to
petroleum and natural gas or other energy related assets including,
without limitation, Petroleum Substances, facilities of any kind, oil
sands interests, electricity or power generating assets and pipeline,
gathering, processing and transportation assets;
Acquisition Criteria of Properties
As at the date of the Information Circular, the Trust Indenture
provided that acquisitions of Additional Resources Assets which are "Properties"
(and which are defined as petroleum and natural gas rights and related tangibles
and miscellaneous interests) were to comply with the acquisition criteria set
forth in section 3.2 of the Royalty Agreement. One of the acquisition criteria
contained in Section 3.01(b) of the Royalty Agreement was that Properties shall
be located in Western Canada, namely, Alberta, Saskatchewan, British Columbia
and Manitoba and, at the time of purchase, not more than 10% of the Asset Value
(as defined in the Royalty Agreement), after giving effect to the proposed
acquisition may be
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represented by Properties located outside of Western Canada. It was an
additional criterion contained within Section 3.01(b) of the Royalty Agreement
that all of the Properties must be located in Canada.
The Board of Directors felt that it would be prudent to increase the
maximum percentage of Properties which can be located outside of Western Canada
from 10% to 20% in order that the Trust is not limited in its ability to acquire
a greater interest in attractive oil and gas assets which are located outside of
Western Canada, and also remove the restriction that all of the properties must
be located in Canada.
Accordingly, at the Meeting it was proposed to amend the acquisition
criteria set forth in Section 3.01(b) of the Royalty Agreement to read as
follows:
"The Properties shall be located primarily in Western Canada, namely,
Alberta, Saskatchewan, British Columbia and Manitoba and, at the time of
purchase, not more than 20% of the Asset Value, after giving effect to
the proposed acquisition, may be represented by Properties located
outside of Western Canada."
Option to Designate Principal Office of Trustee
As at the date of the Information Circular, the Trust Indenture
provided that the register of Unitholders, and all books and records of the
Trust, be kept at the principal corporate trust office of the Trustee in the
City of Toronto. The Board of Directors felt that it would be prudent and
expeditious to have the option to designate the principal corporate trust office
of the Trustee in the City of Calgary as the custodian of the register of
Unitholders and the books and records of the Trust.
Accordingly, at the Meeting it was proposed to amend the provisions of
the Trust Indenture to give the Board of Directors the option to designate the
principal corporate trust office of the Trustee in either the City of Toronto or
the City of Calgary as the custodian of the register of Unitholders and the
books and records of the Trust.
Definition of Asset Value
As at the date of the Information Circular, the Trust Indenture defined
"Asset Value" as the present worth of the total estimated pre-tax cash flow from
the proved reserves and 50% of the probable reserves, as shown in the most
recent engineering report relating thereto. However, the introduction of the new
National Instrument 51-101 has imposed a new definition of probable reserves on
the industry as a whole. The Board of Directors felt that it would be prudent
and expeditious to amend the definition of Asset Value in the Trust Indenture to
reflect the new definition contained in NI 51-101.
Accordingly, at the Meeting it was proposed to amend the definition of
"Asset Value" in the Trust Indenture to read as follows:
"Asset Value" means the present worth of all of the estimated pre-tax
net cash flow from the proved reserves plus probable reserves, as such
terms are defined for the purposes of National Instrument 51- 101 (or
any replacement thereof), shown in the most recent engineering report
relating thereto, discounted at an annual rate equal to the then current
annual yield of long-term (10 year) Government of Canada bonds plus 400
basis points, subject to a maximum rate of 10% and using forecast price
and cost assumptions;".
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Unitholder Approval
At the Meeting, Unitholders approved the following Special Resolution
in relation to the amendments to the Trust Indenture and the Royalty Agreement
which are described above:
"BE IT RESOLVED as a special resolution of the Unitholders of Petrofund
Energy Trust that:
1. the definition of "Resource Issuer" contained in each of the
Trust Indenture and the Royalty Agreement be amended to read as
follows:
"Resource Issuer" means any company, partnership, limited
partnership, trust or other entity whose principal business
activity is or relates to petroleum and natural gas or other
energy related assets including, without limitation, Petroleum
Substances, facilities of any kind, oil sands interests,
electricity or power generating assets and pipeline, gathering,
processing and transportation assets;";
2. the acquisition criteria contained in Section 3.01(b) of the
Royalty Agreement be amended to read as follows:
"The Properties shall be located primarily in Western Canada,
namely, Alberta, Saskatchewan, British Columbia and Manitoba
and, at the time of purchase, not more than 20% of the Asset
Value, after giving effect to the proposed acquisition, may be
represented by Properties located outside of Western Canada.";
3. the designation of the principal corporate trust office of the
Trustee contained in the first paragraph of Section 13.2 of the
Trust Indenture be amended to read as follows:
"A register shall be kept, at the discretion and option of the
Board of Directors of the Corporation, at the principal
corporate trust office of the Trustee in either the City of
Toronto or the City of Calgary by the Trustee or by a Transfer
Agent designated to act on behalf and under the direction of the
Trustee, which register shall contain the names and addresses of
the Unitholders, the respective number of Units held by them,
the certificate number of the Certificates representing such
Units and a record of all transfers thereof. In addition, the
Trustee shall maintain a branch register at its principal
offices in Halifax, Montreal, Vancouver, and either Calgary or
Toronto and in such other locations as the Trustee may designate
from time to time."; and
4. the designation of the principal office of the Trustee contained
in Section 18.2 of the Trust Indenture be amended to read as
follows:
"The Trustee shall keep such books, records and accounts as are
necessary and appropriate to document the Trust Fund and each
transaction of the Trust. Without limiting the foregoing, the
Trustee will, at its principal office, as designated by the
Board of Directors of the Corporation, in either Toronto,
Ontario, or Calgary, Alberta, keep records of all transactions
of the trust, a list of the assets of the Trust Fund from time
to time and a copy of this Trust Indenture and the Royalty
Agreement with any amendments thereto.".
5. the definition of "Asset Value" contained in Section 1.1 of the
Trust Indenture be amended to read as follows:
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"Asset Value" means the present worth of all of the estimated
pre-tax net cash flow from the proved reserves plus probable
reserves, as such terms are defined for the purposes of National
Instrument 51-101 (or any replacement thereof), shown in the
most recent engineering report relating thereto, discounted at
an annual rate equal to the then current annual yield of
long-term (10 year) Government of Canada bonds plus 400 basis
points, subject to a maximum rate of 10% and using forecast
price and cost assumptions;".
In accordance with the terms of the Trust Indenture the proposed
amendments to the Trust Indenture and the Royalty Agreement required the
approval of not less than 66-2/3% of the Units represented at the Meeting and
voted on such resolution.
EXECUTIVE COMPENSATION PRIOR TO THE INTERNALIZATION
Management Agreement
The Unitholders approved the Internalization Transaction at the annual
and special meeting held on April 16, 2003, and in connection with the
Internalization Transaction, PC acquired the Manager and the external management
contract of Petrofund as described below and all related fees were eliminated.
Pursuant to the Management Agreement, the Manager was compensated for
providing services to PC and Petrofund. As a result of the completion of the
Internalization, no fees were payable to the Manager under the Management
Agreement in respect of the period commencing on January 1, 2003 to the closing
date, April 29, 2003. Previously the Manager received a quarterly fee paid on
the last Business Day of each quarter of each year equal to 3.25% (reduced from
3.75%, effective January 1, 2002) of the sum of net production revenue less
Crown royalties and other Crown charges attributable to PC's properties for the
applicable quarterly period.
In addition the Manager received acquisition fees equal to 1.5%
(reduced from 1.75%, effective January 1, 2002) of the purchase costs of all oil
and gas properties, oil and gas companies and other related assets acquired by
PC, other than replacement properties. In the event that PC properties were
sold, the Manager also received disposition fees of 1.25% (reduced from 1.5%,
effective January 1, 2002) of the sale price of the properties sold.
PC is entitled to a residual 1% interest in the properties. The
management fee and investment fee were paid in part, firstly, by applying any
income received by PC in respect of its residual interest in the properties and,
secondly, by applying any interest income of PC relating to the proceeds or
revenue from the properties.
The Manager was also entitled to be reimbursed by PC for general and
administrative costs and by Petrofund for trust expenses. PC was not responsible
for the payment in any fiscal year of Petrofund of general and administrative
costs in excess of the greater of (a) 5% of the gross production revenue for
such fiscal year and (b) $240,000. To the extent that general and administrative
costs paid by PC for any fiscal year of Petrofund exceed such maximum amount, PC
was entitled to set off and deduct such excess amount from its liability to pay
management fees to the Manager.
Compensation of Directors
Prior to the Internalization Transaction each director of PC was
entitled to receive a quarterly retainer of $5,000, in addition each director
received a fee of $1,000 for each meeting of the board of directors attended and
$1,500 for each meeting of Unitholders attended. Subsequent to the
Internalization Transaction each director of PC is entitled to receive a
quarterly retainer of $7,500, and the committee
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chairs also receive an annual retainer of $10,000, except for the chair of the
audit committee who receives an annual retainer of $15,000. Each director of PC
also receives a fee of $1,750 for each board of directors, unitholders, or
committee meeting attended. All amounts paid to the directors of PC are paid by
Petrofund.
For Petrofund's fiscal year ended December 31, 2003, the directors were
paid an aggregate of $360,500 for retainer fees and attending regular meetings
of the Board of Directors, $20,750 for attending audit committee meetings, and
$43,250 for participation on two special committees, pertaining to the
Internalization Transaction. John F. Driscoll, the Chairman of the Board of
Directors, receives a fixed amount of $125,000 a year in lieu of retainer and
meeting fees.
Executive Compensation
Summary Compensation Table
The following table provides a summary of compensation information for
the chief executive officer plus the four other most highly compensated policy
making executive officers of PC (collectively, the "Named Executive Officers")
for the period January 1, 2003 to December 31, 2003.
-----------------------------------------------------------------------------------------------------------
Long-Term Comp
-----------------------------------
Annual Compensation ("Comp") Awards Payout
---------------------------------------------------------------------
Securities Restricted
Under Shares or
Other(2) Options / Restricted
Name and Principal Salary Annual SARs Share LTIP All Other
Position (1) ($) Bonus ($) Comp ($) Granted Units Pay-outs Comp
-----------------------------------------------------------------------------------------------------------
Jeffery E Errico, $305,000 $195,000 (2) - (3) - -
President & CEO
-----------------------------------------------------------------------------------------------------------
Jeffrey D. Newcommon, $218,333 $156,000 (2) - (3) - -
Executive Vice President
-----------------------------------------------------------------------------------------------------------
Vince P. Moyer, CA $205,000 $149,500 (2) - (3) - -
Senior Vice President,
Finance & CFO
-----------------------------------------------------------------------------------------------------------
Glen C. Fischer, $185,000 $149,500 (2) - (3) - -
Senior Vice President,
Operations
-----------------------------------------------------------------------------------------------------------
Noel F. Cronin $158,000 $40,000 (2) - (3) - -
Vice President,
Production
-----------------------------------------------------------------------------------------------------------
Notes:
(1) For the period January 1, 2003 to December 31, 2003. Note also that
amounts prior to April 29, 2003 were paid by the Manager and reimbursed by
PC.
(2) The value of perquisites and other personal benefits received by the Named
Executive Officers was not greater than 10% of the total salary and bonus
for the period.
(3) See "Certain Matters Voted on at Meeting - Approval of Issuance of Units
Under Long Term Incentive Plan for restricted Units which were granted
under the LTIP, subject to regulatory and Unitholder approval.
Aggregate Unit Incentive Rights Exercised and Year End Values
The following table sets forth, with respect to the Named Executive
Officers, the number of Trust Unit Incentive Rights exercised during the year
ended December 31, 2003, and the value of the "in-the-money" unexercised Trust
Unit Incentive Rights at December 31, 2003.
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Aggregate Unit Incentive Rights Exercised During the Most Recently Completed
Financial Year and Financial Year End Unit Incentive Rights Values
-----------------------------------------------------------------------------------------------------------
Value of Unexercised
Aggregate Unexercised Unit In-the-Money Unit
Securities Value Incentive Rights at Incentive Rights at
Acquired on Realized FY-End (#) FY-End ($)
Name Exercise (#) ($) Exercisable/Unexercisable Exercisable/Unexercisable
-----------------------------------------------------------------------------------------------------------
J. E. Errico 141,133 554,303 41,667/ 50,000 106,668 / 443,000
-----------------------------------------------------------------------------------------------------------
J. D. Newcommon 101,667 406,900 33,333 / 35,000 85,332 / 310,100
-----------------------------------------------------------------------------------------------------------
V. P. Moyer 134,999 264,740 - / 35,000 - / 310,100
-----------------------------------------------------------------------------------------------------------
G. C. Fischer 138,333 314,247 - / 35,000 - / 310,100
-----------------------------------------------------------------------------------------------------------
N. F. Cronin 51,667 140,374 - / 9,000 - / 79,740
-----------------------------------------------------------------------------------------------------------
The value of the exercisable Unit Incentive Rights (market value of
Units less exercise price) at December 31, 2003, was based upon the closing
price of $18.79 for the Units on December 31, 2003, being the last day of
trading of the Units in 2003, as quoted by the Toronto Stock Exchange.
Unit Incentive Plans
The Petrofund Incentive Plan authorized the issuance of options to
acquire Units to directors, senior officers, employees and consultants of PC and
certain related parties. As of December 31, 2003, 4,689 options were outstanding
pursuant to the Petrofund Incentive Plan. The Petrofund Incentive Plan will be
terminated once all options outstanding thereunder are exercised or expire
unexercised.
All option rights to purchase Units are now granted under the Petrofund
Unit Rights Incentive Plan. The purpose of the Petrofund Unit Rights Incentive
Plan is to encourage ownership of Units by directors, senior officers, employees
and consultants of PC, as designated from time to time by the Board of
Directors, and personal holding corporations controlled by or registered
retirement savings plans of any such persons.
The aggregate number of Units which may be reserved for issuance under
the Petrofund Unit Rights Incentive Plan is 5,200,000 Units, of which 2,945,900
have been issued. As of February 27, 2004, 751,789 options were outstanding
pursuant to the Petrofund Unit Rights Incentive Plan. The Petrofund Unit Rights
Incentive Plan permits Petrofund to increase such maximum number from time to
time, subject to the approval of the Unitholders. If the Restricted Unit Plan,
outlined in this Information Circular, is approved no further options will be
issued under the Petrofund Unit Rights Incentive Plan.
The exercise price of rights granted under the Petrofund Unit Rights
Incentive Plan is based upon the market price of the Units at the date of grant
or, at the election of the grantee, based upon such market price and the unit
distribution levels subsequently achieved by Petrofund. In particular, the
Petrofund Unit Rights Incentive Plan provides that the rights exercise price
will be equal to either (a) the market price of the Units on the date of the
grant of the right or, (b) if so elected by the holder no later than the
exercise of the applicable right, the market price of the Units on the date of
grant of the right reduced from time to time for each calendar quarter ending
after the date of grant by the positive amount, if any, equal to:
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(i) the amount by which the aggregate unit distributions
made to Unitholders in any calendar quarter ending after
the date of the grant exceed 2.5% of Petrofund's Oil and
Gas Interests (as defined below) on its balance sheet at
the beginning of the applicable calendar quarter,
divided by
(ii) the number of issued and outstanding Units as at
the beginning of the applicable calendar quarter.
These provisions of the Petrofund Unit Rights Incentive Plan reflects
Petrofund's primary objective of maximizing distributions in order to allow it
to compete in the oil and gas business for the employment of qualified
professionals. The exercise price of rights will effectively allow the holders
of rights granted under the Petrofund Unit Rights Incentive Plan, at their
election, to indirectly participate in Unit distributions in excess of 2.5% of
the net book value per unit of Petrofund's consolidated oil and gas royalty and
property interests (the "Oil and Gas Interests") on a quarterly basis.
Rights granted under the Petrofund Unit Rights Incentive Plan may be
exercised during a period not exceeding five years, subject to earlier
termination in the event of termination, retirement, disability or death. The
rights are non-transferable. PC may from time to time amend or revise the terms
of the Petrofund Unit Rights Incentive Plan or may terminate the Petrofund Unit
Rights Incentive Plan at any time; provided, however, that the Petrofund Unit
Rights Incentive Plan will be terminated should the Restricted Unit Plan receive
all necessary approvals. Rights that have been previously issued under the
Petrofund Unit Rights Incentive Plan which remain outstanding will not be
affected by the termination of the plan.
Restricted Unit Plan
On February 17, 2004, the Board of Directors approved the adoption of
the Restricted Unit Plan which authorizes the Trust to grant Restricted Units to
directors, officers, employees or consultants of the Trust or any of its
subsidiaries which will vest over time and which, upon vesting, may be redeemed
by the holder for cash or Units.
At the Meeting, Unitholders approved a resolution authorizing the
issuance of up to 1,200,000 Units from Treasury pursuant to the terms of the
Restricted Unit Plan. For a description of the Restricted Unit Plan, see
"Certain Matters Voted on at Meeting - Approval of Issuance of Units under
Restricted Unit Plan - Description of Restricted Unit Plan".
Long Term Incentive Plan
On February 17, 2004, the Board of Directors approved the LTIP for the
President and Chief Executive Officer, the Executive Vice President, the Senior
Vice President, Finance and Chief Financial Officer and the Senior Vice
President, Operations of PC (collectively, the "Senior Executives") and other
employees of PC who may, in the future, be designated as participants under the
LTIP.
At the Meeting, Unitholders approved a resolution authorizing the
issuance of up to 800,000 Units from treasury, over the life of the LTIP,
pursuant to the terms of the LTIP. For a description of the LTIP and the grant
of Units thereunder that has been made, subject to regulatory and Unitholder
approval, see "Certain Matters Voted on at Meeting -- Approval of Issuance of
Units Under Long Term Incentive Plan" above.
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The issuance of Units from treasury under the LTIP is subject to the
approval of the TSX, which approval has been obtained.
Short Term Incentive Plan
On February 17, 2004, the Board of Directors approved a short term
incentive plan (the "STIP") for the Senior Executives and other employees of PC
who may, in the future, be designated as participants under the STIP.
The STIP is intended to encourage and reward outstanding performance by
participants, and if certain financial, operational and individual performance
measures are met, participants may receive a significant portion of their annual
cash compensation through the STIP. While the STIP is intended to reward
outstanding performance, it is also intended to insulate the participants from
the fluctuation of commodity prices as the participants should neither be
rewarded nor penalized solely due to increases or decreases in commodity prices
for reasons completely beyond their control. Rather, it is the intention of PC
that participants be rewarded based on their ability to manage the Trust's
business better than other similar businesses which are subject to the same
market and economic forces. The STIP will not be allowed to promote
decision-making by the participants that is contrary to the best interests of
the Trust and PC. As such, those administrating the STIP shall retain the
discretion, acting reasonably, to adjust awards, performance measures, and to
look at individual performance, to ensure that the decision-making of the
participants continues to be in the best interests of PC, the Trust, and its
Unitholders.
The STIP was approved by the Board of Directors of STIP effective
January 1, 2004, and the first year for consideration of compensation under the
STIP is the fiscal year 2004. Should certain measures be achieved, the first
awards under the STIP for the fiscal year 2004 would be made in the first
quarter of 2005.
The STIP is administered by the HR&C Committee. From time to time the
HR&C Committee will review the objectives of the STIP and the STIP to ensure
that the STIP continues to properly encourage outstanding participant
performance, and to help achieve PC's and the Trust's strategies and value
creation. After such review, reasonable adjustments and amendments may be made
to the STIP in the reasonable discretion of the HR&C Committee.
Subject to the discretion of the HR&C Committee and future changes to
the roles of the participants, the STIP establishes threshold, target and
maximum opportunities for each of the participants. The amount of the award for
any given year which is given to a participant under the STIP depends upon the
degree to which performance levels as described below (and individual
performance, where applicable) have been met in that year. The size of the STIP
award for any given year is expressed on a percentage of the participant's base
salary (not including any bonus, incentive or STIP compensation, or the value of
benefit or perquisites).
The STIP presently has five financial and operational performance
measures: (i) total unitholder return; (ii) production per Trust Unit; (iii)
operating and general and administrative costs; (iv) established reserves per
Trust Unit; and (v) acquisition and development costs.
Subject to the discretion and judgement of the HR&C Committee, the five
performance measures are weighted equally. The HR&C Committee may, however,
change the weighting of such measures from time to time in order to achieve the
objectives of the STIP. In addition to the above five performance measures, the
HR&C Committee will take into account in certain circumstances the individual
performance of the STIP participants in determining the STIP award.
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As at the date hereof and subject to individual performance considerations, the
five performance measures at the following percentiles would result in the
following awards under the STIP:
o the 25th percentile of the peer group for absolute and relative
performance, as applicable, would result in a threshold STIP
payment equal to 50% of the target incentive for each component;
o the 50th percentile (median) of the peer group for absolute and
relative performance, as applicable, would result in a STIP
payment equal to the target incentive for each component; and
o at or above the 75th percentile of the peer group for absolute
and relative performance, as applicable, would result in a
maximum STIP payment equal to 200% of the target incentive for
each component.
Subject to the discretion of the HR&C Committee and future changes to
the roles of the participants, the following are the present threshold, target,
and maximum opportunities for each of the Senior Executive participants in the
following positions:
Level 1 - President and Chief Executive Officer
Level 2 - Executive Vice President
Level 3 - Senior Vice Presidents
Annual Short Term Incentive (as a % of base salary)
------------------------------------------------------
Threshold Maximum
Participation Level (50% of Target) Target (200% of Target)
------------------- --------------- ------ ----------------
1 25% 50% 100%
2 22.5% 45% 90%
3 20% 40% 80%
The awards under the STIP will be determined at the conclusion of the
STIP year and will be based on performance of the participants and the Trust
during the STIP year. The amount of any STIP award will be based on the
participant's base salary earned during the fiscal year under which the STIP
award was granted. Awards under the STIP will be in cash and subject to
appropriate withholding taxes.
Subject to any employment agreement that is in place with the Senior
Executives, PC, and the HR&C Committee have the right and discretion, provided
they act reasonably, to amend the STIP, in whole or in part, or to terminate the
STIP at any time. Upon termination of the STIP, all rights to the participants
under the STIP shall cease as of the date of termination, except with respect to
STIP awards that have been declared by the HR&C Committee but not yet paid to
the participants.
As the STIP is intended to encourage and reward outstanding performance
by certain key PC employees rights under the STIP, subject to any employment
agreement that is in place with the Senior Executives, generally cease upon the
cessation of such employment.
Employment Contracts
The President and Chief Executive Officer and the other Named Executive
Officers of PC are each a party to an employment agreement with PC, which
continues indefinitely until terminated in accordance with its terms, and
provides for payment of the executive's annual base salary and participation in
benefits provided by PC as provided in the agreement. Each agreement further
provides
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for a bonus for the year 2003 and the payment of such bonus and the
participation by the executive in the LTIP commencing January 1, 2003, and
participating in the STIP commencing January 1, 2004, such participation in the
LTIP (subject to unitholder approval) and STIP being as provided in the
agreement. The agreements may be terminated by PC without cause upon payment of
the following amounts: (i) a lump sum payment equal to the annual base salary
multiplied by a range of 2.5 times to 1.75 times (the "Multiplier") depending on
the executive's position; (ii) 20% of the amount calculated pursuant to (i)
above as compensation for loss of benefits; (iii) depending on the termination
date, a distribution under the LTIP consisting of a distribution of Units equal
to the executive's target LTIP bonus for the year in which the termination
occurs times the Multiplier if the termination occurs before January 2004 to 0.5
for the President and Chief Executive Officer and zero for the other executives
in the event the termination occurs after January 1, 2009; and (iv) a lump sum
payment equal to the Multiplier times the average of the STIP bonus awarded to
the executive over the preceding three years. In addition, in the event of
termination, any unvested but previously awarded LTIP grants shall be
distributed to the executive and, subject to regulatory approval; any unvested
rights to purchase Units of the Trust pursuant to the Unit Rights Incentive Plan
of the Trust that would have vested over a specified period from the termination
date shall vest. Furthermore, in the event that the agreements are terminated by
PC without cause, PC shall pay to the executive a payment in lieu of continued
participation in the 2003 bonus plan or in the STIP equal to the proportionate
share of the amount that the executive would have received pursuant to the 2003
bonus plan or STIP had the agreement not been terminated. In addition, in the
event of a change of control (as defined in the agreements), the executive has
the right, for a period of six months following the event causing the change of
control, to terminate the agreement and be entitled to the foregoing payments.
INDEBTEDNESS OF DIRECTORS AND OFFICERS
None of the directors or senior officers of Petrofund or PC and no
affiliate or associate of any of the foregoing, has been indebted to Petrofund
or PC at any time since January 1, 2003.
INTERESTS OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS
To the knowledge of the Board, except for the internalization of
management described below, none of the directors or senior officers of PC, or
any associate or affiliate of the foregoing, has had any material interest,
direct or indirect, in any transaction since January 1, 2003 that has materially
affected Petrofund, or in any proposed transaction that would materially affect
Petrofund.
Internalization of Management
On March 10, 2003, the Trust entered into an agreement to internalize
its management structure such that Previous Manager became a wholly owned
subsidiary of PC. Unitholder and regulatory approval of the Internalization was
received at the annual and special meeting of Unitholders held on April 16,
2003. As a result of the Internalization all management, acquisition and
disposition fees payable to the Previous Manager were eliminated effective
January 1, 2003. The cost of the Internalization was $30.9 million including
$2.5 million of transaction costs, all of which was expensed to the income
statement. The transaction was effected in the following manner:
o Prior to the closing, the Previous Manager acquired NCE Services
(which employed all of the Calgary-based personnel who provided
services to the Trust and PC on behalf of the Previous Manager).
o At the closing, PC purchased all of the issued shares of the
Previous Manager from Petro Assets Inc. for $21.7 million. Petro
Assets Inc. is owned by the Driscoll Family Trust (a
B-125
trust established for the family of John F. Driscoll). John F.
Driscoll was Chairman and Chief Executive Officer of PC at
closing.
o The purchase price for the shares of the Previous Manager was
satisfied by the issuance of 1,939,147 PC Exchangeable Shares,
plus a cash amount per PC Exchangeable Share equal to the
distributions paid or payable per Unit by the Trust to
Unitholders of record from and after January 1, 2003 up to and
including the closing date. Initially each PC Exchangeable Share
was exchangeable into one Unit. The exchange rate is adjusted
from time to time to reflect distributions paid on each Unit
after the closing date. Each PC Exchangeable Share was initially
ascribed a value of $12.1703, representing the weighted average
trading price of the Units over the 10 trading days, ending on
March 4, 2003 on the TSX. For accounting purposes the PC
Exchangeable Shares were deemed to be issued at a value of $11.20
per share being the average trading value of the Units for the
last ten days prior to the closing date.
o At closing, PC paid $3.4 million in cash to fund the repayment of
indebtedness owing by the Previous Manager. In addition, as part
of the Internalization NCE Services paid certain senior
executives of the Previous Manager $780,000 in cash and issued
100,244 Units plus an amount per Unit equal to the distributions
per Unit paid to holders of record of Units during the period
commencing on January 1, 2003 and ending on the closing date.
Subsequent to the closing of the Internalization, the Trust proceeded
to consolidate all activities in PC's offices in Calgary, Alberta. To ensure an
orderly transition of the services then provided by the Previous Manager through
its office in Toronto, Ontario, Sentry Select Capital Corp. ("Sentry") entered
into an agreement on closing, which was effective January 1, 2003, with the
Trust, PC and the Previous Manager to provide certain of these services to the
Trust and PC at Sentry's cost until December 31, 2003, subject to a maximum cost
of $2 million. After December 31, 2003, Sentry no longer provides any services.
At closing Sentry was an affiliate of the Previous Manager and is a company in
which John F. Driscoll owns a controlling interest.
As part of the agreement, all management fees, acquisition and
disposition fees were eliminated retroactive to January 1, 2003.
B-126
APPENDIX "C"
INFORMATION RELATING TO ULTIMA ENERGY TRUST
TABLE OF CONTENTS
Page
----
1. Renewal Annual Information Form dated April 30, 2004 for the
year ended December 31, 2003............................................ C-o
2. Management's Discussion and Analysis for the year ended
December 31, 2003 compared to the year ended December 31, 2002.......... C-o
3. Comparative Audited Consolidated Financial Statements as at
and for the years ended December 31, 2003 and 2002, together
with the auditors' report thereon....................................... C-o
[OBJECT OMITTED]
ULTIMA
ENERGY TRUST
RENEWAL ANNUAL INFORMATION FORM
April 30, 2004
TABLE OF CONTENTS
DEFINITIONS........................................C-3 Termination of the Trust.......................C-37
CONVERSION.........................................C-8 COMPETITIVE CONDITIONS AND RISK FACTORS...........C-37
ORGANIZATION AND STRUCTURE OF ULTIMA ENERGY TRUST..C-9 Nature of Trust Units..........................C-37
Ultima Energy Trust.............................C-9 Operational Matters............................C-38
Ultima Ventures Trust..........................C-10 Regulation and Competition.....................C-38
Ultima Ventures Corp...........................C-11 Reserves.......................................C-38
Ultima Energy Inc..............................C-11 Volatility of Oil and Natural Gas Prices.......C-39
Ultima Acquisitions Corp.......................C-12 Currency Exchange Rates........................C-40
Ultima Management Inc..........................C-12 Debt Service...................................C-40
GENERAL DEVELOPMENT OF THE BUSINESS...............C-14 Payment of Distributable Income................C-40
Formation......................................C-14 Changes in Legislation.........................C-41
Development....................................C-14 Loss of Mutual Fund Trust Status...............C-41
2001...................................C-14 Foreign Property Designation...................C-41
2002...................................C-16 Income Tax Payable.............................C-42
2003...................................C-18 March 23, 2004 Federal Budget..................C-42
2004...................................C-20 Experience of Management.......................C-43
DESCRIPTION OF BUSINESS...........................C-20 Potential Conflicts of Interest................C-43
Properties.....................................C-20 Government Regulation..........................C-43
Production.....................................C-24 SELECTED CONSOLIDATED FINANCIAL INFORMATION.......C-47
Selected Reserve Information...................C-24 MANAGEMENT'S DISCUSSION AND ANALYSIS..............C-48
Additional Information Relating to
Reserves Data................................C-30 MARKET FOR SECURITIES.............................C-48
Other Oil And Gas Information..................C-31 DISTRIBUTION POLICY AND RECORD....................C-48
TRUST INDENTURE...................................C-33 DIRECTORS AND OFFICERS............................C-49
Trustee........................................C-33 Amendment of Ventures USA and AcquireCo USA....C-49
Nature of the Trust............................C-34 Ultima Ventures Corp...........................C-49
Distributions..................................C-34 Ultima Acquisitions Corp.......................C-49
Offerings......................................C-34 Directors and Officers.........................C-50
Meetings and Voting............................C-34 CONFLICTS OF INTEREST.............................C-52
Limitation on Non-Resident Ownership...........C-34 ADDITIONAL INFORMATION............................C-53
Redemption Rights..............................C-35
Canadian Federal Income Tax Considerations.....C-36
EXHIBIT A - Form 51-101F2 - Report on Reserves Data by Independent Qualified Reserves Evaluators
EXHIBIT B - Form 51-101F3 - Report of Management and Directors on Oil and Gas Disclosure
EXHIBIT C - Financial Statements of Trioco Resources Inc.
EXHIBIT D - Pro forma Financial Statements of the Trust
C-2
DEFINITIONS
In this Annual Information Form, the terms set forth below have the
following meanings:
"1032213" means 1032213 Alberta Ltd., a corporation incorporated under the laws
of the Province of Alberta;
"ABCA" means the Business Corporations Act (Alberta), as amended from time to
time;
"AcquireCo" means Ultima Acquisitions Corp., a corporation incorporated under
the laws of the Province of Alberta;
"AcquireCo USA" means the amended and restated unanimous shareholder agreement
dated as of June 23, 1999 among AcquireCo, Maximize and the Trustee, for and on
behalf of the Trust, as amended;
"Additional Properties" means the working or other interests in any petroleum
and natural gas rights and miscellaneous interests that may be acquired by
Ventures Trust;
"Assets" means all forms of petroleum and natural gas related assets owned
directly by AcquireCo or any entity acquired by AcquireCo;
"bbls" means barrels; one barrel equals 0.15891 cubic metres; "bbls/d" means
barrels per day; and "mbbls" means thousands of barrels;
"boe" means barrels of oil equivalent, determined approximately on the basis
that 6 mcf of natural gas is equivalent to one bbl of oil (the factor used to
convert natural gas to oil equivalent is not based upon either energy content or
prices); "boe/d" means barrels of oil equivalent per day; and "mboe" means
thousands of barrels of oil equivalent;
"Calcrude Acquisition" has the meaning ascribed thereto under "General
Development of the Business - Development - 2003 - Calcrude Acquisition";
"COGE Handbook" means the "Canadian Oil and Gas Evaluation Handbook";
"Distributable Income" means the income of the Trust that is distributed to
Unitholders pursuant to the terms of the Trust Indenture;
"Energy Royalty" means the royalty in respect of revenues attributable to
properties and working interests held by Ultima Energy payable to the Trust;
"Energy Royalty Agreement" means the royalty agreement dated as of June 26, 2003
between Ultima Energy and Ventures, for and on behalf of the Trust;
"Exempt Plan" means trusts governed by registered retirement savings plans
("RRSPs"), registered retirement income funds ("RRIFs"), registered education
savings plans ("RESPs") and deferred profit sharing plans ("DPSPs");
"Ferrybank Property" means the 100% working interest in an oil producing
property in the Ferrybank area of central Alberta;
"GJ" means gigajoule;
C-3
"GLJ" means Gilbert Laustsen Jung Associates Ltd., a firm of independent
petroleum engineering consultants located in Calgary, Alberta;
"GLJ Report" means the report dated effective January 1, 2004 prepared by GLJ
setting forth certain information relating to the oil and natural gas reserves
associated with the Weyburn NRI;
"gross" means:
(a) in relation to the Trust's interest in production and reserves, "gross
reserves", which are Ventures' and Ultima Energy's interest (operating
and non-operating) share before deduction of royalties and without
including any royalty interests of Ventures or Ultima Energy. The
Weyburn NRI is treated as a working interest as the Trust is
responsible for its share of capital costs, operating costs, royalties
and abandonment costs;
(b) in relation to wells, the total number of wells in which Ventures and
Ultima Energy have an interest; and
(c) in relation to properties, the total area of properties in which
Ventures and Ultima Energy have an interest;
"Initial Properties" means the petroleum and natural gas working interests and
related assets in the Dodsland, Kerrobert, North Eureka, Gleneath, Plato, Smiley
and Totnes areas located near Kindersley, Saskatchewan, acquired by Ventures
Trust (through its predecessor in interest) as of July 29, 1996;
"M" means thousands; and "MM" means millions;
"Management Agreement" means the amended and restated management agreement dated
as of August 31, 1997 among Maximize, Ventures, on its own behalf and on behalf
of Ventures Trust, AcquireCo, the Trustee, for and on behalf of the Trust, and
Maximum Energy Corp. (as it existed at the time), as amended;
"Management Internalization Transaction" has the meaning ascribed thereto under
the heading "General Development of the Business - 2003 - Management
Internalization";
"Manager" means Ultima Management Inc., a corporation incorporated under the
laws of the Province of Alberta, which is the manager of the Trust, Ventures,
Ventures Trust, AcquireCo and Ultima Energy;
"Maximize" means Maximize Management Corp., a corporation incorporated under the
laws of the Province of Alberta, and the former manager of the Trust, Ventures,
Ventures Trust and AcquireCo;
"McDaniel" means McDaniel & Associates Consultants Ltd., a firm of independent
petroleum engineering consultants located in Calgary, Alberta;
"McDaniel Report" means the report prepared by McDaniel dated January 1, 2004,
setting forth certain information relating to the oil and natural gas reserves
of the Properties;
"mcf" means thousands of cubic feet; "mcf/d" means thousands of cubic feet per
day; and "mmcf" means millions of cubic feet;
"net" means:
C-4
(a) in relation to the Trust's interest in production and reserves, "net
reserves", which are Ventures' and Ultima Energy's interest (operating
and non-operating) share after deduction of royalties obligations,
plus Ventures' and Ultima Energy's royalty interests in production or
reserves;
(b) in relation to wells, the number of wells obtained by aggregating
Ventures' and Ultima Energy's working interest in each of its gross
wells; and
(c) in relation to properties, the total area in which Ventures or Ultima
Energy has an interest multiplied by the working interest owned by
Ventures or Ultima Energy.
"NGLs" means natural gas liquids;
"NI 51-101" means National Instrument 51-101 - Standards of Disclosure for Oil
and Gas Activities;
"Partnership" means the Weyburn Limited Partnership, a limited partnership
formed under the laws of the Province of British Columbia;
"Partnership Redemption" has the meaning ascribed thereto under "General
Development of the Business - Development - 2002 - Weyburn Limited Partnership
Capital Contribution and Redemption";
"Permitted Investments" includes (i) obligations issued or guaranteed by the
government of Canada or any province of Canada or any agency or instrumentality
thereof, (ii) term deposits, guaranteed investment certificates, certificates of
deposit or bankers' acceptances of or guaranteed by any Canadian chartered bank
or other financial institution (including the Trustee and any affiliate of the
Trustee) the short-term debt or deposits of which have been rated at least A1 or
the equivalent by Standard & Poors Ratings Group or at least P1 or the
equivalent thereof by Moody's Investors Service, Inc. or which have been rated
at least A1 by Canadian Bond Rating Service Inc. or at least R1 by Dominion Bond
Rating Service Limited, (iii) commercial paper rated at least A1 or the
equivalent by Canadian Bond Rating Service Inc. and R1 (high) by Dominion Bond
Rating Service Limited, in each case maturing within 180 days after the date of
acquisition, and (iv) loan advances to Ventures to finance the acquisition of
tangible equipment associated with Additional Properties provided that such
advances, in the aggregate, do not exceed 8% of the total fair market value of
the assets of the Trust Fund;
"Plato Property" means the 93% working interest in an oil producing property in
the Plato area of west central Saskatchewan;
"Probable Reserves" are those additional reserves that are less certain to be
recovered than Proved Reserves. It is equally likely that the actual remaining
quantities recovered will be greater or less than the sum of the estimated
Proved plus Probable Reserves. At least a 50% probability that the quantities
actually recovered will equal or exceed the sum of the estimated Proved plus
Probable Reserves is the targeted level of certainty;
"Properties" means the petroleum and natural gas working interests and related
assets, excluding the Weyburn NRI, which Ventures, on behalf of Ventures Trust,
and Ultima Energy may hold from time to time;
"Proved Reserves" are those reserves that can be estimated with a high degree of
certainty to be recoverable. It is likely that the actual remaining quantities
recovered will exceed the estimated Proved Reserves. At least a 90% probability
that the quantities actually recovered will equal or exceed the estimated Proved
Reserves is the targeted level of certainty;
C-5
"reserves" are the estimated remaining quantities of oil and natural gas and
related substances anticipated to be recoverable from known accumulations, from
a given date forward, based on: analysis of drilling, geological, geophysical
and engineering data; the use of established technology; and specified economic
conditions, which are generally accepted as being reasonable. Reserves are
classified according to the degree of certainty associated with the estimates;
"Rights" means rights to purchase Trust Units granted pursuant to the TURIP;
"Royalty" means the royalty in respect of revenues attributable to the
Properties held by Ventures, on behalf of Ventures Trust, payable to the Trust
pursuant to the Royalty Agreement;
"Royalty Agreement" means the amended and restated royalty agreement dated as of
as of June 23, 1999 between the Trustee, in its capacity as trustee of the
Trust, and Ventures, in its capacity as trustee of Ventures Trust;
"Subsequent Investment" means an investment made to acquire a royalty in respect
of Properties other than the Royalty or an investment made to acquire an
interest or an additional interest in all forms of petroleum and natural gas
related assets, including any Assets;
"Tax Act" means the Income Tax Act (Canada);
"Trioco Properties" has the meaning ascribed thereto under "General Development
of the Business - Development - 2003 - Trioco Acquisition";
"Trust" means Ultima Energy Trust, an open-end investment trust formed under the
laws of the Province of Alberta;
"Trust Fund" means, at any time, all monies, properties and other assets as are
at such time held by the Trust, or by the Trustee on behalf of the Trust,
including, without limitation:
(a) the Royalty;
(b) the trust units of Ventures Trust;
(c) the issued and outstanding shares of Ventures and AcquireCo held by
the Trustee;
(d) any royalty payable by AcquireCo;
(e) the issued and outstanding shares of the Manager and Ultima Energy;
(f) any instrument pursuant to which any fees, costs or expenses
associated with, and all interest, principal and other amounts payable
in relation to, funds borrowed by AcquireCo from the Trust;
(g) all Permitted Investments in which funds of the Trust may from time to
time be invested;
(h) all Subsequent Investments;
(i) all unapplied or undistributed funds which the Trust may have on hand
from time to time including the unapplied or undistributed portion of:
(i) funds realized from the sale of Trust Units;
C-6
(ii) proceeds of disposition of any asset forming part of the Trust
Fund; and
(iii) income, interest, profit and gains accruing to any asset forming
part of the Trust Fund assets; and
(j) all accretions and additional assets, rights and benefits of any kind
or nature whatsoever arising directly or indirectly from or in
connection with or accruing to any asset forming part of the Trust
Fund;
"Trustee" means Computershare Trust Company of Canada, in its capacity as
trustee of the Trust and any predecessor trustee of the Trust;
"Trust Indenture" means the amended and restated trust indenture governing the
Trust dated as of August 31, 1997 among the Trustee, Ventures, in its own
capacity and for and on behalf of Ventures Trust, AcquireCo, Maximum Energy
Corp. and Glenn C. Proudfoot, as amended;
"Trust Units" means units of the Trust, each representing an equal fractional
undivided beneficial interest therein;
"TSX" means the Toronto Stock Exchange;
"TURIP" means the amended and restated trust unit rights incentive plan of the
Trust dated May 23, 2003;
"Ultima Energy" means Ultima Energy Inc., a corporation incorporated under the
laws of the Province of Alberta;
"Unitholders" means holders of Trust Units;
"Ventures" means Ultima Ventures Corp., a corporation incorporated under the
laws of the Province of Alberta;
"Ventures Trust" means Ultima Ventures Trust, a trust formed under the laws of
the Province of Alberta;
"Ventures Trust Indenture" means the trust indenture governing Ventures Trust
dated as of August 31, 1997 between Ventures in its capacity as trustee of
Ventures Trust and the Trustee in its capacity as trustee of the Trust, as
amended;
"Ventures USA" means the unanimous shareholder agreement dated as of August 31,
1997 among Ventures, on its own behalf and for and on behalf of Ventures Trust,
Maximize, and the Trustee, for and on behalf of the Trust, as amended;
"Weyburn Unit" means the Weyburn Unit located in southeastern Saskatchewan; and
"Weyburn NRI" means the 11.7136% net royalty interest held by Ventures Trust in
the Weyburn Unit.
C-7
CONVERSION
In this Annual Information Form, certain measurements may be given in
Standard Imperial or metric units only. The following table sets forth certain
standard conversions.
TO CONVERT FROM TO MULTIPLY BY
mcf cubic metres 28.174
cubic metres cubic feet 35.494
barrels cubic metres 0.159
cubic metres barrels 6.293
feet metres 0.305
metres feet 3.281
miles kilometres 1.609
kilometers miles 0.621
acres hectares 0.405
hectares acres 2.471
A boe conversion may be misleading, particularly if used in isolation. A boe
conversion ratio of 6 mcf: l bbl is based on an energy equivalency conversion
method primarily applicable at the burner tip and does not represent a value
equivalency at the wellhead.
C-8
ORGANIZATION AND STRUCTURE OF ULTIMA ENERGY TRUST
Ultima Energy Trust
Formation and Structure
Ultima Energy Trust is an open-end investment trust formed under the
laws of the Province of Alberta pursuant to the Trust Indenture for the purpose
of acquiring and holding royalties on petroleum and natural gas properties and
related assets. The trustee of the Trust is Computershare Trust Company of
Canada. The sole beneficiaries of the Trust are the Unitholders. The head and
principal office of the Trust is located at 1000, 350 - 7th S.W., Calgary,
Alberta, T2P 3N9. The principal place of business of the Trustee is located at
600, 530 - 8th Avenue S.W., Calgary, Alberta, T2P 3S8.
The Trust holds: (i) all the issued and outstanding trust units of
Ventures Trust and, accordingly, is the sole beneficiary of Ventures Trust; (ii)
the Royalty equal to 99% of the net income derived from certain petroleum and
natural gas properties, the working interests in which are held by Ventures
Trust; (iii) all of the issued and outstanding shares of Ventures, the trustee
of Ventures Trust; (iv) all of the issued and outstanding shares of AcquireCo,
through which future petroleum and natural gas related corporate and facilities
acquisitions may be made; (v) all of the issued and outstanding shares of Ultima
Energy; (vi) the Energy Royalty equal to 99% of the net income derived from
certain petroleum and natural gas properties, the working interests in which are
held by Ultima Energy; (vii) all of the issued and outstanding shares of the
Manager; and (viii) promissory notes granted by Ventures Trust and the Manager
to the Trust (the "Notes").
Pursuant to the terms of Royalty Agreement and the Energy Royalty
Agreement, the Trust receives royalty payments from Ventures Trust and Ultima
Energy in respect of the cash flow generated from the Properties. As the sole
beneficiary of Ventures Trust, the Trust also receives distributions from
Ventures Trust in respect of cash flow attributable to the Weyburn NRI.
Pursuant to the terms of the Trust Indenture, the boards of directors
of Ventures and AcquireCo, have the authority and responsibility to make or
approve most significant decisions affecting the Trust and its subsidiaries. At
the Annual and Special Meeting of the Trust held on May 23, 2003, Unitholders
resolved to amend the Ventures USA and the AcquireCo USA to provide that all of
the directors of Ventures and AcquireCo be elected by the Unitholders. Each of
the Ventures USA and the AcquireCo USA also provides that the boards of
directors of Ventures and AcquireCo, respectively, may give special, but not
exclusive, consideration to the interests of the Unitholders in determining
whether a matter under its consideration is in the best interests of Ventures
and AcquireCo, respectively.
The Manager has been engaged to provide services in connection with the
management and administration of the Trust, Ventures Trust, Ventures and
AcquireCo, and in connection with the operation of the assets and petroleum and
natural gas properties owned or that may be acquired by Ventures Trust and/or
AcquireCo. The Manager also provides services to Ultima Energy.
On March 26, 2003, the Trust, through 1032213, completed the
acquisition of all of the issued and outstanding common shares of the Manager
(the "Common Shares") in connection with the internalization of the management
structure of the Trust. See "General Development of the Business - Development -
2003 - Management Internalization".
The Manager employs the employees and consultants that manage and
administer the Trust's assets and undertakings. The Trust has no employees.
C-9
The Trust's current organizational structure is as follows:
[OBJECT OMITTED]
UNITHOLDERS
|
|
Ultima Ventures Ultima
Corp. ------ 100% ----- Energy
Trust
| |
| |
Trustee of Ventures Trust |
| |
--------------------------------------------------------------------------------------------------------
| | | |
100% 100% 100% 100%
| | | |
| | | |
Ultima Ultima Ventures Ultima Ultima
Energy Inc. Trust Acquisitions Management Inc.
Corp.
| | | |
| | | |
Holds petroleum and Holds petroleum and Holds future acquired Manages the Trust,
natural gas properties natural gas properties corporations and facilities Ventures, Ventures
and the Weyburn NRI Trust, AcquireCo and
Ultima Energy
As an open-end trust, the Trust is not as restricted in the type of
assets it holds or the type of acquisitions it undertakes in order to maintain
its status under the Tax Act as a "unit trust" and as a "mutual fund trust" so
long as a retraction right is attached to the Trust Units. As an open-end trust,
the activities of the Trust can be expanded from the acquisition and holding of
royalties on petroleum and natural gas properties and related assets to include
the direct or indirect acquisition and holding of all forms of petroleum and
natural gas related assets (such as the shares of an oil and gas company or
facilities without associated properties) that can be reasonably expected to
provide long-term returns and Unitholder distributions.
Distributions to Unitholders
The Trust receives cash royalty payments from Ventures Trust under the
Royalty Agreement, distributions from Ventures Trust in respect of cash flow
attributable to the Weyburn NRI, cash royalty payments from Ultima Energy under
the Energy Royalty Agreement and cash interest payments in respect of the Notes.
Pursuant to the terms of the Trust Indenture, the Trust distributes
substantially all such amounts to the Unitholders, subject only to certain
adjustments that include fees and expenses paid to the Trustee and the Manager.
See "Distribution Policy and Record".
Ultima Ventures Trust
Formation
Ventures Trust was formed under the laws of the Province of Alberta
pursuant to the Ventures Trust Indenture. The sole beneficiary of Ventures Trust
is the Trust, being the sole holder of the trust units of Ventures Trust. The
head and principal office of Ventures Trust and the principal place of business
of Ventures, the trustee of the Trust, is located at 1000, 350 - 7th Avenue
S.W., Calgary, Alberta T2P 3N9.
C-10
Ventures Trust was established for the purpose of, and its business is
restricted to, purchasing, holding, operating and divesting petroleum, natural
gas and related hydrocarbons and related facility interests including the
development of petroleum and natural gas, the transportation, processing,
marketing and sale thereof and all business operations incidental or in any way
related to the foregoing.
Since Ventures holds, as trustee for Ventures Trust, all the assets and
property of Ventures Trust and conducts all business on behalf of Ventures
Trust, Ventures Trust is bound by the same restrictions affecting Ventures in
the Royalty Agreement, including a prohibition on spending funds on exploratory
operations and the nature of acquisitions and dispositions that it may effect.
Distributions and Royalty Payments
Ventures, in its capacity as trustee of Ventures Trust, receives cash
flow from the sale of petroleum and natural gas produced from the Properties
held by it (and other properties that it may in the future acquire) and, to an
immaterial extent, from the provision of processing services to third parties
who use the gathering facilities located near the Properties. Pursuant to the
terms of the Royalty Agreement, 99% of such cash flow, less the aggregate of all
operating costs, capital expenditures not funded by debt, net contributions to
Ventures' (and, therefore, Ventures Trust's) reclamation fund, debt service
costs and debt repayments, fees paid or payable to the Manager and other general
and administrative expenses, taxes, and certain other adjustments, is paid to
the Trust as the Royalty. Ventures Trust also receives revenues attributable to
the Weyburn NRI. Such amounts are distributed to the Trust as sole beneficiary
of Ventures Trust.
Cash flow from the Royalty and the Weyburn NRI is, subject to certain
deductions, distributed to Unitholders by the Trust. Such cash distributions may
be taxable in whole or in part. In approving any future acquisition by Ventures,
in its capacity as trustee of Ventures Trust, the board of directors of Ventures
is required to consider and determine, among other things, that such acquisition
is in the best interests of Ventures and the Trust.
Ultima Ventures Corp.
Incorporation and Organization
Ventures was incorporated under the ABCA on August 21, 1997. The
registered office of Ventures is 4500, 855 - 2nd Street S.W. Calgary, Alberta
T2P 4K7. The head and principal office of Ventures is located at 1000, 350 - 7th
Avenue S.W., Calgary, Alberta T2P 3N9. The Trust is the sole shareholder of
Ventures.
Ventures, in its capacity as trustee of Ventures Trust, has retained
the Manager, pursuant to the Management Agreement, for the purposes of
identifying, evaluating and assisting in the acquisition, disposition and
ongoing management of its assets, including overseeing the operation and
administration of the business of Ventures and Ventures Trust, all subject to
the direction of the board of directors of Ventures. The Manager is required to
exercise the degree of care, diligence and skill that a reasonably prudent oil
and natural gas industry advisor and manager would exercise in comparable
circumstances.
Ultima Energy Inc.
Incorporation and Organization
Ultima Energy was incorporated under the ABCA on June 23, 2003, and
subsequently amalgamated with Trioco Resources Inc. ("Trioco") on June 26, 2003.
The registered office of Ultima Energy is 4500, 855 - 2nd Street S.W. Calgary,
Alberta T2P 4K7. Ultima Energy does not maintain its own premises. The Trust is
the sole shareholder of Ultima Energy.
C-11
Ultima Energy was formed for the purpose of effecting the acquisition
of all of the issued and outstanding shares of Trioco. See "General Development
of the Business - Development - 2003 - Trioco Acquisition". Following the Trioco
Acquisition (as defined below), Ultima Energy granted the Energy Royalty to the
Trust effective June 26, 2003. Pursuant to the Energy Royalty Agreement, the
Trust receives a royalty from Ultima Energy equal to 99% of the net cashflow,
after costs, derived from petroleum and natural gas properties owned by Ultima
Energy.
Ultima Acquisitions Corp.
Incorporation and Organization
AcquireCo was incorporated under the ABCA on August 21, 1997. The
registered office of AcquireCo is 4500, 855 - 2nd Street S.W. Calgary, Alberta
T2P 4K7. AcquireCo does not maintain its own premises. The Trust is the sole
shareholder of AcquireCo.
AcquireCo has retained the Manager, pursuant to the Management
Agreement, for the purposes of identifying, evaluating and assisting in the
acquisition, disposition and ongoing management of its assets, including
overseeing the operations and administration of the business of AcquireCo, all
subject to the direction of the board of directors of AcquireCo. The Manager is
required to exercise the degree of care, diligence and skill that a reasonably
prudent oil and natural gas industry advisor and manager would exercise in
comparable circumstances.
Restrictions on the Business of AcquireCo
AcquireCo was incorporated and organized for the sole purpose of, and
its business is restricted in the AcquireCo USA to, acquiring, developing,
exploiting and disposing of all forms of petroleum and natural gas related
assets, including, without limitation, facilities of any kind (whether acquired
with associated properties or not) and whether effected through an acquisition
of assets or an acquisition of shares or other form of ownership interest in an
entity the substantial majority of the assets of which are comprised of like
assets and activities ancillary thereto. AcquireCo is prohibited from spending
funds on exploratory operations, except as deemed necessary or advisable to
wind-down existing exploration operations in progress in respect of assets at
the time of their acquisition by AcquireCo, including funds necessary to fulfill
any pre-existing contractual or other commitments or to enhance the value of any
property, and except as approved by the board of directors of AcquireCo.
As at the date hereof, AcquireCo does not own any assets.
Dividends
As at the date hereof, AcquireCo does not own any assets and therefore
has received no cash flow and made no dividend, interest or other payments to
the Trust.
Pursuant to the terms of the AcquireCo USA, with the approval of its
board of directors, AcquireCo will distribute to the Trust all of its available
cash, subject to applicable law and certain deductions, including, without
limitation, expenses, ongoing capital expenditures to the extent not funded by
debt and subject to AcquireCo retaining such reasonable reserves or funds for
the acquisition of replacement assets as may be considered appropriate by the
board of directors of AcquireCo.
Ultima Management Inc.
Incorporation and Organization
The Manager was incorporated under the ABCA on October 25, 2000 and
subsequently amalgamated with 1032213, a wholly-owned subsidiary of the Trust,
on August 1, 2003 and continued
C-12
under the name Ultima Management Inc. The registered office of the Manager is
4500, 855 - 2nd Street S.W., Calgary, Alberta T2P 4K7. The head and principal
office of the Manager is located at 1000, 350 - 7th Avenue S.W., Calgary,
Alberta T2P 3N9.
On March 26, 2003, the Trust, through 1032213, completed the
acquisition of all of the issued and outstanding Common Shares for a total cost
of $5,300,000. A total of $3,800,000, consisting of $3,000,000 in cash and
143,365 Trust Units (with a value of $800,000), was paid to purchase all of the
Common Shares. The remaining $1,500,000 has been and will be used to fund
retention obligations to the three senior officers and other management
employees of the Manager. See "General Development of the Business - Development
- 2003 - Management Internalization".
Business of the Manager
Pursuant to the terms of the Management Agreement, the Manager provides
services in connection with the management and administration of the Trust,
Ventures Trust, Ventures and AcquireCo, and in connection with the operation of
the properties and assets owned, or which may be acquired, by Ventures Trust
and/or AcquireCo. The delegation of authority to the Manager is subject to the
supervision of, and restrictions imposed from time to time by, the boards of
directors of Ventures and AcquireCo, and the provisions of the Management
Agreement. In particular, the boards of directors of Ventures and AcquireCo have
exclusive authority over matters such as the annual operating budget,
acquisitions and dispositions of properties, capital expenditures and
acquisitions in excess of $2,000,000, borrowing limits and policies, equity
financing approval and the Trust's cash distribution policy. The Manager also
provides services to Ultima Energy.
Compensation of the Manager
Pursuant to the Management Agreement, Ventures, for and on behalf of
Ventures Trust, AcquireCo and the Trustee, for and on behalf of the Trust, paid
the Manager a management fee (the "Management Fee") equal to the aggregate of
(i) 3% of the net production revenue attributable to the Properties; and (ii)
1/99 of the royalty payable by Ventures Trust to the Trust. The Management
Agreement also provided that the Manager be paid an acquisition fee equal to
1.5% of the purchase price of any assets acquired by Ventures Trust or AcquireCo
(the "Acquisition Fee"), and an administration fee for management,
administration and advisory services provided to Ventures, AcquireCo, Ventures
Trust and the Trust (the "Administration Fee"). A Management Fee of $487,000 was
paid to the Manager for the period commencing January 1, 2003 and ending on
March 26, 2003. No Administration Fee or Acquisition Fee was earned for that
period.
The Management Agreement also provides that Ventures, AcquireCo and the
Trustee, for and on behalf of the Trust, reimburse the Manager for the time the
Manager's personnel spend on the management and administration of the Trust,
Ventures Trust, Ventures and AcquireCo. The boards of directors of Ventures and
AcquireCo, having regard to industry salaries, approve the amounts paid in
respect of salaries and benefits as part of their approval of the general and
administrative budget of the Manager. A total of $554,000 was paid to the
Manager by Ventures, AcquireCo and the Trustee, for and on behalf of the Trust,
in respect of salaries, benefits and bonus for the period commencing January 1,
2003 and ending on March 26, 2003, the date on which the Management
Internalization Transaction was completed.
As a result of the Management Internalization Transaction and
subsequent amalgamation of the Manager with 1032213, the Manager is now a
wholly-owned subsidiary of the Trust. Consequently, any fees paid or
reimbursement of costs to the Manager are now effectively for the account of the
Trust as they remain within the Trust's structure.
C-13
GENERAL DEVELOPMENT OF THE BUSINESS
Formation
Maximum Energy Corp. ("Maximum") and the Trust were created in 1996 for
the purpose of acquiring, developing and operating petroleum and natural gas
properties and related assets. Maximum acquired the Initial Properties in July
1996 and granted a royalty on the properties to the Trust. During 1997, Maximum
acquired a gas gathering system in the Kindersley area of west central
Saskatchewan and petroleum and natural gas properties located in the Provost
area of east central Alberta.
At a special meeting of Unitholders held in August 1997, the
Unitholders approved the conversion of the Trust from a close-end unincorporated
investment trust to an open-end unincorporated investment trust. At the same
meeting, the Unitholders approved the sale, transfer and conveyance of all of
the assets and liabilities of Maximum to the newly created Ventures Trust, which
transaction was completed as of August 31, 1997. As part of the transaction, the
credit facility maintained by Maximum, and the royalty obligation under the
Royalty Agreement were assumed by Ventures Trust.
Pursuant to the Royalty Agreement, the Trust receives a royalty from
Ventures Trust and the Trust distributes such royalty payments to the
Unitholders, subject only to certain adjustments that include fees and expenses
paid to the Trustee and the Manager. Since 1997, additional oil and gas
properties have been acquired by Ventures Trust and the Trust has received
royalties from those properties. As sole beneficiary of Ventures Trust, the
Trust also receives distributions from Ventures Trust in respect of cash flow
attributable to the Weyburn NRI. Pursuant to the Energy Royalty Agreement, the
Trust receives a royalty from Ultima Energy in respect of certain petroleum and
natural gas properties, the working interests of which are held by Ultima
Energy.
Development
2001
Appointment of New Trustee
In April 2001, The Trust Company of Bank of Montreal resigned as
trustee of the Trust. Pursuant to an assignment and novation agreement dated
September 10, 2001, Computershare Trust Company of Canada accepted its
appointment as, and assumed all the obligations of, trustee of the Trust.
Change of Name
As part of the restructuring of the Trust that began in December 2000,
the Manager determined that the Trust should be renamed to better reflect the
changes which had been implemented to the business and affairs of the Trust.
Accordingly, a process was commenced in the Spring of 2001 to search for a new
name for the Trust. "Ultima Energy Trust" was chosen to replace "Maximum Energy
Trust" as the name of the Trust and "UET.UN" was chosen as the new trading
symbol for the Trust Units on the TSX. The boards of directors of Ventures and
AcquireCo approved the change of name of the Trust by resolution dated September
10, 2001 as permitted by the terms of the Trust Indenture.
The names of Ventures and AcquireCo were also changed as part of the
restructuring process. Pursuant to the Ventures USA and the AcquireCo USA,
changes in the names of Ventures and AcquireCo required the approval of the
Trustee acting on the direction of a special resolution of Unitholders. At a
Special Meeting of Unitholders held on October 15, 2001, the Unitholders
approved the change of name of Ventures from "Maximum Holdings Corp." to "Ultima
Ventures Corp." and the change of name of AcquireCo from "Maximum Acquisitions
Corp." to "Ultima Acquisitions Corp." By Certificates of Amendment dated October
16, 2001, the names of Ventures and AcquireCo were changed to Ultima Ventures
Corp. and Ultima Acquisitions Corp., respectively.
C-14
Change of Auditors
In the Spring of 2001, the Trust began realigning its relationships
with its advisors and professional services firms. In furtherance of that
objective, the boards of directors of each of Ventures and AcquireCo resolved to
search for a replacement for Deloitte & Touche LLP as auditors of the Trust,
Ventures Trust, Ventures and AcquireCo. At the Special Meeting of Unitholders
held on October 15, 2001, the Unitholders accepted and approved the resignation
of Deloitte & Touche LLP and approved, by ordinary resolution, the appointment
of Arthur Andersen LLP as auditors of the Trust, Ventures Trust, Ventures and
AcquireCo.
Trust Unit Rights Incentive Plan
At the Special Meeting of Unitholders held on October 15, 2001, the
Unitholders adopted, by ordinary resolution, a Trust Unit rights incentive plan.
The purpose of the TURIP is:
1. to develop the interest of directors, officers, employees and key
consultants of the Trust, its affiliates and the Manager, in the growth
and development of the Trust by providing such persons with the
opportunity to acquire a proprietary interest in the Trust;
2. to provide a compensation mechanism for persons who provide a service
to the Trust on an ongoing basis, or who have provided, or are expected
to provide, a service of value to the Trust; and
3. to align the interests of directors, officers, employees and key
consultants with those of Unitholders by devising a compensation
mechanism which encourages the prudent maximization of distributions to
Unitholders and long-term value growth of the Trust Units.
The TURIP permits the directors of Ventures and AcquireCo to grant
Rights to those persons eligible to participate in the TURIP. Rights may only be
granted with the approval of the directors of Ventures and AcquireCo. As at
December 31, 2003, Rights to acquire 2,007,669 Trust Units were outstanding.
Asset Acquisition
On December 17, 2001, Ventures Trust acquired from Baytex Energy Ltd.
two oil producing properties and associated facilities located at Westerose and
Glenevis in central Alberta (the "Central Alberta Properties") with an average
combined working interest of 93% for a purchase price of $35,000,000 in cash,
before closing adjustments and costs of the acquisition. Production from the
Central Alberta Properties at the time of purchase was approximately 1,375
bbls/d of light and medium quality oil (33 API average) and 150 mcf/d of natural
gas.
Private Placements
On December 17, 2001, the Trust closed a private placement of 3,400,000
Trust Units at a price of $3.50 per Trust Unit for gross proceeds of
$11,900,000. The proceeds of the private placement were used to partially fund
the acquisition of the Central Alberta Properties. The Trust closed a subsequent
private placement of 350,000 Trust Units on January 17, 2002 at a price of $4.30
per Trust Unit for gross proceeds of $1,505,000. The proceeds of the private
placement were used to reduce bank debt incurred in connection with the purchase
of the Central Alberta Properties.
C-15
2002
Cherhill Acquisition
On October 16, 2002, the Trust, through Ventures Trust, purchased an
approximately 50% working interest in a light oil producing property and
associated facilities in the Cherhill area of central Alberta (the "Cherhill
Property") from Southward Energy Ltd. (the "Cherhill Acquisition"). The total
purchase price of the Cherhill Acquisition, net to the Trust, was $10,260,000 in
cash, before closing adjustments and expenses related to the Cherhill
Acquisition. The Cherhill Acquisition was financed using Ventures Trust's credit
facility.
McDaniel evaluated the Cherhill Property for the Trust and assigned 1.1
million boe of total proved reserves (suggesting a purchase price of $9.30 per
proved boe) and 1.25 million boe of established reserves (suggesting a purchase
price of $8.20 per established boe and an established reserve life index of
approximately eight years) to the Cherhill Property.
Cyn-Pem Acquisition
On December 3, 2002, the Trust, through Ventures Trust, entered into an
agreement with a number of Conoco Phillips entities to purchase working
interests ranging from 25% to 65% in liquids-rich natural gas and light oil
producing properties in the Cyn-Pem area of central Alberta (the "Cyn-Pem
Properties") for a total purchase price of $16,750,000 in cash, before closing
adjustments and expenses related to the acquisition (the "Cyn-Pem Acquisition").
The transaction was closed on December 17, 2002, with an effective date of
October 1, 2002. The Cyn-Pem Acquisition was financed using Ventures Trust's
credit facility.
The transaction was consistent with the Trust's strategy of asset
diversification and growth of its central Alberta core area through acquisition
of predictable, high quality, low operating cost reserves. The Cyn-Pem
Properties are characterized by operating costs of less than $4.00 per boe and
are located near the Central Alberta Properties.
McDaniel evaluated the Cyn-Pem Properties for the Trust and assigned
1.3 million boe of total proved reserves and 1.4 million boe of established
reserves (suggesting a purchase price of $11.65 per established boe) to the
properties.
Weyburn Limited Partnership Capital Contribution and Redemption
On December 31, 2002, with an effective date of November 1, 2002, the
Trust sold its entire interest in the Partnership to Ventures Trust. Ventures
Trust subsequently advanced approximately $67,000,000 to the Partnership in the
form of a capital contribution (the "Contribution"), which payment increased
Ventures Trust's percentage partnership interest in the Partnership from 92% to
approximately 99%. The Partnership then used the Contribution to repay, in full,
a loan in the amount of approximately $67,000,000 (the "Loan") owing to EnCana
Resources, the managing partner of the Partnership. Upon repayment of the Loan,
Ventures Trust redeemed its entire limited partnership interest in the
Partnership (the "Partnership Redemption"). As a result of the Partnership
Redemption, the Trust, through Ventures Trust, acquired an interest in
approximately 99% of the assets of the Partnership, primarily consisting of the
Weyburn NRI, the Ferrybank Property and the Plato Property (collectively, the
"Partnership Assets"). Ventures Trust designated the Weyburn NRI and the Plato
Property, as well as the Partnership's working capital, as the Partnership
Assets it would obtain in exchange for its interest in the Partnership pursuant
to the Partnership Redemption. The Ferrybank Property, which accounted for less
than 3% of the total value of the Partnership's reserves, was retained by the
Partnership.
EnCana Resources granted the Weyburn NRI to the Partnership pursuant to
a Net Royalty Agreement dated October 31, 2000 (the "NRI Agreement"). Under the
terms of the NRI Agreement, the
C-16
Weyburn NRI entitles Ventures Trust, as a result of the Partnership Redemption,
to receive a monthly royalty payment calculated by reference to the revenue from
oil and natural gas production attributable to an 11.7136% participating
interest in the Weyburn Unit (the "Revenue") less all costs and expenses,
including capital expenditures and future reclamation costs, associated with
such production. The Weyburn NRI is intended to be an interest in land and is to
continue in full force and effect so long as there are petroleum and natural gas
rights associated with the Weyburn Unit to which the Weyburn NRI applies. Prior
to the Partnership Redemption, the NRI Agreement provided for the payment of
capital costs incurred in connection with the Weyburn Unit's operations prior to
January 1, 2003 to be deferred and accrue interest. Deferred capital
expenditures and accrued interest were to be deducted from Revenue only on a
monthly basis commencing January 2003 and ending December 2019 (the
"Amortization Period"). Interest was accrued on the amount of the deferred
capital expenditures at a base interest rate of 8.5% per annum, and was to be
adjusted over the Amortization Period to provide for an effective interest rate
of approximately 13% per annum throughout the Amortization Period, with the
higher levels of interest accruing during the last five years of the
Amortization Period. The maximum amount of the capital expenditures which was to
be deferred in this manner was $18,778,000, plus accrued interest (the "Initial
Deferred Capital Obligation").
In connection with the Partnership Redemption, the NRI Agreement was
amended (the "NRI Amendment") to provide that:
(a) the base interest rate accrued on the Initial Deferred Capital
Obligation will be reduced to 7.0% from 8.5% effective January 1,
2003;
(b) as at January 1, 2004, up to an additional $9,200,000 of capital
expenditures applicable to the Weyburn NRI can be deferred for
the years 2004 and 2005 (the "Other Deferred Capital
Obligation"). The Trust shall have the right to select the amount
of capital expenditures to be deferred each year, to a maximum of
$8,000,000 of deferred capital expenditures in any given year.
Interest will accrue on the Other Deferred Capital Obligation at
the base interest rate of 7.0% per annum;
(c) the Initial Deferred Capital Obligation and the Other Deferred
Capital Obligation (collectively, the "New Deferred Capital
Obligation") will be consolidated and deducted from Revenue on a
monthly basis pursuant to the deferred capital charge
calculation, over a 15 year period commencing the month
immediately following the month the Other Deferred Capital
Obligation, excluding interest charges, reaches $15,000,000, or
January 1, 2006, whichever occurs first (the "New Amortization
Period"). Interest will continue to accrue on the amount of the
outstanding New Deferred Capital Obligation at a base interest
rate of 7.0% per annum and be adjusted over the New Amortization
Period to provide for an effective interest rate of approximately
10% per annum throughout the New Amortization Period, with the
higher levels of interest accruing during the last five years of
the New Amortization period;
(d) the New Deferred Capital Obligation will be recovered by EnCana
Resources as a deductible cost from Revenue in the calculation of
the monthly Weyburn NRI payment only (Ventures Trust's assets do
not secure the Weyburn NRI); and
(e) the Trust will have the right to prepay all or any part of the
New Deferred Capital Obligation, plus accrued but unpaid interest
along with an additional 7% of the amount of New Deferred Capital
Obligation being prepaid, for cash at anytime which the Trust
presently intends to do prior to the expiry of the New
Amortization Period.
C-17
Prospectus Offerings
The Trust completed a public offering of 5,000,000 Trust Units at a
price of $5.10 per Trust Unit in May of 2002. The net proceeds from the offering
were used to reduce the outstanding bank debt primarily incurred by Ventures
Trust to fund the acquisition of the Central Alberta Properties. The Trust
completed another public offering of 10,000,000 Trust Units at a price of $4.90
per Trust Unit in December of 2002. The net proceeds from that offering, along
with $20,350,000 drawn from the credit facility of Ventures Trust, was paid to
the Partnership as a Contribution in connection with the Partnership Redemption.
See "General Development of the Business - Development - 2002 - Weyburn Limited
Partnership Capital Contribution and Redemption".
2003
Management Internalization
In the fall of 2002, a Special Committee comprised of independent
members of the Boards was established to consider the merits of internalizing
the management services provided by the Manager to the Trust, Ventures Trust,
Ventures and AcquireCo pursuant to the Management Agreement in order to
eliminate future management fees, improve the governance structure of the Trust
and align the interests of management and the Trust (the "Management
Internalization Transaction").
The Special Committee completed a comprehensive review of a wide range
of issues relevant to the internalization process. In evaluating the
alternatives available to the Trust, the Special Committee had several
objectives, including:
1. retaining the management team of the Trust;
2. ensuring that the economic benefit to Unitholders realized by
eliminating future third party management and acquisition fees would
exceed the cost of the internalization and be accretive to future cash
flow and net asset value; and
3. better aligning the interests of management and directors with the
interests of Unitholders.
Upon completion of its review, the Special Committee unanimously
recommended approval of the Management Internalization Transaction to the Boards
and the Boards unanimously approved the Management Internalization Transaction.
In approving the transaction, the Boards gave particular attention to the
opinion of RBC Dominion Securities Inc., financial advisor to the Special
Committee, that the consideration paid for the common shares of the Manager was
fair, from a financial point of view, to the Trust.
On March 26, 2003, the Trust completed the Management Internalization
Transaction for a total cost of $5,300,000. $3,800,000, consisting of $3,000,000
in cash and 143,369 Trust Units (valued at $800,000 based on the preceding
20-day average closing price of the Trust Units on the TSX), was paid by the
Trust through 1032213 to purchase all of the issued and outstanding common
shares of the Manager. The remaining $1,500,000 was used to fund retention
obligations to the three senior officers and other management employees of the
Manager. One-half of the retention, consisting of $500,000 in cash and 44,803
Trust Units (valued at $250,000, based on the preceding 20 day average closing
price of the Trust Units on the TSX), was paid on closing of the transaction.
The balance of the retention ($750,000) to be paid in Trust Units may be earned
by the three senior officers of the Manager over the three-year period following
the closing of the transaction, subject to certain conditions, including the
officers remaining as employees of the Manager.
C-18
Calcrude Acquisition
On June 24, 2003, Ventures Trust, through Ventures, completed the
purchase of an approximate 40% working interest in 29 gross (11.6 net) producing
light oil and natural gas wells and associated facilities in the Cherhill Banff
A pool located in central Alberta, and other minor property interests in central
Alberta (collectively, the "Cherhill Properties") from Calgary Crude Oil Limited
and Calcrude Oils Ltd. for a purchase price of $16,100,000, prior to any closing
adjustments (the "Calcrude Acquisition"). Ventures Trust had previously
purchased interests in the Cherhill Properties in 2002.
As of March 2003, production from the Cherhill Properties was
approximately 600 boed, consisting of 350 bbls/d of light oil and natural gas
liquids and 1.5 mmcfd of natural gas. Production is primarily from the medium
depth Banff and Mannville zones. The Calcrude Acquisition increased the Trust's
total working interest in the Cherhill Banff A pool to approximately 90%.
Ventures assumed operatorship of the Cherhill Banff A pool following the
Calcrude Acquisition.
McDaniel prepared a report for the Trust in respect of the Cherhill
Properties acquired in connection with the Calcrude Acquisition representing
approximately 95% of the reserves and net present value attributable to the
Calcrude Acquisition and assigned 1.4 million boe of total proved reserves and
1.6 million boe of established reserves to the Cherhill Properties. The report
excluded reserves attributable to the Cherhill Property acquired in 2002.
Trioco Acquisition
On June 26, 2003 the Trust, through Ultima Energy, completed the
purchase of all of the issued and outstanding common shares and preferred shares
in the capital of Trioco for an aggregate purchase price of $71,000,000, subject
to certain adjustments (the "Trioco Acquisition"). The Trioco Acquisition closed
on June 26, 2003 and was financed using the existing credit facilities of
Ventures Trust and a $35,000,000 bridge facility of Ventures Trust. Upon closing
of the Trioco Acquisition, Ultima Energy and Trioco amalgamated and the
amalgamated company retained the name of Ultima Energy Inc. Effective June 26,
2003, Ultima Energy granted the Energy Royalty to the Trust.
Trioco was an Alberta-based oil and gas company with its primary
producing properties located in the Spirit River area of the Peace River Arch
and the St. Albert, Deanne and Caroline areas of central Alberta. In a report
dated as of May 1, 2003 (the "Trioco Report"), McDaniel evaluated the reserves
for the petroleum and natural gas interests acquired pursuant to the Trioco
Acquisition for the Trust and assigned 5.1 million boe of total proved reserves
and 6.1 million boe of established reserves to the properties (the "Trioco
Properties"). As of June 2003, production from the Trioco Properties was
approximately 2,050 boed, consisting of 660 boed of oil and natural gas liquids
and 8.3 mmcfd of natural gas.
At the time of purchase, the Trioco Acquisition increased the Trust's
total production to approximately 9,600 boed. The Trioco Acquisition also
included 33,005 gross (15,580 net) acres of undeveloped land in the Peace River
Arch area and central Alberta as well as proprietary seismic data valued at
$1,400,000.
Exhibit "C" hereto sets forth certain financial information relating to
Trioco and Exhibit "D" contains pro forma financial information of the Trust
which gives effect to the Trioco Acquisition.
Prospectus Offerings
The Trust completed a public offering of 5,000,000 Trust Units at a
price of $5.05 per Trust Unit in May of 2003. $23,987,500 of the net proceeds of
the offering were used to fund the Calcrude Acquisition. "See "General
Development of the Business - Development - 2003 - Cherhill Acquisition".
C-19
The balance of the net proceeds from the offering were used to repay a portion
of the outstanding indebtedness of Ventures Trust and to fund future development
of the Trust's properties.
The Trust completed a public offering of 12,000,000 Trust Units at a
price of $5.20 per Trust Unit in July of 2003. The net proceeds of $59,280,000
from that offering were used to repay a portion of the outstanding indebtedness
of Ventures Trust, which indebtedness was incurred, in part, to complete the
Trioco Acquisition. See "General Development of the Business-Development - 2003
- Trioco Acquisition".
In December of 2003, the Trust completed another public offering of
6,000,000 Trust Units at a price of $5.70 per Trust Unit. The net proceeds of
$32,490,000 from that offering were used to reduce outstanding bank debt of
Ventures Trust, thereby freeing up capacity to fund the Trust's 2004 capital
expenditures and acquisition program and for general purposes.
2004
Merger with Petrofund Energy Trust
On March 29, 2004, the Trust, Ventures, Petrofund Energy Trust
("Petrofund") and Petrofund Corp., entered into a combination agreement (the
"Combination Agreement") whereby they agreed to combine the operations of the
Trust and Petrofund. Pursuant to the terms of the Combination Agreement, each
Trust Unit will be exchanged for 0.442 of a Petrofund unit on a tax-deferred
rollover basis. Unitholders will also receive an aggregate of $10 million in the
form of a one-time special distribution, estimated to be approximately $0.17 per
Trust Unit and payable on or about June 15, 2004. Subject to regulatory approval
and the approval of at least two-thirds of Unitholders voting at a meeting to be
held on or about June 4, 2004, the transaction is expected to close on or about
June 16, 2004.
DESCRIPTION OF BUSINESS
The business activities from which the Trust derives its revenues are
presently conducted through or in connection with assets, properties and
interests held by Ventures Trust (through Ventures) and Ultima Energy. All
references herein to any business, assets, properties or interests of the Trust
are made, without specifying the nature thereof, about the business, assets,
properties and interests of Ventures Trust (or Ventures on behalf of Ventures
Trust) and Ultima Energy.
The Trust engaged McDaniel to evaluate the oil and natural gas reserves
associated with the Properties. The reserves associated with the Weyburn NRI
were evaluated by another independent engineering firm, GLJ. References to
reserve volumes in the following discussion are based on the McDaniel Report and
the GLJ Report which have been combined by McDaniel for use by the Trust.
Properties
Ventures Trust owns oil and natural gas reserves located primarily in
the Westerose, Cherhill and Cyn-Pem areas of central Alberta, the Kindersley
area of west central Saskatchewan and the Provost area of east central Alberta.
Ventures Trust also holds the Weyburn NRI which provides it an 11.7136% net
royalty interest in the Weyburn Unit in southeastern Saskatchewan. Ultima Energy
holds the Trioco Properties located in central and northwest Alberta.
The portfolio of Properties, including the Weyburn NRI, acquired and
held by the Trust include primarily long life, unitized and non-unitized
properties with well established production profiles. The following table sets
forth a summary of the proved plus probable reserves and production attributable
to the Properties and the Weyburn NRI:
C-20
------------------------------------------------------------------------------------------------------------------------
Trust Reserves and Production
------------------------------------------------------------------------------------------------------------------------
Property Proved plus Average Daily Production Average Daily Production
Probable Reserves for the 12 months ended for the three months ended
as at January 1, 2004 December 31, 2003 of December 31, 2003
(mboe) (boe/d) (boe/d)
------------------------------------------------------------------------------------------------------------------------
Weyburn NRI 17,751 2,517 2,684
Spirit River 4,631 364 875
Cherhill 4,182 879 1,257
Westerose 2,262 897 860
Provost 2,118 387 410
Kerrobert 1,813 498 497
Glenevis 1,509 683 652
North Eureka 1,194 236 245
Cyn-Pem 987 477 685
Other 4,930 1,628 2,049
------------------------------------------------------------------------------------------------------------------------
Total 41,377 8,566 10,214
------------------------------------------------------------------------------------------------------------------------
Approximately 88% of the total proved plus probable reserves of
Ventures Trust and Ultima Energy are in the nine principal areas described
below.
The estimates of reserves and future net revenue for individual
properties may not reflect the same confidence level as estimates of reserves
and future net revenue for all properties, due to the effects of aggregation.
Weyburn Unit, Saskatchewan
Effective December 31, 2002, Ventures Trust acquired from the
Partnership an 11.7136% net royalty interest in the Weyburn Unit located in
southeastern Saskatchewan pursuant to the Partnership Redemption. See "General
Development of the Business - Development - 2002 - Weyburn Limited Partnership
Capital Contribution and Redemption". The Weyburn Unit was formed in 1963 and
produces medium gravity crude oil from the Midale formation. EnCana Corporation
operates the Weyburn Unit and markets Ventures Trust's share of production.
The Weyburn Unit is one of Canada's largest oil pools and contained 1.4
billion barrels of oil when discovered in the 1950's. The Weyburn Unit has been
under waterflood since 1964 and has been continuously developed through a
horizontal infill drilling program that was initiated in 1991. A carbon dioxide
miscible flood project aimed at significantly increasing the ultimate recovery
of original oil reserves in place from the Weyburn Unit was implemented late in
2000. The majority of the future development costs of the Trust are attributable
to the Weyburn NRI.
Spirit River, Alberta
The Spirit River property is located in the Peace River Arch area of
northwest Alberta. As of December 31, 2003, production from the property, net to
Ultima Energy, was approximately 930 boe/d consisting of 425 bbls/d of light oil
and natural gas liquids and 3.1 mmcf/d of natural gas. Production is primarily
from the medium depth Charlie Lake and Gething zones. The Trust holds interests
in 32 gross (24 net) producing oil and natural gas wells for an average 75%
working interest in the lands and facilities in the area, excluding penalty
wells. The Trust, through Ventures, is the operator of the majority of its
production in the area. Plans for 2004 include expanding the Charlie Lake E and
M Unit waterflood and drilling up to 12 development wells targeting the Charlie
Lake formation.
Cherhill, Alberta
As at December 31, 2003, Ventures Trust owned an average 90% working
interest in 39 gross (35 net) operated light oil and natural gas wells and
associated oil treating and natural gas processing facilities
C-21
in the Cherhill area of central Alberta. The primary Cherhill asset consists of
the Banff A Pool, which is a carbonate reef complex occurring at a depth of
approximately 1,500 meters. This pool produces light oil and associated solution
natural gas. Other natural gas production comes from three non-associated
natural gas wells. The property was acquired in two stages. The first
acquisition of an approximate 50% working interest was completed in the fall of
2002 and the second acquisition for the operatorship and the balance of the
working interest was acquired as part of the Calcrude Acquisition.
The light crude oil is shipped via the Pembina pipeline system and sold
under a 30-day contract. The natural gas production is sold to aggregators and
into the spot market.
Plans for 2004 include installing high volume lift pumps on producing
oil wells and drilling up to four development oil wells.
Westerose, Alberta
As at December 31, 2003, Ventures Trust owned an average 85% working
interest in 39 gross (33 net) operated producing light oil and natural gas wells
in the Westerose area of central Alberta. The property was acquired from Baytex
Energy Ltd. in December 2001. Ventures Trust's production comes from the Belly
River and Banff formations at depths of between 950 and 1,500 meters. The
Westerose Belly River field was initially developed with vertical wells and
subsequently developed with horizontal production and water injection wells
commencing in 1997. The field has been under waterflood since 1997 and has shown
significant positive response to the pressure maintenance scheme.
The field is equipped with a pipeline gathering system that delivers
the produced hydrocarbons to a Ventures Trust-owned central battery facility
where the light oil is separated from the associated natural gas and pipelined
to the Pembina Pipeline system. Conserved solution gas is gathered, compressed,
dehydrated and processed through Ventures Trust-owned facilities and delivered
to the TransCanada Pipelines system for sale on the spot market.
Ventures Trust also holds a 14.3% interest in the Westerose Banff B
Unit. The unit was formed in 2001 and produces medium quality oil from the Banff
formation. The Unit is equipped with a pipeline gathering system that delivers
the produced hydrocarbons to a Ventures Trust-owned central battery facility
where the oil is separated from the associated natural gas and pipelined to the
Pembina Pipeline system. Conserved solution gas is injected into the Banff
formation under an enhanced recovery scheme that was implemented in early 2001.
Plans for 2004 include a two well development drilling program
targeting the Belly River formation, continued production optimization efforts
and enhancement of the waterflood scheme.
Provost, Alberta
As at December 31, 2003, Ventures Trust owned an average 93% working
interest in 79 gross (73 net) operated producing light oil wells in the Provost
area of east central Alberta. The Provost assets consist of two adjacent
unitized light oil pools producing from the Viking Sandstone formation at a
depth of approximately 900 metres. These assets are developed on 80-acre and
40-acre well spacing and have been under partial waterflood since the mid-1980s.
The field is equipped with a pipeline gathering system that delivers
the produced hydrocarbons to two Ventures Trust-owned central battery facilities
where the light oil is separated from the associated natural gas and trucked to
the Ventures Trust's Kerrobert central battery for connection to the Mid-Sask
Pipeline system. Conserved natural gas is compressed and processed at a nearby
third party gas plant and marketed under an aggregator contract.
C-22
Kerrobert, Saskatchewan
As at December 31, 2003, Ventures Trust owned an average 84% working
interest in 558 gross (467 net) operated producing Viking light oil wells in the
Kerrobert area of west central Saskatchewan. The Kerrobert area assets consist
of two adjacent unitized light oil pools producing from the Viking Sandstone
formation at a depth of approximately 900 metres. The Kerrobert field was
initially developed by wells drilled on 40-acre spacing units. Commencing in the
fall of 1992, this field was infill drilled on 20-acre spacing units. The field
is equipped with a pipeline gathering system that delivers the produced
hydrocarbons to three central battery facilities where the light oil is
separated from the associated natural gas and pipelined to the Mid-Sask Pipeline
system. Production from a limited number of wells is trucked to the batteries.
Conserved solution gas is gathered, compressed and dehydrated through the
Altagas gathering system and delivered to the Transgas Coleville Gas Plant for
processing. Residue gas is sold to the spot market.
Glenevis, Alberta
As at December 31, 2003, Ventures Trust owned a 91% working interest in
22 gross (20 net) operated producing oil and natural gas wells in the Glenevis
area of central Alberta. The property was acquired from Baytex Energy Ltd. in
December 2001 and further minor purchases occurred in 2002 and 2003. Ventures
Trust's production comes from the medium depth Banff formation. The Glenevis
Banff Pool was discovered in 1951 and was initially developed with vertical
wells. In 1992, a horizontal infill drilling program was successfully
implemented. A subsequent 1998 program yielded similar positive results.
The field is equipped with a pipeline gathering system that delivers
the produced hydrocarbons to a Ventures Trust-owned central battery facility
where the oil is separated from the associated natural gas and trucked to the
Westerose facility.
North Eureka, Saskatchewan
As at December 31, 2003, Ventures Trust owned an average 99% working
interest in 82 gross (81 net) operated producing Viking light oil wells in the
North Eureka area of west central Saskatchewan. Ventures Trust's interests
include a 99% interest in the North Eureka Unit that has been under waterflood
since 1966. The North Eureka field was initially developed by wells drilled on
40-acre spacing units. Some 20-acre infill wells have subsequently been drilled
on this property.
The field is equipped with a pipeline gathering system that delivers
the produced hydrocarbons to a Ventures Trust-owned central battery facility
where the light oil is separated from the associated natural gas and pipelined
to the Mid-Sask Pipeline system. Production from a limited number of wells is
trucked to the battery. Natural gas is utilized to fire electrical generators
that in turn provide power to the property's wells and central production
facility.
Cyn-Pem, Alberta
As at December 31, 2003, Ventures Trust owned an average 24% working
interest in 17 gross (4 net) non-operated light oil and natural gas wells in the
Cyn-Pem area of west central Alberta. Ventures Trust also owns a 0.773% working
interest in the Carrot Creek Cardium F Unit Pool No. 3. The major producing
horizons are the Rock Creek, Viking, Ostracod and Cardium formations, which
occur at depths ranging from 1,950 metres to 2,500 metres.
Natural gas production is processed at third party facilities and sold
into the spot market. Crude oil production is also treated at a third party
facility, shipped on the Pembina pipeline system and sold under 30 day
contracts.
C-23
Production
Average Daily Production Volumes
The average daily production volumes for the Trust for 2003 are set out
below:
----------------------------------------------------------------------------------------------------------------------
Annual
1st Quarter 2nd Quarter 3rd Quarter 4th Quarter Average
----------------------------------------------------------------------------------------------------------------------
Light and Medium Crude Oil (bbls/d) 5,848 6,654 6,957 7,233 6,678
Natural Gas (mcf/d) 4,976 4,708 12,887 15,200 9,480
NGLs (bbls/d) 199 167 417 447 309
Light and Medium Crude Oil ($/bbl)
Price 39.61 33.97 34.79 33.16 35.14
Royalties 7.85 6.71 6.50 5.69 6.60
Production Costs 9.30 8.12 9.04 8.36 8.68
Netback 22.46 19.14 19.25 19.11 19.86
Natural Gas ($/mcf)
Price 7.36 6.81 5.96 6.09 6.30
Royalties 1.55 1.56 1.39 1.60 1.51
Production Costs 0.87 1.10 0.72 0.92 0.86
Netback 4.94 4.16 3.85 3.57 3.93
Natural Gas Liquids ($/bbl)
Price 34.36 25.79 31.78 27.58 29.84
Royalties 2.28 6.47 1.77 9.24 5.22
Production Costs 5.48 5.27 3.86 3.52 4.26
Netback 31.16 14.05 26.15 14.82 20.36
----------------------------------------------------------------------------------------------------------------------
Selected Reserve Information
The following tables set forth certain information relating to the oil
and natural gas reserves of the Trust and the present value of the estimated
future net cash flow associated with such reserves as at January 1, 2004. The
information set forth below is derived from the McDaniel Report and the GLJ
Report which have been combined by McDaniel for the Trust and have been prepared
in accordance with the standards contained in the COGE Handbook and the reserves
definitions contained in NI 51-101 and the COGE Handbook.
Prior to 2004, reserve reports were prepared in accordance with
National Policy Statement 2-B ("NP-2B"). Reserve reports for the year ended
December 31, 2003 are required to be prepared in accordance with NI 51-101. In
accordance with the requirements of NI 51-101, the Report on Reserves Data by
Independent Qualified Reserves Evaluator in Form 51-101F2 and the Report of
Management and Directors on Oil and Gas Disclosure in Form 51-101F3 are attached
as Appendices A and B hereto, respectively.
All evaluations of future net revenue are stated prior to any provision
for income taxes, interest costs or general and administrative costs and after
the deduction of estimated future capital expenditures for wells to which
reserves have been assigned. It should not be assumed that the estimated future
net revenue shown below is representative of the fair market value of the
Properties and the Weyburn NRI. There is no assurance that such price and cost
assumptions will be attained and variances could be material. The recovery and
reserve estimates of crude oil, natural gas liquids and natural gas reserves
provided herein are estimates only and there is no guarantee that the estimated
reserves will be recovered. Actual crude oil, natural gas liquids and natural
gas reserves may be greater than or less than the estimates provided herein.
C-24
SUMMARY OF OIL AND GAS RESERVES
AND NET PRESENT VALUES OF FUTURE NET REVENUE
as of January 1, 2004
CONSTANT PRICES AND COSTS
------------------------------------------------------------------------------------------------------------------------------------
RESERVES
------------------------------------------------------------------------------------------------------------------------------------
LIGHT AND HEAVY NATURAL NATURAL GAS
MEDIUM OIL OIL GAS LIQUIDS
-----------------------------------------------------------------------------------------------------
Gross Net Gross Net Gross Net Gross Net
RESERVES CATEGORY (Mbbl) (Mbbl) (Mbbl) (Mbbl) (MMcf) (MMcf) (Mbbl) (Mbbl)
------------------------------------------------------------------------------------------------------------------------------------
PROVED
Developed Producing 18,814 16,331 0 0 21,862 17,169 770 584
Developed Non-Producing 65 60 0 0 5,418 4,214 114 84
Undeveloped 6,525 5,730 0 0 1,123 807 30 23
TOTAL PROVED 25,404 22,121 0 0 28,403 22,190 914 690
------------------------------------------------------------------------------------------------------------------------------------
8,259 7,037 0 0 10,285 7,851 709 598
PROBABLE
------------------------------------------------------------------------------------------------------------------------------------
33,662 29,157 0 0 38,687 30,041 1,623 1,288
TOTAL PROVED PLUS PROBABLE
------------------------------------------------------------------------------------------------------------------------------------
------------------------------------------------------------------------------------------------------------------------------------
NET PRESENT VALUES OF FUTURE NET REVENUE
------------------------------------------------------------------------------------------------------------------------------------
BEFORE INCOME TAXES DISCOUNTED AT (%/year)(1)
------------------------------------------------------------------------------------------------------------------------------------
RESERVES CATEGORY 0 5 10 15 20
(MM$) (MM$) (MM$) (MM$) (MM$)
------------------------------------------------------------------------------------------------------------------------------------
PROVED
Developed Producing 381.1 300.7 250.0 215.5 190.4
Developed Non-Producing 22.1 12.4 8.2 5.9 4.6
Undeveloped 116.5 81.6 59.7 45.2 34.9
TOTAL PROVED 519.8 394.6 317.9 266.6 230.1
------------------------------------------------------------------------------------------------------------------------------------
228.9 144.2 99.8 73.6 56.8
PROBABLE
------------------------------------------------------------------------------------------------------------------------------------
748.7 538.8 417.7 340.3 286.9
TOTAL PROVED PLUS PROBABLE
------------------------------------------------------------------------------------------------------------------------------------
TOTAL FUTURE NET REVENUE
(UNDISCOUNTED)
as of January 1, 2004
CONSTANT PRICES AND COSTS
------------------------------------------------------------------------------------------------------------------------------------
FUTURE
NET
REVENUE
WELL BEFORE
OPERATING DEVELOPMENT ABANDONMENT INCOME
RESERVES REVENUE ROYALTIES COSTS COSTS COSTS TAXES
CATEGORY (M$) (M$) (M$) (M$) (M$) (M$) (1)
--------------------- ------------------ ----------------- ------------------ ------------------ ------------------- ------------
Proved Reserves 1,090,289 182,639 283,522 90,545 13,807 519,777
--------------------- ------------------ ------------------ ------------------- ------------------- ------------------- ------------
Proved Plus 1,479,168 251,581 354,084 110,942 13,881 748,680
Probable Reserves
------------------------------------------------------------------------------------------------------------------------------------
C-25
FUTURE NET REVENUE
BY PRODUCTION GROUP
as of January 1, 2004
CONSTANT PRICES AND COSTS
------------------------------------------------------------------------------------------------------------------------------------
FUTURE NET REVENUE BEFORE
RESERVES INCOME TAXES (discounted at 10%/year)(1)
CATEGORY PRODUCTION GROUP (M$)
------------------------------------------------------------------------------------------------------------------------------------
Proved Reserves Light and Medium Crude Oil (including solution gas and other
by-products) 234,691
Heavy Oil (including solution gas and other by-products) 0
Natural Gas (including by-products) 83,311
------------------------------------------------------------------------------------------------------------------------------------
Proved Plus Probable Reserves Light and Medium Crude Oil (including solution gas and other
by-products) 313,374
Heavy Oil (including solution gas and other by-products) 0
Natural Gas (including by-products) 104,399
------------------------------------------------------------------------------------------------------------------------------------
SUMMARY OF OIL AND GAS RESERVES
AND NET PRESENT VALUES OF FUTURE NET REVENUE
as of January 1, 2004
FORECAST PRICES AND COSTS
------------------------------------------------------------------------------------------------------------------------------------
RESERVES
------------------------------------------------------------------------------------------------------------------------------------
LIGHT AND HEAVY NATURAL NATURAL GAS
MEDIUM OIL OIL GAS LIQUIDS
------------------------------------------------------------------------------------------------------------------------------------
RESERVES CATEGORY Gross Net Gross Net Gross Net Gross Net
(Mbbl) (Mbbl) (Mbbl) (Mbbl) (MMcf) (MMcf) (Mbbl) (Mbbl)
------------------------------------------------------------------------------------------------------------------------------------
PROVED
Developed Producing 18,525 16,095 0 0 21,674 16,991 762 577
Developed Non-Producing 65 60 0 0 5,423 4,216 114 84
Undeveloped 6,524 5,858 0 0 1,123 807 30 23
TOTAL PROVED 25,115 22,013 0 0 28,220 22,014 907 684
------------------------------------------------------------------------------------------------------------------------------------
PROBABLE 8,232 7,058 0 0 10,269 7,836 709 599
------------------------------------------------------------------------------------------------------------------------------------
TOTAL PROVED PLUS PROBABLE 33,347 29,071 0 0 38,489 29,850 1616 1283
------------------------------------------------------------------------------------------------------------------------------------
------------------------------------------------------------------------------------------------------------------------------------
NET PRESENT VALUES OF FUTURE NET REVENUE
------------------------------------------------------------------------------------------------------------------------------------
BEFORE INCOME TAXES DISCOUNTED AT (%/year)(1)
------------------------------------------------------------------------------------------------------------------------------------
RESERVES CATEGORY 0 5 10 15 20
(MM$) (MM$) (MM$) (MM$) (MM$)
------------------------------------------------------------------------------------------------------------------------------------
PROVED
Developed Producing 255.9 208.3 177.6 156.3 140.5
Developed Non-Producing 18.0 9.7 6.2 4.4 3.4
Undeveloped 81.8 55.4 39.0 28.3 20.9
TOTAL PROVED 355.7 273.4 222.9 189.0 164.8
------------------------------------------------------------------------------------------------------------------------------------
PROBABLE 180.0 113.3 78.2 57.6 44.4
------------------------------------------------------------------------------------------------------------------------------------
TOTAL PROVED PLUS PROBABLE 535.7 386.7 301.1 246.6 209.2
------------------------------------------------------------------------------------------------------------------------------------
C-26
TOTAL FUTURE NET REVENUE
(UNDISCOUNTED)
as of January 1, 2004
FORECAST PRICES AND COSTS
------------------------------------------------------------------------------------------------------------------------------------
FUTURE
NET
REVENUE
WELL BEFORE
OPERATING DEVELOPMENT ABANDONMENT INCOME
RESERVES REVENUE ROYALTIES COSTS COSTS COSTS TAXES
CATEGORY (M$) (M$) (M$) (M$) (M$) (M$) (1)
--------------------- ------------------ ----------------- ------------------ ------------------ ------------------- ------------
Proved Reserves 939,975 151,314 319,508 95,615 17,850 355,689
------------------------------------------------------------------------------------------------------------------------------------
Proved Plus 1,293,668 210,791 410,385 118,516 18,352 535,624
Probable Reserves
------------------------------------------------------------------------------------------------------------------------------------
FUTURE NET REVENUE
BY PRODUCTION GROUP
as of January 1, 2004
FORECAST PRICES AND COSTS
------------------------------------------------------------------------------------------------------------------------------------
RESERVES PRODUCTION GROUP FUTURE NET REVENUE BEFORE
CATEGORY INCOME TAXES (discounted at 10%/year)(1)
(M$)
------------------------------------------------------------------------------------------------------------------------------------
Proved Reserves Light and Medium Crude Oil (including solution gas and other
by-products) 153,445
Heavy Oil (including solution gas and other by-products) 0
Natural Gas (including by-products) 69,469
------------------------------------------------------------------------------------------------------------------------------------
Proved Plus Probable Reserves Light and Medium Crude Oil (including solution gas and other
by-products) 214,466
Heavy Oil (including solution gas and other by-products) 0
Natural Gas (including by-products) 86,643
------------------------------------------------------------------------------------------------------------------------------------
Notes:
(1) The Trust is entitled to deduct from its income all amounts which
are paid or payable by it to Unitholders in a given financial
year. As a result of amounts paid to Unitholders in the course of
the most recent financial year, the Trust is not liable for any
material amount of income tax on income. The net present values
of future net revenue after income taxes are, therefore, the same
as the net present values of future net revenue before income
taxes.
(2) "Gross Reserves" means the working interest owner's share of
gross reserves before the deduction of royalties. Royalty
interest share of reserves is not included in this category. The
Weyburn NRI is treated as a working interest as the Trust is
responsible for its share of capital costs, operating costs,
royalties and abandonment costs.
(3) "Net Reserves" means the working interest owner's share of gross
reserves after the deduction of royalties. Royalty interest share
of reserves is included in this category.
(4) The net cumulative cash flow forecasts are after direct lifting
costs, freehold royalties, Crown mineral taxes and future
investments but before income taxes An allowance for future well
abandonment costs for all Working Interest wells was included,
however, no allowance was made for the abandonment of any
facilities.
(5) "Royalties" refers to royalties paid to others. The royalties
deducted from the reserves are based on the percentage royalty
calculated by applying the applicable royalty rate or formula. In
the case of Crown sliding scale royalties which are dependent on
selling prices, the price forecasts for the individual properties
in question have been employed.
(6) "Reserves" are the estimated remaining quantities of oil and
natural gas and related substances anticipated to be recoverable
from known accumulations, from a given date forward, based on:
analysis of drilling, geological, geophysical and engineering
data; the use of established technology; and specified economic
conditions, which are generally accepted as being reasonable.
Reserves are classified according to the degree of certainty
associated with the estimates.
C-27
(7) "Proved Reserves" are those Reserves that can be estimated with a
high degree of certainty to be recoverable. It is likely that the
actual remaining quantities recovered will exceed the estimated
Proved Reserves. At least a 90% probability that the quantities
actually recovered will equal or exceed the estimated Proved
Reserves is the targeted level of certainty.
(8) "Probable Reserves" are those additional Reserves that are less
certain to be recovered than Proved Reserves. It is equally
likely that the actual remaining quantities recovered will be
greater or less than the sum of the estimated Proved plus
Probable Reserves. At least a 50% probability that the quantities
actually recovered will equal or exceed the sum of the estimated
Proved plus Probable Reserves is the targeted level of certainty.
(9) "Proved Developed Reserves" are those Reserves that are expected
to be recovered from existing wells and installed facilities or,
if facilities have not been installed, that would involve a low
expenditure (e.g., when compared to the cost of drilling a well)
to put the Reserves on production. The developed category may be
subdivided into producing and non-producing.
(10) "Developed Producing Reserves" are those Reserves that are
expected to be recovered from completion intervals open at the
time of the estimate. These Reserves may be currently producing
or, if shut-in, they must have previously been on production, and
the date of resumption of production must be known with
reasonable certainty.
(11) "Developed Non-Producing Reserves" are those Reserves that either
have not been on production, or have previously been on
production, but are shut-in, and the date of resumption of
production is unknown.
(12) "Undeveloped Reserves" are those Reserves expected to be
recovered from known accumulations where a significant
expenditure (e.g., when compared to the cost of drilling a well)
is required to render them capable of production. They must fully
meet the requirements of the Reserves classification (proved,
probable, possible) to which they are assigned.
(13) The pricing assumptions used in the McDaniel Report and the GLJ
Report with respect to net cumulative cash flow as well as the
inflation rates used for operating costs are set forth below.
SUMMARY OF PRICING ASSUMPTIONS
as of January 1, 2004
CONSTANT PRICES AND COSTS
------------------------------------------------------------------------------------------------------------------------------------
OIL
------------------------------------------------------------------------------------------------------------------------------------
Alberta NATURAL
Edmonton Par Average GAS LIQUIDS
WTI Cushing Price Hardisty Heavy Cromer Medium Plantgate FOB EXCHANGE
Oklahoma 400 API 120 API 29.30 API Price Field Gate RATE
Year ($US/bbl) ($Cdn/bbl) ($Cdn/bbl) ($Cdn/bbl) ($Cdn/Mmbtu) ($Cdn/bbl) ($US/Cdn)
------------------------------------------------------------------------------------------------------------------------------------
2003 (Year End) 32.78 39.76 22.75 34.25 5.87 31.50 .7738
------------------------------------------------------------------------------------------------------------------------------------
SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS
as of January 1, 2004
FORECAST PRICES AND COSTS
------------------------------------------------------------------------------------------------------------------------------------
OIL
------------------------------------------------------------------------------------------------------------------------------------
Alberta NATURAL
Cromer Average GAS LIQUIDS
WTI Cushing Edmonton Par Hardisty Heavy Medium Plantgate FOB INFLATION EXCHANGE
Oklahoma Price 40o API 12o API 29.3o API Price Field Gate RATE RATE
Year ($US/bbl) ($Cdn/bbl) ($Cdn/bbl) ($Cdn/bbl) ($Cdn/Mmbtu) ($Cdn/bbl) (%/Year) ($US/Cdn)
------------------------------------------------------------------------------------------------------------------------------------
Historical
------------------------------------------------------------------------------------------------------------------------------------
2000 30.31 44.72 27.80 40.10 5.20 35.70 2.7 .674
------------------------------------------------------------------------------------------------------------------------------------
2001 25.97 39.60 18.05 32.22 5.25 31.60 2.6 .646
------------------------------------------------------------------------------------------------------------------------------------
2002 26.10 39.95 27.60 34.93 3.89 26.20 2.2 .637
------------------------------------------------------------------------------------------------------------------------------------
2003 30.95 43.10 27.45 36.90 6.35 33.80 2.0 .715
------------------------------------------------------------------------------------------------------------------------------------
Forecast
------------------------------------------------------------------------------------------------------------------------------------
2004 29.00 37.70 22.70 32.20 5.65 27.90 2.0 .750
------------------------------------------------------------------------------------------------------------------------------------
2005 26.50 34.30 21.55 29.71 5.30 25.50 2.0 .750
------------------------------------------------------------------------------------------------------------------------------------
2006 25.50 33.00 21.56 28.84 4.95 24.50 2.0 .750
------------------------------------------------------------------------------------------------------------------------------------
2007 25.00 32.30 20.63 28.06 4.75 23.80 2.0 .750
------------------------------------------------------------------------------------------------------------------------------------
2008 25.00 32.30 20.39 27.97 4.60 23.70 2.0 .750
------------------------------------------------------------------------------------------------------------------------------------
2009 25.50 32.90 20.76 28.48 4.65 24.10 2.0 .750
------------------------------------------------------------------------------------------------------------------------------------
2010 26.00 33.50 21.11 29.00 4.65 24.50 2.0 .750
------------------------------------------------------------------------------------------------------------------------------------
2011 26.50 34.20 21.56 29.61 4.75 25.00 2.0 .750
------------------------------------------------------------------------------------------------------------------------------------
C-28
SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS
as of January 1, 2004
FORECAST PRICES AND COSTS
------------------------------------------------------------------------------------------------------------------------------------
OIL
------------------------------------------------------------------------------------------------------------------------------------
Alberta NATURAL
Cromer Average GAS LIQUIDS
WTI Cushing Edmonton Par Hardisty Heavy Medium Plantgate FOB INFLATION EXCHANGE
Oklahoma Price 40o API 12o API 29.3o API Price Field Gate RATE RATE
Year ($US/bbl) ($Cdn/bbl) ($Cdn/bbl) ($Cdn/bbl) ($Cdn/Mmbtu) ($Cdn/bbl) (%/Year) ($US/Cdn)
------------------------------------------------------------------------------------------------------------------------------------
------------------------------------------------------------------------------------------------------------------------------------
2012 27.00 34.80 21.91 30.11 4.85 25.40 2.0 .750
------------------------------------------------------------------------------------------------------------------------------------
2013 27.50 35.50 22.35 30.72 4.95 26.00 2.0 .750
------------------------------------------------------------------------------------------------------------------------------------
2014 28.10 36.20 22.79 31.32 5.05 26.50 2.0 .750
------------------------------------------------------------------------------------------------------------------------------------
Thereafter +2.0% +2.0% +2.0% +2.0% +2.0% +2.0% 2.0 .750
------------------------------------------------------------------------------------------------------------------------------------
(14) Total burdens include crown, freehold and overriding royalties as
well as mineral taxes.
(15) Ventures Trust's interest in the Weyburn Unit, as reflected in
the GLJ Report, is a royalty interest, the share of which is
determined on a net profit basis. Gross reserve values presented
herein are the share of reserves prior to deduction of lessor
royalties, while the net share is their entitled value after
lessor royalty burdens.
RECONCILIATION OF
NET RESERVES
BY PRINCIPAL PRODUCT TYPE
FORECAST PRICES AND COSTS
------------------------------------------------------------------------------------------------------------------------------------
ASSOCIATED AND
LIGHT AND MEDIUM OIL HEAVY OIL NON-ASSOCIATED GAS
------------------------------------------------------------------------------------------------------------------------------------
Net
Net Proved Proved
Net Net Proved Net Net Plus Net Net Plus
Net Proved Probable Plus Probable Proved Probable Probable Proved Probable Probable
FACTORS (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mmcf) (Mmcf) (Mmcf)
------------------------------------------------------------------------------------------------------------------------------------
January 1, 2003(a) 20,148 5,113 25,261 0 0 0 9,836 1,317 11,153
Extensions(b) 606 449 1,055 0 0 0 1,052 1,296 2,348
Improved Recovery 809 0 809 0 0 0 0 0 0
Technical Revisions 1,036 1,006 2,042 0 0 0 -2,520 2,561 41
Discoveries 0 0 0 0 0 0 0 0 0
Acquisitions 1,895 366 2,261 0 0 0 16,624 2,660 19,284
Dispositions -140 -54 -194 0 0 0 -62 -30 -92
Economic Factors -328 179 -149 0 0 0 -145 32 -113
Production -2,013 0 -2,013 0 0 0 -2,771 0 -2,771
January 1, 2004 22,013 7,058 29,071 0 0 0 22,014 7,836 29,850
------------------------------------------------------------------------------------------------------------------------------------
Notes:
(a) The evaluation of reserves as at January 1, 2003 was prepared
using National Policy Statement 2-B reserves definitions. Under
those definitions, probable reserves were adjusted by a factor to
account for the risk associated with their recovery. The Trust
previously applied a risk factor of 50% in reporting probable
reserves. Under current NI 51-101 reserves definitions, estimates
are prepared such that the full proved plus probable reserves are
estimated to be recoverable (proved plus probable reserves are
effectively a "best estimate"). The above reconciliation reflects
current probable reserves versus previous risk adjusted (50%)
probable reserves reported by the Trust.
(b) Consists entirely of infill drilling additions in 2003.
C-29
RECONCILIATION OF CHANGES IN
NET PRESENT VALUES OF FUTURE NET REVENUE
DISCOUNTED AT 10% PER YEAR
PROVED RESERVES
CONSTANT PRICES AND COSTS
-------------------------------------------------------------------------------------------------------------------------
PERIOD AND FACTOR 2003
(M$)
-------------------------------------------------------------------------------------------------------------------------
Estimated Net Present Value at Beginning of Year 293,548
Oil and Gas Sales During the Period Net of Production Costs and Royalties(a) -70,410
Changes due to Prices and Royalties Related to Forecast Production(b) -3,993
Development Costs During the Period(c) 33,100
Changes in Forecast Development Costs(d) -39,410
Changes Resulting from Extensions and Improved Recovery(e) 17,111
Changes Resulting from Discoveries(e) 0
Changes Resulting from Acquisitions of Reserves(e) 68,073
Changes Resulting From Dispositions of Reserves(f) -2,490
Accretion of Discount(g) 29,355
Net Change in Income Taxes(h) 0
Changes Resulting from Technical Reserves Revisions 5,971
All Other Changes(i) -12,855
Estimated Net Present Value as at End of Year 318,000
-------------------------------------------------------------------------------------------------------------------------
Notes:
(a) Company actual before income taxes, excluding G&A.
(b) The impact of changes in prices and other economic factors on future
net revenue.
(c) Actual capital expenditures relating to the exploration, development
and production of oil and gas reserves.
(d) The change in forecast development costs.
(e) End of period net present value of the related reserves.
(f) Start of the period net present value of the related reserves adjusted
to the effective date of the disposition.
(g) Estimated as 10% of the beginning of period net present value. (h) The
Trust should not be liable for any material amount of income tax on
income. (i) Includes changes due to revised production profiles,
development timing, operating costs, royalty rates,
actual price received in 2003 versus forecast, etc.
Additional Information Relating to Reserves Data
Undeveloped Reserves
The following table summarizes the volumes of net proved undeveloped
reserves that were first attributed in each of the most recent five financial
years and, in the aggregate, before that time based on forecast prices and
costs:
-----------------------------------------------------------------------------------------------------------------------
PRODUCT 2003 2002 2001 2000 1999 Pre-1999
-----------------------------------------------------------------------------------------------------------------------
Light and Medium Crude Oil (mbbls) 5,858 5,439 1,211 0 1,139 2,479
Heavy Oil (mbbls) 0 0 0 0 0 0
Natural Gas (mmcf) 807 15 51 0 3,091 4,698
Natural Gas Liquids (mbbls) 23 0 1 0 111 0
-----------------------------------------------------------------------------------------------------------------------
Total (mboe) 6,016 5441 1,221 0 1,765 3,458
-----------------------------------------------------------------------------------------------------------------------
The following table summarizes the volumes of net probable undeveloped
reserves that were first attributed in each of the most recent five financial
years and, in the aggregate, before that time based on forecast prices and
costs:
-----------------------------------------------------------------------------------------------------------------------
PRODUCT 2003 2002 2001 2000 1999 Pre-1999
-----------------------------------------------------------------------------------------------------------------------
Light and Medium Crude Oil (mbbls) 2,901 2,589 120 0 0 0
Heavy Oil (mbbls) 0 0 0 0 0 0
Natural Gas (mmcf) 978 11 23 0 0 0
Natural Gas Liquids (mbbls) 419 204 0 0 0 0
-----------------------------------------------------------------------------------------------------------------------
Total (mboe) 3,483 2,795 124 0 0 0
-----------------------------------------------------------------------------------------------------------------------
C-30
Undeveloped reserves are those reserves expected to be recovered from
known accumulations where a significant expenditure is required to render them
capable of production.
Significant Factors or Uncertainties
For details of significant economic factors or uncertainties affecting
the reserves data of the Trust, see "Competitive Conditions and Risk Factors"
and "Management's Discussion and Analysis".
Future Development Costs
The following table outlines development costs deducted in the
estimation of future net revenue calculated using no discount and a 10% discount
rate.
-----------------------------------------------------------------------------------------------------------------------
2004 2005 2006 2007 2008-2010
(MM$) (MM$) (MM$) (MM$) (MM$)
--------------------------------------------------------------------------------------
RESERVE CATEGORY 0% 10% 0% 10% 0% 10% 0% 10% 0% 10%
-----------------------------------------------------------------------------------------------------------------------
Proved Reserves 27.2 25.9 16.2 14 11.5 9.1 10.6 7.6 16.5 9.9
(Constant Prices and Costs)
Proved Reserves
(Forecast Prices and Costs) 27.4 25.9 16.5 14.3 12.0 9.5 11.2 8.1 18.1 10.8
-----------------------------------------------------------------------------------------------------------------------
Proved & Probable Reserves: 28.6 27.3 18.9 16.4 13.1 10.4 12.5 9.0 24.7 15.0
(Forecast Prices and Costs)
-----------------------------------------------------------------------------------------------------------------------
The Trust's future oil and natural gas reserves and production, and
therefore its cash flows, will be highly dependent upon Ventures Trust's and
Ultima Energy's success in exploiting their reserve bases and acquiring
additional reserves. Without reserve additions through acquisition or
development activities, the Trust's reserves and production will decline over
time as reserves are produced.
To the extent that external sources of capital, including the issuance
of additional Trust Units, become limited or unavailable, the Trust'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 the Trust is required to use
cash flow to finance capital expenditures or property acquisitions, the level of
Distributable Income will be reduced, all other factors remaining equal. See
"Competitive Conditions and Risk Factors".
Other Oil And Gas Information
Oil and Gas Properties and Wells
As at December 31, 2003, the Trust had an interest in 2,047 gross
(1,561 net) producing and non-producing oil and natural gas wells as follows:
----------------------------------------------------------------------------------------------------------------------
PRODUCING NON-PRODUCING(3)
----------------------------------------------------------------------------------------------------------------------
Gross(1)(4) Net (2)(4) Gross(1)(4) Net(2)(4)
------------------- ------------------- -------------------- -------------------
CRUDE OIL WELLS
Alberta 237 176 199 111
Saskatchewan 1,286 1,098 133 119
NATURAL GAS WELLS
Alberta 143 37 42 14
Saskatchewan 7 6 0 0
----------------------------------------------------------------------------------------------------------------------
TOTAL 1,673 1,317 374 244
----------------------------------------------------------------------------------------------------------------------
Notes:
(1) "Gross" wells means the number of wells in which the Trust has a working
interest or a royalty interest that may be convertible to a working
interest.
(2) "Net" wells means the aggregate number of wells obtained by multiplying
each gross well by the Trust's percentage working interest therein.
(3) "Non-producing" wells includes water injection wells, disposal wells,
service wells, standing wells and wells which are not producing but which
are considered to be capable of production.
(4) Excludes the Weyburn NRI wells.
C-31
Properties with No Attributed Reserves
The following table sets forth the gross and net acres of unproved
properties held by the Trust and the net area of unproved property for which the
Trust expects its rights to explore, develop and exploit to expire during the
next year:
---------------------------------------------------------------------------------------------------------------------
UNPROVED PROPERTIES
(acres)
---------------------------------------------------------------------------------------------------------------------
LOCATION Gross Net Net Area to Expire
---------------------------------------------------------------------------------------------------------------------
Alberta 70,897 25,147 522
Saskatchewan 13,948 10,123 0
Other 0 0 0
---------------------------------------------------------------------------------------------------------------------
TOTAL 84,845 35,270 522
---------------------------------------------------------------------------------------------------------------------
Forward Contracts
For information relating to forward contracts, see "Competitive
Conditions and Risk Factors - Volatility of Oil and Natural Gas Prices".
Abandonment & Reclamation Costs
Future abandonment and reclamation costs have been estimated based on
actual costs incurred to date by Ventures and Ultima Energy for abandonment and
reclamation activities. Costs to abandon approximately 1,561 net wells totaling
$16.2 million net of salvage value ($5.2 million discounted at 10%) are included
in the estimate of future net revenue. Only the abandonment costs associated
with wells were deducted in estimating the future net revenue in the McDaniel
and GLJ Reports. The additional liability associated with well reclamation costs
and facility/pipeline abandonment and reclamation costs, which were estimated to
be $6.7 million ($1.1 million discounted at 10%), were not deducted in
estimating future net revenue. Abandonment and reclamation costs estimated for
the next three years are $0.3 million in 2004, $0.2 million in 2005 and $0.4
million in 2006.
Tax Horizon
The Trust is entitled to deduct from its income all amounts which are
paid or payable by it to Unitholders in a given financial year. As a result of
amounts paid to Unitholders in respect of the most recent financial year, the
Trust is not liable for any material amount of income tax on income.
Costs Incurred
The following table outlines costs incurred during the financial year
ended December 31, 2003:
Acquisitions, Dispositions and Capital Expenditures
--------------------------------------------------------------------------------------------------------------------
NATURE OF COST AMOUNT
(MM$)
--------------------------------------------------------------------------------------------------------------------
Acquisition Costs(1)
Proved 87.4
Unproved 1.4
Exploration Costs 0
Development Costs (excluding the Weyburn NRI) 19.6
Development Costs -- Weyburn NRI 13.5
--------------------------------------------------------------------------------------------------------------------
Total 135.4
--------------------------------------------------------------------------------------------------------------------
C-32
Note:
(1) All acquisition costs other than land and seismic are included in proved
acquisition costs.
Exploration and Development Activities
The following table summarizes the results of exploration and
development activities during the financial year ended December 31, 2003,
excluding the Weyburn NRI.
-------------------------------------------------------------------------------------------------------------------
GROSS NET
-------------------------------------------------------------------------------------------------------------------
DEVELOPMENT WELLS 21 14.4
Gas 5 1.6
Oil 16 12.8
Service 0 0
Dry 0 0
-------------------------------------------------------------------------------------------------------------------
EXPLORATORY WELLS 0 0
Gas 0 0
Oil 0 0
Service 0 0
Dry 0 0
-------------------------------------------------------------------------------------------------------------------
TOTAL WELLS 21 14.4
-------------------------------------------------------------------------------------------------------------------
Production Estimates
The following table summarizes the annual volume of production
estimated on a proved plus probable basis for 2004 using constant and forecast
prices and costs.
---------------------------------------------------------------------------------------------------------------------
ESTIMATED PRODUCTION
---------------------------------------------------------------------------------------------------------------------
Constant Prices and Costs Forecast Prices and Costs
---------------------------------------------------------------------------------------------------------------------
Light and Medium Crude Oil (mbbls) 2,778 2,778
---------------------------------------------------------------------------------------------------------------------
Heavy Oil (mbbls) 0 0
---------------------------------------------------------------------------------------------------------------------
Natural Gas (mmcf) 4,991 4,991
---------------------------------------------------------------------------------------------------------------------
Natural Gas Liquids (mbbls) 166 166
---------------------------------------------------------------------------------------------------------------------
TRUST INDENTURE
An unlimited number of Trust Units have been created and may be issued
pursuant to the Trust Indenture. Each Trust Unit represents an equal fractional
undivided beneficial interest in the Trust Fund. All Trust Units outstanding
from time to time are entitled to share equally in any distributions by the
Trust and, in the event of termination of the Trust, in the net assets of the
Trust.
The following is a summary of certain provisions of the Trust
Indenture. For a complete description of such Trust Indenture, reference should
be made to the Trust Indenture, copies of which may be viewed at the offices of,
or obtained from, the Trustee.
Trustee
Computershare Trust Company of Canada is the trustee of the Trust and
also acts as the transfer agent for the Trust Units. The Trustee is responsible,
among other things for: (i) holding the Trust Fund in trust for the use and
benefit of the Unitholders; and (ii) maintaining all records of the Trust and
reporting to the Unitholders in accordance with the terms and conditions of the
Trust Indenture.
The Trustee may resign upon giving not less than 60 days' notice in
writing to Ventures, for and on behalf of Ventures Trust, and AcquireCo. The
Trustee may also be removed by special resolution of the Unitholders. Such
resignation or removal becomes effective upon the appointment of a successor
C-33
approved by an ordinary resolution passed at a meeting of Unitholders, and the
acceptance of such appointment by the successor trustee.
Nature of the Trust
The Trust is an open-end investment trust formed under the laws of the
Province of Alberta pursuant to the Trust Indenture for the purpose of acquiring
and holding all forms of petroleum and natural gas related assets including the
Royalty.
Distributions
The Trust Indenture provides that the Trustee will distribute
Distributable Income on the 15th day (or if such day is not a business day, the
next business day following the 15th day) following the last day of each
calendar month in each year.
Offerings
Pursuant to the Trust Indenture, the Trust may offer Trust Units,
including rights to acquire Trust Units at such time or times and on such terms
and conditions as Ventures, for and on behalf of Ventures Trust, or AcquireCo
may determine.
Meetings and Voting
Pursuant to the Trust Indenture, Unitholders are entitled to receive
notice of and to attend all meetings of the Unitholders. Pursuant to the
Ventures USA and the AcquireCo USA, Unitholders are entitled to elect the
directors of Ventures and AcquireCo, respectively. Only Unitholders of record
are entitled to vote and each Unitholder is entitled to one vote per Trust Unit
held with respect to all matters on which they are entitled to vote.
The Trust holds annual meetings of the Unitholders. Special meetings of
Unitholders may be called at any time by the Trustee and shall be called by the
Trustee upon the written request of Unitholders holding in aggregate not less
than 20% of the Trust Units then outstanding. Notice of all meetings of
Unitholders shall be given by unregistered mail to each Unitholder at his
registered address, mailed at least 21 days and not more than 50 days prior to
the meeting.
At any meeting of Unitholders, any holder of Trust Units entitled to
vote thereat may vote either in person or by proxy and a proxy holder need not
be a Unitholder. Two persons present in person or represented by proxy and
representing in the aggregate not less than 5% of the votes attaching to all
outstanding Trust Units constitute a quorum for the transaction of business at
any meeting of Unitholders.
A special resolution approved by not less than 66 2/3% of the votes of
Unitholders represented at a meeting is required to, among other things, amend
the Trust Indenture, remove the Trustee or terminate the Trust.
Limitation on Non-Resident Ownership
In order for the Trust to maintain its status as a mutual fund trust
under the Tax Act, the Trust must not be established or maintained primarily for
the benefit of non-residents of Canada ("non-residents") within the meaning of
the Tax Act. Accordingly, the Trust Indenture provides that at no time may
non-residents be the beneficial owners of a majority of the Trust Units. If the
Trustee becomes aware, as a result of requiring declarations as to beneficial
ownership or otherwise, that the beneficial owners of 49% of the Trust Units
then outstanding are or may be non-residents or that such a situation is
imminent, the Trustee may make a public announcement thereof and shall 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
C-34
declaration that the person is not a non-resident. If notwithstanding the
foregoing, the Trustee determines that a majority of the Trust Units are held by
non-residents, the Trustee may send a notice to non-resident holders of Trust
Units, 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 them to sell their Trust Units or a portion thereof within a specified
period of not less than 60 days. If the Unitholders receiving such notice have
not sold the specified number of Trust Units or provided the Trustee with
satisfactory evidence that they are not non-residents within such period, the
Trustee may on behalf of such Unitholders sell such Trust Units and, in the
interim, shall suspend the voting and distribution rights attached to such Trust
Units. Upon such sale, the affected holders shall cease to be holders of Trust
Units and their rights shall be limited to receiving the net proceeds of sale
upon surrender of the certificates representing such Trust Units.
Laws in certain jurisdictions outside Canada may also limit the
ownership of Trust Units by certain non-residents, and the Trustee may from time
to time take steps similar to the foregoing to minimize any adverse consequences
to non-resident Unitholders arising from such laws.
Redemption Rights
Each Unitholder is entitled to require the Trust to redeem at any time
and from time to time at the demand of the Unitholder all or any number of the
Trust Units registered in the name of the Unitholder. Upon receipt by the
Trustee, in its capacity as transfer agent of the Trust Units, of the notice to
redeem Trust Units, the Unitholder shall thereafter cease to have any rights
with respect to the Trust Units tendered for redemption (other than to receive
the redemption payment therefor) including the right to receive any
distributions thereon which are declared payable to the Unitholders of record on
a date which is subsequent to the date of receipt by the Trustee of such notice.
Trust Units shall be considered to be tendered for redemption on the date that
the Trustee has, to the satisfaction of the Trustee and the Manager, received
the notice, certificates representing the Trust Units and other required
documents or evidence as provided in the Trust Indenture.
Upon receipt by the Trustee of the notice to redeem Trust Units, the
holder of the Trust Units tendered for redemption shall be entitled to receive a
price per Trust Unit (hereinafter called the "Cash Redemption Price") equal to
the lesser of:
(a) 95% of the market price of the Trust Units on the principal
market on which the Trust Units are quoted for trading during the
ten trading day period commencing immediately after the date on
which the Trust Units were tendered for redemption; and
(b) the closing market price on the principal market on which the
Trust Units are quoted for trading, on the date that the Trust
Units were so tendered for redemption.
The aggregate Cash Redemption Price payable by the Trust in respect of
any Trust Units surrendered for redemption during any calendar month shall be
paid by cheque in lawful money of Canada payable at par to or to the order of
the Unitholder who exercised the right of redemption on the last day of the
month following the month in which the Trust Units were tendered for redemption.
The entitlement of Unitholders to receive the Cash Redemption Price is subject
to the limitations that: (i) the total amount payable by the Trust in respect of
such Trust Units and all other Trust Units tendered for redemption in the same
calendar month is not to exceed $100,000 (provided that such limitation may be
waived at the discretion of the boards of directors of Ventures and AcquireCo);
(ii) no payments of the Cash Redemption Price can be made unless, at the time
such Trust Units are tendered for redemption, the outstanding Trust Units of the
Trust are listed for trading on a stock exchange or traded or quoted on any
other market which the boards of directors of Ventures and AcquireCo consider,
in their discretion, provides representative fair market value prices for the
Trust Units; and (iii) the normal trading of Trust Units is not suspended or
halted on any stock exchange on which the Trust Units are listed (or, if not
C-35
listed on a stock exchange, on any market on which the Trust Units are quoted
for trading) on the date that the Trust Units are tendered for redemption or for
more than five trading days during the ten day trading period commencing
immediately after the date on which the Trust Units are tendered for redemption.
If a Unitholder is not entitled to receive the entire Cash Redemption
Price as a result of the foregoing limitations, then the Cash Redemption Price
for such Trust Units is to be the fair market value thereof as determined by the
boards of directors of Ventures and AcquireCo and, subject to any applicable
regulatory approvals, is to be paid and satisfied by way of a distribution in
specie of the Trust's interests in Ventures Trust and AcquireCo (the
"Securities"). No fractional Securities will be distributed and where a number
of Securities to be received by a Unitholder includes a fraction, such number
will be rounded to the next lowest whole number. The Trust is entitled to all
interest paid, or accrued and unpaid, and to all dividends paid or declared
payable on the Securities on or before the date of the distribution in specie.
It is anticipated that this redemption right will not be the primary
mechanism for Unitholders to dispose of their Trust Units. The Securities which
may be distributed in specie to Unitholders in connection with a retraction will
not be listed on any stock exchange and no market is expected to develop in the
Securities. The Securities may be subject to resale restrictions under
applicable securities laws. Securities so distributed may or may not be
qualified investments for trusts governed by registered retirement savings
plans, registered retirement income trusts and deferred profit sharing plans.
Canadian Federal Income Tax Considerations
A Unitholder who is resident in Canada for purposes of the Tax Act
(other than Exempt Plans) will generally be required to include in computing
income for a taxation year that part of the income of the Trust for tax
purposes, including net taxable capital gains, if any, that is paid or becomes
payable to the Unitholder by the Trust in that year. To the extent that amounts
payable to a Unitholder are designated as taxable capital gains, those amounts
will be treated as taxable capital gains realized by the Unitholder.
Distributions by the Trust to a Unitholder in excess of the Trust's
income will generally reduce the adjusted cost base of the Unitholder's Trust
Units. To the extent that the adjusted cost base of a Trust Unit held as capital
property would otherwise be less than zero, the Unitholder will be deemed to
have realized a capital gain equal to that negative amount.
A Unitholder who holds the Trust Units as capital property will
generally realize a capital gain (or capital loss) on the disposition of such
Trust Units to the extent that the proceeds of disposition exceed (or are less
than) the aggregate of the Unitholder's adjusted cost base of the Trust Units
and reasonable disposition expenses.
Exempt Plans will not generally be liable for any tax with respect to
any distributions by the Trust or on any capital gain realized on the
disposition of Trust Units.
A Unitholder who is not resident in Canada for the purposes of the Tax
Act will generally be subject to a 25% Canadian withholding tax on distributions
of the Trust's income unless such rate is reduced pursuant to the terms of an
income tax treaty between Canada and the non-resident Unitholder's jurisdiction
of residence.
Unitholders should also see "Competitive Conditions and Risk Factors -
March 23, 2004 Federal Budget" for proposed amendments to the Tax Act. Effective
January 1, 2003, the Trust Units constituted foreign property for the purposes
of Part XI of the Tax Act. However, the Trust Units will not constitute
C-36
foreign property in 2004. See "Competitive Conditions and Risk Factors - Foreign
Property Designation".
Termination of the Trust
The Unitholders may vote by special resolution (66 2/3% of the votes of
Unitholders represented at a meeting) to terminate the Trust at any meeting of
Unitholders duly called for that purpose, whereupon the Trustee shall commence
to wind up the affairs of the Trust, provided that such a vote may only be held
if it is requested in writing by the holders of not less than 25% of the
outstanding Trust Units and holders of not less than 50% of the outstanding
Trust Units are present in person or represented by proxy at the meeting at
which the vote is taken. Unless the Trust is terminated or its term extended,
the Trustee shall commence to wind up the affairs of the Trust on December 31,
2065.
Upon being required to commence to wind up the affairs of the Trust,
the Trustee shall sell and convert into money or otherwise dispose of the
Royalty and all other assets comprising the Trust Fund in one transaction or in
a series of transactions at public or private sale and do all other acts
appropriate to liquidate the Trust Fund. In no event shall the Trust be wound up
until the Royalty shall have been sold, and under no circumstances shall any
Unitholder come into possession of any interest in the Royalty as a result of
the termination of the Trust.
After paying, retiring or discharging or making provision for the
payment, retirement or discharge of all known liabilities and obligations of the
Trust and providing for indemnity against any other outstanding liabilities and
obligations, the Trustee shall distribute the remaining part of the proceeds of
the sale of the Royalty and the other assets of the Trust to Unitholders of
record as at the date the register of the Trust is closed on a pro rata basis.
COMPETITIVE CONDITIONS AND RISK FACTORS
The business activities from which the Trust derives its revenues are
conducted through or in connection with assets, properties and interests held by
Ventures Trust (through Ventures) or Ultima Energy, or subsidiaries or
affiliates thereof. All references herein to any business, assets, properties or
interests of the Trust are made, without specifying the nature thereof, about
the business, assets, properties and interests held by Ventures Trust (or
Ventures on Ventures Trust's behalf), Ultima Energy, or subsidiaries or
affiliates thereof. There are no foreign properties or assets owned by Ventures
Trust or Ultima Energy.
Nature of Trust Units
The Trust Units do not represent a traditional investment in the oil
and natural gas sector and should not be viewed by investors as shares in
Ventures, AcquireCo, the Manager or Ultima Energy. The Trust Units represent a
fractional interest in the Trust. The Trust's assets presently include Permitted
Investments, the Royalty under the Royalty Agreement, the Energy Royalty under
the Energy Royalty Agreement, all of the issued and outstanding trust units of
Ventures Trust and all of the issued shares of Ventures, AcquireCo, Ultima
Energy and the Manager. The market price of the Trust Units is sensitive to a
variety of factors, including, but not limited to, commodity prices for
petroleum products, interest rates, the ability of the Trust to acquire suitable
oil and natural gas properties and past and expected future distributions to
Unitholders. Changes in any of these factors may adversely affect the trading
price of the Trust Units.
The Trust Indenture provides that Unitholders will not be liable for or
in respect of the obligations of the Trust and that any contracts entered into
on behalf of the Trust will not be personally binding on the Trustee, the
Manager or any Unitholder and that any liability will be limited to and
satisfied only out of the assets of the Trust. Notwithstanding the terms of the
Trust Indenture, Unitholders may not be
C-37
protected from liabilities of the Trust to the same extent as a shareholder is
protected from the liabilities of a corporation. Unlike many other royalty
trusts, the structure of the Trust does not include the interposition of a
limited liability entity such as a corporation or limited partnership which
would provide further limited liability protection to Unitholders between the
Properties and Ventures Trust.
Operational Matters
Continuing production from a property, and to some extent the marketing
of production therefrom, are dependent upon the ability of the operator of the
property and the performance of the reservoir. To the extent the operator fails
to perform its functions properly revenue may be reduced. Payments from
production generally flow through the operator. Where Ventures or Ultima Energy
is not the operator, there is a risk of delay and additional expense in
receiving such revenues. Any delay in payment along the production chain could
adversely affect payment of Distributable Income.
The Trust's operations are subject to all of the inherent risks
normally associated with the development and other operations conducted in
respect of oil and natural gas properties. For example, in drilling wells, the
Trust may encounter or experience unexpected formations or pressures, blow-outs,
cratering and fires. In producing wells, the Trust may encounter or experience
premature or unexpected declines of reservoirs or invasion of water into
producing formations. The Trust's operations may also result in environmental or
other damage. Any of these occurrences could result in material losses,
liabilities or costs to the Trust. The wells and facilities of Ventures and
Ultima Energy are covered by liability insurance coverage, where available, in
amounts consistent with standard industry practice. Business interruption
insurance is also purchased for selected facilities, to the extent such
insurance is available. The Manager, Ventures Trust, Ventures, AcquireCo, Ultima
Energy or the Trust may become liable for damages arising from such events
against which they cannot insure or against which they may elect not to insure
because of high premium costs or other reasons. Costs incurred to repair any
such damage or pay any such liabilities will reduce Distributable Income.
Regulation and Competition
The Trust's oil and natural gas operations are subject to extensive
controls and regulations imposed by various levels of government. See
"Competitive Conditions and Risk Factors - Government Regulation". The future
value of the Trust's properties is impacted by various local, national and
international economic and political factors that are beyond the control of the
Trust. The oil and natural gas industry is intensely competitive and the Trust
competes against much larger, well-established companies with substantially
greater technical and financial resources for capital, skilled personnel,
undeveloped lands, reserves acquisitions, access to drilling rigs, service rigs
and other equipment, access to processing facilities and pipeline and refining
capacity and all other aspects of its operations. Some of those organizations
not only explore for, develop and produce oil and natural gas but also carry on
refining operations and market petroleum and other products on a world wide
basis and as such have greater and more diverse resources on which to draw.
Reserves
The reserves and estimated future net cash flows from the Properties
have been independently evaluated in the McDaniel Report. The reserves and
estimated future net cash flows attributable to the Trust's net royalty interest
in the Weyburn NRI have been independently evaluated in the GLJ Report. See
"Description of Business". These estimates include a series of assumptions
relating to factors such as recoverability and marketability of production,
future prices of oil and natural gas, operating costs, future capital
expenditures and royalties and other government levies that may be imposed over
the producing life of the reserves. The Trust's ability to increase reserves in
the future will depend not only on its ability to develop its present
properties, but also on its ability to select and acquire suitable producing
properties or prospects. In that regard, the Trust is restricted from spending
funds on exploratory operations and it is
C-38
not permitted to incur capital expenditures in excess of 10% of the annual net
cash flow to which it is entitled from the Properties (excluding any interest in
the Weyburn Unit or the Weyburn NRI) unless the incurrence of such capital
expenditures is, in the opinion of the Manager and as determined by the boards
of directors of Ventures or AcquireCo, as the case may be, necessary or
advisable to maintain the integrity of the Properties (or other assets) in
accordance with prudent oil and gas practices or unless such expenditures are
funded by the public offering of additional Trust Units, debt, or a combination
thereof. There is no assurance that the Trust's future development efforts will
result in the discovery and development of additional commercial accumulations
of oil and natural gas, notwithstanding the independent evaluations of McDaniel
or GLJ.
The Trust's future oil and natural gas reserves and production, and
therefore its cash flows, will be highly dependent upon Ventures Trust's,
AcquireCo's and Ultima Energy's success in exploiting their reserve bases and
acquiring additional reserves. Without reserve additions through acquisition or
development activities, the Trust's reserves and production will decline over
time as reserves are exploited.
To the extent that external sources of capital, including the issuance
of additional Trust Units, become limited or unavailable, the Trust'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 the Trust is required to use
cash flow to finance capital expenditures or property acquisitions, the level of
Distributable Income will be reduced, all other factors remaining equal.
The price for petroleum or natural gas interests to be acquired by the
Trust will, in part, be based on engineering and economic assessments made by
independent engineers. These assessments include a series of assumptions
regarding such factors as recoverability and marketability of oil and natural
gas, future prices of oil and natural gas and operating costs, future capital
expenditures and royalties and other government levies which will be imposed
over the producing life of the reserves. Many of these factors are subject to
change and are beyond the control of the Manager, Ventures Trust, AcquireCo,
Ultima Energy or the Trust. In particular, changes in the prices of, and markets
for, oil and natural gas from those anticipated at the time of making such
assessments will affect the return on and value of the Trust Units. In addition,
all such assessments involve a measure of geological and engineering uncertainty
which could result in lower production and reserves than anticipated.
Volatility of Oil and Natural Gas Prices
The price that the Trust receives for its oil and natural gas
production is market determined and has been subject to considerable volatility
over which the Trust has no control. See "Competitive Conditions and Risk
Factors - Government Regulation". There is also competition between the
petroleum industry and other industries with respect to the supply of energy and
fuel to industrial, commercial and individual customers. Any decline in oil or
natural gas prices could have a material adverse effect on the Trust's
operations, financial condition, Distributable Income, proved reserves and the
level of expenditures for the development of its oil and natural gas reserves.
The ability of the Trust to sell its oil and natural gas production is subject
to many factors, including price and other market fluctuations, the proximity
and capacity of both oil and natural gas pipelines and processing facilities and
extensive government regulation. The economics of producing from some wells may
change as a result of lower prices, which could result in a reduction in the
volumes of the Trust's reserves. The Trust may also elect not to produce from
certain wells at lower prices. All of these factors could result in a material
decline in the Trust's net production revenue and overall value.
In order to partially hedge the effect that fluctuating oil prices have
on the Trust, the Trust may, from time to time, enter into commodity price hedge
arrangements and foreign currency hedge arrangements.
C-39
Summarized below are Ventures Trust's outstanding commodity price hedge
arrangements as at December 31, 2003:
Crude Oil Hedges Daily Sold Purchased
(US$/bbl except as indicated) Quantity Fixed Price Call Put Sold Put Term
----------------------------- -------- ----------- ---- --- -------- ----
Crude Oil 1,000 bbls $35.00(CDN) - - - Calendar 2004
Crude Oil 800 bbls - $27.50 $24.00 $20.00 Calendar 2004
Crude Oil 700 bbls - $30.00 $25.00 $21.00 Calendar 2004
Crude Oil 1,000 bbls $27.00 - - - January 1 -
June 30, 2004
Natural Gas Hedges
(CDN$/GJ) Daily Quantity Fixed Price Term
--------------------------- -------------- ----------- ----
Natural Gas 1,000 GJs $7.00 April 1, 2003 -
March 31, 2004
Natural Gas 4,000 GJs $6.15 August 1, 2003 -
March 31, 2004
Currency Exchange Rates
The Trust's operating costs, including costs of production, are
generally paid in Canadian dollars. World oil prices are quoted in U.S. dollars
and the price Canadian producers receive is therefore affected by the
Canadian/U.S. dollar exchange rate that will fluctuate over time. An increase in
the value of the Canadian dollar may negatively impact the Trust's production
revenue and reduce Distributable Income.
Debt Service
The Trust's bank indebtedness is based on variable interest rates that
may fluctuate over time. A material increase in interest rates would lead to
higher bank debt servicing costs that would negatively impact Ventures Trust's
and Ultima Energy's royalty payments to the Trust. In order to partially hedge
the effect that fluctuating bank interest rates have on the Trust, the Trust
may, from time to time, enter into interest rate swaps that fix the effective
rate of interest that the Trust will pay on a portion of its bank debt. The
Trust is not currently a party to any interest rate swap transactions.
The Trust's deferred capital obligation is based on a fixed interest
rate and repayment schedule.
Payment of Distributable Income
Although the Trust is structured for monthly payments of any
Distributable Income, such Distributable Income does not necessarily reflect
accrued royalty income in such month, but rather an estimate of the actual
amounts received or receivable in the period. Estimates are required to be made
because, in addition to the usual delays in payment by purchasers of oil and
natural gas to the operator of the Properties, from the operator to Ventures
Trust, AcquireCo or Ultima Energy (where the Manager is not the operator), from
Ventures Trust, AcquireCo or Ultima Energy to the Trust and from the Trust to
Unitholders, payments between any of such parties may also be affected or
delayed by restrictions imposed by lenders, accounting delays, delays in the
sale or delivery of products, delays in the connection of wells to a gathering
system, blowouts or other accidents, adjustments for prior periods, recovery by
the operator of expenses incurred in the operation of properties or the
establishment by the operator of reserves for such expenses. As the accrued
royalty income for each month is verified, adjustments to reflect the actual
Distributable Income for each month are made to payments of Distributable Income
in subsequent months.
C-40
The payment of Distributable Income may also be affected by obligations
under Ventures Trust's credit facility. Under the terms of Ventures Trust's
credit facility, the lender is paid in priority to distributions to Unitholders.
To the extent that there are amounts due and unpaid under the facility, the
Trust may be precluded from providing distributions on Trust Units and from
redeeming any Trust Units until such outstanding amounts are paid. The lender
under the credit facility may also restrict the Trust's ability to pay
distributions when Ventures Trust is in breach or default of the credit
facility.
Changes in Legislation
There can be no assurance that income tax laws and government incentive
programs relating to the oil and natural gas industry, such as the resource
allowance, will not be changed in a manner which adversely affects Unitholders.
Loss of Mutual Fund Trust Status
If the Trust ceases to qualify at any relevant time as a "mutual fund
trust" under the Tax Act, the Trust Units will cease to be qualified investments
for Exempt Plans. Where at the end of any month an Exempt Plan holds Trust Units
that are not qualified investments, the Exempt Plan must, in respect of that
month, pay a tax under Part XI.1 of the Tax Act equal to 1% of the fair market
value of the Trust Units at the time such Trust Units were acquired by the
Exempt Plan. In addition, where an RRSP or RRIF acquires Trust Units that are
not qualified investments, the RRSP or RRIF will become taxable on its income
attributable to the Trust Units while they are not qualified investments and the
annuitant or beneficiary, respectively, of such Exempt Plan will be required to
include in income the fair market value of the non-qualified investment at the
time of acquisition. If the Trust ceases to qualify as a "mutual fund trust" it
may also be subject to taxation under Part XII.2 of the Tax Act which may have
negative consequences for non-residents or other persons exempt from Part I tax
under the Tax Act. For Unitholders who are non-residents of Canada, loss of
mutual fund trust status will result in the Trust Units constituting taxable
Canadian property for the purposes of the Tax Act, thus potentially subjecting
the disposition of such Trust Units to tax under the Tax Act.
Foreign Property Designation
On April 5, 2002, the Trust announced that due to the strong financial
performance of its investment in the Partnership, Trust Units will be deemed to
be "foreign property" under Part XI of the Tax Act effective January 1, 2003 for
RRSPs, DPSPs, RRIFs and other deferred income plans (collectively, "Registered
Plans"). Trust Units were not "foreign property" for purposes of the Tax Act in
2001 and will not be "foreign property" in 2002 and, as such, holders of Trust
Units will not be subject to any tax under Part XI of the Tax Act for 2001 or
2002 solely as a result of holding Trust Units. The designation of the Trust
Units as "foreign property" does not affect Trust Units which are held outside
of Registered Plans.
Part XI tax may be payable in respect of a Registered Plan in 2003 if,
at the end of any month, the aggregate cost amount of all foreign property
(including the Trust Units) of the Registered Plan exceeds 30% of the cost
amount of all property of the Registered Plan. The tax payable under Part XI of
the Tax Act is calculated at the end of each month at the rate of 1% of the
amount, if any, by which the cost amount of all foreign property exceeds 30% of
the aggregate cost amount of all property. However, Registered Plans which have
acquired their Trust Units prior to January 1, 2003, will have a 24-month grace
period before any tax is payable by them under Part XI of the Tax Act.
As a result of the Partnership Redemption, the Trust Units ceased to be
"foreign property" as of January 1, 2004. See "General Development of the
Business - Development - 2002 - Weyburn Limited Partnership Capital Contribution
and Redemption". Unitholders whose Registered Plans have in excess of 30%
foreign property by virtue of their investment in Trust Units acquired prior to
January 1, 2003
C-41
should likely be able to take no action and avoid paying any tax pursuant to
Part XI of the Tax Act due to the 24-month grace period described above. Trust
Units acquired in 2003 will not be entitled to the 24-month grace period. As a
consequence, if the acquisition of Trust Units in 2003 results in a Registered
Plan exceeding the 30% foreign property content level, Part X1 tax should apply
to such plan.
Income Tax Payable
There can be no assurance that the Canada Revenue Agency ("CRA") will
agree with how the Trust calculates its income for tax purposes or that the CRA
will not change its administrative practices to the detriment of the Trust or
the Unitholders. In 2004, it is expected that a portion of the distributions
paid or payable by the Trust will represent the income of the Trust and will
thus be required to be included in the income of Unitholders.
March 23, 2004 Federal Budget
On March 23, 2004, Minister of Finance (Canada) Ralph Goodale tabled
the federal budget (the "budget") which proposes amendments to the Tax Act that
could have an impact on the Trust and its Unitholders.
In order to qualify as a mutual fund trust, among other things, Ultima
cannot, and may not at any time, reasonably be considered to be established or
maintained primarily for the benefit of non-resident persons unless at all times
since February 21, 1990, all or substantially all of its property has consisted
of property other than "taxable Canadian property" (as defined in the Tax Act)
(the "property exception").
Subject to certain transitional relief available until December 31,
2006, the budget proposes that Canadian resource property (which includes the
Royalty and the Energy Royalty) be considered taxable Canadian property for the
purposes of the property exception after March 22, 2004. The transitional relief
contained in the budget is available to those trusts that on March 23, 2004 (i)
were maintained primarily for the benefit of non-resident persons and (ii)
satisfied the property exception. The Trust has never been maintained primarily
for the benefit of non-resident persons and thus the budget proposals in this
regard will not have an adverse impact on the Trust.
The budget proposes a new 15% Canadian withholding tax on the
non-taxable portion of the Trust's distributions, which, under the current
provisions of the Tax Act, are not subject to any Canadian withholding tax. The
budget proposes that the new 15% Canadian withholding tax be applicable to
distributions made by the Trust after 2004. The new 15% Canadian withholding tax
will only apply if, at the time of the distribution, Units of the Trust are
listed on a prescribed stock exchange (which includes the Toronto Stock
Exchange) and the value of the Trust's Units is primarily attributable to real
property situated in Canada, Canadian resource property (which includes the
Royalty and the Energy Royalty) or a timber resource property. If a subsequent
disposition of a Unit results in a capital loss to a non-resident Unitholder, a
refund of the new 15% Canadian withholding tax is available in limited
circumstances, subject to the filing of a special Canadian tax return.
The budget also proposes a 25% withholding tax on distributions made to
non-residents of Canada which are attributable to capital gains realized by the
Trust after March 22, 2004 on the disposition of taxable Canadian property where
the Trust has made certain designations on such capital gain with respect to its
Unitholders. The 25% rate of Canadian withholding tax may be reduced pursuant to
the terms of an applicable income tax treaty between Canada and the Unitholder's
jurisdiction of residence.
It is expected that the budget proposals with respect to withholding
tax on distributions will not have any impact on the Trust prior to the Merger,
but could have an impact on the trust remaining after the merger of the Trust
with Petrofund pursuant to the Combination Agreement.
C-42
Experience of Management
Subject to the annual audit by the independent auditors and supervision
by the Boards, Unitholders are dependent on management in respect of the
administration of all matters relating to the Royalty Agreement and the Trust
Units. Moreover, Ventures Trust's and Ultima Energy's operations are also highly
dependent on the executive officers and management employees of the Manager. The
unexpected loss of the services of any of these individuals could have a
detrimental effect on the operations of the Trust.
Potential Conflicts of Interest
Certain of the directors of Ventures, AcquireCo, Ultima Energy and the
Manager may be associated with other oil and natural gas companies from time to
time which could occasionally give rise to various conflicts of interest. In
order to address those conflicts, Ventures, AcquireCo, Ultima Energy and the
Manager and their directors comply with the provisions of the ABCA concerning
conflicts of interest. Those provisions require a director who has an interest
in a material contract or proposed material contract with Ventures, AcquireCo,
Ultima Energy, the Manager or an affiliate thereof to disclose the nature and
extent of that interest and, in most instances, to refrain from voting on any
resolution to approve that contract. See "Conflicts of Interest".
Government Regulation
The oil and natural gas industry in Canada is subject to extensive
controls and regulations imposed by various levels of government. In addition to
federal regulation, in western Canada, the various provincial governments have
enacted legislation and regulations which govern land tenure, production rates,
royalties, environmental protection, the prevention of waste, safety regulation
and other matters.
On March 3, 2003, the Department of Finance issued a technical paper on
proposed changes to the taxation of the resource sector, including the tax
treatment of Crown royalties and the resource allowance. In general, the
proposed changes include the elimination of the resource allowance over five
years in conjunction with making Crown royalties deductible over the same time
period. The changes referred to in the technical paper were enacted into law in
November 2003 and could adversely impact the taxation of the Trust.
Outlined below are some of the more significant aspects of the
legislation, regulations and agreements governing the oil and natural gas
industry. All current legislation is a matter of public record and the Manager
is unable to predict what additional legislation or amendments may be enacted.
The Trust does not expect these controls and regulations to affect its
operations in a manner significantly different than they will affect other oil
and gas producers of similar size.
Land Tenure
Oil and natural gas located in western Canada is owned predominantly by
the respective provincial governments. Provincial governments grant rights to
explore for and produce oil and natural gas pursuant to leases, licenses and
permits for varying terms from two years and on conditions set forth in
provincial legislation which may include requirements to perform specific work
or make payments. Oil and natural gas located in such provinces can also be
privately owned and rights to explore for and produce such oil and natural gas
are generally granted by lease from the freehold owner on such terms and
conditions as may be negotiated.
C-43
Production
Provincial governments regulate production in accordance with sound
engineering and conservation practices and usually establish daily production
limits. Production is also limited by pipeline capacities, demand for natural
gas and various grades of crude oil and, in limited circumstances, by production
rate limitations imposed by regulatory authorities to encourage maximum ultimate
recovery.
Price and Marketing
Governments in Canada play little role in the pricing of oil and
natural gas. Producers of oil negotiate sales contracts directly with
purchasers, with the result that the market determines the price of oil. Price
normally depends on factors such as oil quality, price of competing oils,
distance to market and value of refined products.
In Canada, the price of natural gas sold in interprovincial and
international trade is determined by negotiation between buyers and sellers and
normally depends on factors such as price of competing gas, distance to market,
length of contract term and other contractual terms.
While the Trust is not directly involved in the business of oil or gas
export, its sales are indirectly affected by governmental control and regulation
of the removal of oil and natural gas from Saskatchewan and Alberta into other
parts of Canada and further export beyond the borders of Canada. The governments
of Alberta and Saskatchewan 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.
Crude oil and natural gas may be exported from Canada pursuant to
export contracts with terms not exceeding one year in the case of light crude,
and two years in the case of heavy crude and natural gas, provided that an
approval order has been obtained from the National Energy Board (the "NEB"). Any
export to be made pursuant to a contract of longer duration requires an export
license from the NEB, the issuance of which requires the approval of the
Governor in Council.
Although pipeline expansions are ongoing, the lack of firm pipeline
capacity continues to affect the oil and natural gas industry and limit the
ability to produce and to market natural gas production. The prorating of
capacity on the interprovincial pipeline systems may also affect the ability to
export oil.
Provincial Royalties and Incentives
The royalty regime applicable to particular oil and natural gas
production is a significant factor in determining its profitability. Royalties
payable on production from land other than Crown lands are determined by
negotiation between the mineral owner and the lessee. Crown royalties are
determined by government regulation and are generally calculated as a percentage
of the value of gross production and vary depending on factors such as
prescribed reference prices, well productivity, geographic location, field
discovery date, method of recovery and the type and quality of the petroleum
product produced. From time to time, the provincial governments of Alberta and
Saskatchewan have established incentive programs for the purpose of encouraging
oil and natural gas exploration and development. Such programs often provide for
royalty reductions and royalty holidays, and are generally introduced when
commodity prices are low. The programs are designed to encourage exploration and
development activity by improving earnings and cash flow within the industry.
The trend in recent years has been for provincial governments to allow such
programs to expire without renewal, and consequently few such programs are
currently operative.
All properties and interests owned by the Trust as at December 31, 2003
were located in the Provinces of Saskatchewan and Alberta.
C-44
On October 13, 1992, the Government of Alberta implemented major
changes to its royalty structure and created incentives for exploring for oil
and natural gas reserves. The incentives include: (i) a one year royalty holiday
on new oil discovered after October 1, 1992, (ii) incentive by way of royalty
holidays and reduced royalties on reactivated, low productivity, vertical
re-entry and horizontal wells, (iii) introduction of separate par pricing for
light/medium and heavy oil, and (iv) a modification of royalty formula structure
through the implementation of a third tier royalty with a base rate of 10% and
rate cap of 25% for oil pools discovered after September 30, 1992. The new oil
royalty reserved to the Crown has a base rate of 10% and a rate cap of 30%. The
old royalty reserved to the Crown has a base rate of 10% and a rate cap of 35%.
The royalty reserved to the Crown in respect of natural gas production, subject
to various incentives, is between 15% and 30%, in the case of new gas, and
between 15% and 35% in the case of old gas, depending upon a prescribed or
corporate average reference price.
In Alberta, certain producers of oil or natural gas are also entitled
to a credit against the royalties payable to the Crown by virtue of the Alberta
royalty tax credit program ("ARTC"). The ARTC rate is based on a price sensitive
formula and varies between 75% at prices at and below $100 per cubic metre and
25% at prices at and above $210 per cubic metre. The ARTC rate is applied to a
maximum of $2,000,000 of Alberta Crown royalties payable for each producer or
associated group of producers. Crown royalties on production from producing
properties acquired from companies claiming maximum entitlement to ARTC will
generally not be eligible for ARTC. The rate is established quarterly based on
the average "par price", as determined by the Alberta Resource Development
Department for previous quarterly period.
Effective October 1, 2002, the Government of Saskatchewan revised its
fiscal regime for the oil and gas industry. Some royalties on wells existing as
of that date will remain unchanged and will therefore be subject to various
periods of royalty/tax deduction. The changes include new lower royalty and tax
structures applicable to both oil, natural gas and associated natural gas
(natural gas produced from oil wells), a new system of volume incentives and a
reduced Corporation Capital Tax Surcharge rate.
The new fiscal regime for the Saskatchewan oil and gas industry
provides an incentive to encourage exploration and development through a revised
royalty tax structure for oil and natural gas wells with a finished drilling
date on or after October 1, 2002 or incremental oil production due to a new or
expanded waterflood project with a commencement date on or after October 1,
2002. This "fourth tier" Crown royalty rate, applicable to both oil and natural
gas, is price sensitive and ranges from a minimum 5% at a base price to a
maximum of 30% at a price above the base price. A fourth tier freehold tax
structure, calculated by subtracting a production tax factor of 12.5 percentage
points from the corresponding Crown royalty rates, has also been created which
is applicable to conventional oil, incremental oil from new or expanded
waterfloods and natural gas. The fourth tier royalty/tax structure is also
applicable in respect of associated natural gas that is gathered for use or sale
which is produced either from oil wells with a finished drilling date on or
after October 1, 2002 and oil wells with a finished drilling date prior to
October 1, 2002, where the individual oil well has a gas-oil production ratio in
any month of more than 3,500 cubic metres of natural gas per 1 cubic metre of
oil. In addition, volume-based royalty/tax reduction incentives have been
changed such that a maximum royalty of 2.5% now applies to various volumes of
both oil and natural gas, depending on the depth and nature of the well (up to
16,000 cubic metre of oil in the case of deep exploratory wells and 25,000 cubic
metres of natural gas produced from exploratory wells). The royalty/tax category
with respect to re-entry and short sectional horizontal oil wells has been
eliminated such that all horizontal oil wells with a finished drilling date on
or after October 1, 2002 will receive fourth tier royalty/tax rates and
incentive volumes. Further changes include the reduction of the Corporation
Capital Tax Surcharge rate from 3.6% to 2.0% and the expansion of the "deep oil
well" definition to include oil wells producing from a zone deeper than 1,700
metres provided that the zone is within a geological system deposited during the
Mississippian Period or earlier or from a zone that was deposited before the
Bakken zone regardless of depth.
C-45
Kyoto Protocol
In 1994, the United Nations' Framework Convention on Climate Change
came into force and three years later led to the Kyoto protocol which will
require nations, upon ratification, to reduce their emissions of carbon dioxide
and other greenhouse gases. Although it is not known what impact, if any, there
will be on the Trust's operations, reductions in greenhouse gases from the
Trust's operations may be required which could result in increased capital
expenditures and reductions in production of oil and gas.
Environmental Regulation
The oil and gas industry is currently 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 or utilized in association with oil and gas
industry operations. Legislation also requires that well and facility sites be
abandoned and reclaimed to the satisfaction of provincial authorities.
Compliance with such legislation may require significant expenditure and a
breach of any such legislation may result in suspension or revocation of
required licenses and authorizations, civil liability for resulting damage, the
imposition of fines and penalties, or the issuance of clean-up orders.
In Saskatchewan, maintenance of environmental quality for oil and
natural gas operations is governed primarily by the Oil and Gas Conservation Act
(Saskatchewan) and the Environmental Management and Protection Act
(Saskatchewan). Pursuant to those Acts and the regulations promulgated
thereunder, spilled material is monitored and regulated and permits and
approvals are required for any waste processing facility or any facility or
operation which discharges any pollutant into the environment. Those Acts also
regulate the decommissioning, abandonment and reclamation of wells and any
related facility or operation.
Environmental legislation in Alberta has been consolidated into the
Environmental Protection and Enhancement Act (Alberta) ("AEPEA"). Under the
AEPEA, environmental standards and compliance for releases, clean-up and
reporting are stricter. Also, the range of enforcement actions available and the
severity of penalties have been significantly increased. These changes have had
an incremental effect on the cost of conducting operations in Alberta.
Pursuant to the terms of the Royalty Agreement, funds have been set
aside to provide for the future cost of abandonments and reclamation work on
wells, plants and facilities. The Trust contributes $0.20 per boe of production
from cashflow for future use and deposits such funds into a separate reserve
account. A total of $625,000 was contributed during the 12 months ended December
31, 2003 and the total balance is $1,077,000 as at December 31, 2003. Actual
reclamation expenditures in 2003 were $296,000.
The Trust is committed to meeting its legal and moral responsibility to
protect the environment. The Trust anticipates making increased, although not
material, expenditures of both a capital and expense nature as a result of the
higher environmental standards demanded of oil and gas companies by both
legislation and the general public. The amount of these expenditures cannot
presently be determined.
The Trust is of the opinion that it has been in material compliance
with all applicable environmental laws and regulations during the year ended
December 31, 2003. The Trust's operations are, and will continue to be, affected
in varying degrees by laws and regulations regarding the protection of the
environment. It is impossible to predict the full impact of these laws and
regulations on the Trust's operations; however, it is not anticipated that the
Trust's competitive position will be adversely affected by current and future
environmental laws and regulations governing its current oil and gas operations.
C-46
Safety Regulation
The Trust is committed to protecting and promoting the health and
safety of its employees and other stakeholders in all of its operations. To that
end, the Trust has implemented a formal safety program that it will continue to
monitor and upgrade. This program is designed to ensure that the Trust meets or
exceeds all applicable government regulations relating to health and safety.
SELECTED CONSOLIDATED FINANCIAL INFORMATION
The Trust, Ventures Trust, AcquireCo and Ultima Energy present their
audited financial information on a consolidated basis. Prior to the Partnership
Redemption, the Trust only recorded income from the Partnership to the extent of
the Trust's 92% share of the Partnership's distributions, as the Trust did not
control the Partnership. The Trust did not consolidate the financial results of
the Partnership with the financial results of the Trust. Summary financial
statements of the Partnership can be found in the notes to the Annual
Consolidated Financial Statements of the Trust for the year ended December 31,
2003. The following table sets forth selected consolidated financial information
of the Trust, Ventures Trust, AcquireCo and Ultima Energy for each of the three
most recently completed financial years indicated:
SELECTED CONSOLIDATED FINANCIAL INFORMATION
(thousands except per Trust Unit amounts)
12 months ended 12 months ended 12 months ended
December 31, 2003 December 31, 2002(1) December 31, 2001(1)
----------------------------------------------------------------
Oil and natural gas revenues $ 111,107 $ 38,253 $ 28,397
----------------------------------------------------------------
Partnership Income $ -- $ 4,198 $ 3,104
----------------------------------------------------------------
Total revenues, net of royalties $ 89,297 $ 42,451 $ 31,501
----------------------------------------------------------------
Funds from operations $ 54,880 $ 24,016 $ 17,728
----------------------------------------------------------------
Funds from operations per unit, basic $ 1.29 $ 1.09 $ 1.17
----------------------------------------------------------------
Funds from operations per unit, fully $ 1.26 $ 1.08 $ 1.15
diluted
----------------------------------------------------------------
Cash distributed $ 48,135 $ 20,974 $ 15,163
----------------------------------------------------------------
Cash distributed per unit $ 1.09 $ 0.90 $ 1.00
----------------------------------------------------------------
Net income $ 12,278 $ 9,224 $ (5,281)
----------------------------------------------------------------
Net income per unit, basic $ 0.29 $ 0.42 $ (0.35)
----------------------------------------------------------------
Net income per unit, fully diluted $ 0.28 $ 0.41 $ (0.34)
----------------------------------------------------------------
Total book value of assets $ 326,539 $ 218,175 $ 92,771
----------------------------------------------------------------
Total long-term debt(2) $ 81,376 $ 78,238 $ 30,209
----------------------------------------------------------------
Unitholders' equity $ 208,444 $ 125,374 $ 53,820
----------------------------------------------------------------
Trust Units outstanding at period end 57,624,975 33,873,808 18,447,143
----------------------------------------------------------------
Trust Unit price at period end $ 6.24 $ 5.15 $ 4.20
----------------------------------------------------------------
Notes:
(1) Prior periods have been restated to reflect a change in accounting policy.
See note 2(l) to the Consolidated Financial Statements of the Trust for the
year ended December 31, 2003.
(2) Includes long term bank debt and the deferred capital obligation associated
with the Weyburn NRI for 2002. The deferred capital obligation is only
deductible from the royalty payment to be received by Ventures Trust from
the Weyburn NRI. It is not secured by the Trust's other assets. See"
General Development of the Business - Development - 2002 - Weyburn Limited
Partnership Capital Contribution and Redemption".
The following table sets forth selected consolidated financial
information of the Trust, Ventures Trust, AcquireCo and Ultima Energy (including
the Partnership income distributed to the Trust) with respect to each of the
last eight financial quarters ending on March 31 ("Q1"), June 30 ("Q2"),
September 30 ("Q3") and December 31 ("Q4"), respectively:
C-47
SELECTED QUARTERLY FINANCIAL INFORMATION
(thousands except per Trust Unit amounts)
2003 Q4 2003 Q3 2003 Q2 2003 Q1 2002 Q4(1) 2002 Q3(1) 2002 Q2(1) 2002 Q1(1)
------- ------- ------- ------- ---------- ---------- ---------- ----------
Total revenues, net of $ 25,712 $ 24,635 $ 19,100 $ -- $ 13,044 $ 8,644 $ 8,782 $ 7,782
royalties
---------------------------------------------------------------------------------------------------
Partnership Income $ -- $ -- $ -- $ -- $ 424 $ 1,267 $ 1,420 $ 1,087
---------------------------------------------------------------------------------------------------
Funds from operations $ 15,923 $ 14,950 $ 11,670 $ 12,336 $ 7,351 $ 5,652 $ 5,980 $ 5,032
---------------------------------------------------------------------------------------------------
Funds from operations, per $ 0.30 $ 0.30 $ 0.33 $ 0.36 $ 0.31 $ 0.24 $ 0.27 $ 0.27
unit
---------------------------------------------------------------------------------------------------
Cash distributed $ 14,187 $ 14,625 $ 10,131 $ 9,192 $ 6,528 $ 5,726 $ 5,137 $ 3,583
---------------------------------------------------------------------------------------------------
Cash distributed per unit $ 0.265 $ 0.285 $ 0.27 $ 0.27 $ 0.24 $ 0.24 $ 0.23 $ 0.19
---------------------------------------------------------------------------------------------------
Net income $ 4,765 $ 4,124 $ 3,352 $ 37 $ 2,403 $ 2,373 $ 2,574 $ 1,874
---------------------------------------------------------------------------------------------------
Net income per unit $ 0.10 $ 0.09 $ 0.10 $ 0.00 $ 0.10 $ 0.10 $ 0.12 $ 0.10
---------------------------------------------------------------------------------------------------
Notes:
(1) Prior periods have been restated to reflect a change in accounting policy.
See note 2(l) to the Consolidated Financial Statements of the Trust for the
year ended December 31, 2003.
MANAGEMENT'S DISCUSSION AND ANALYSIS
The information contained in the Management's Discussion and Analysis
for the financial year ended December 31, 2003 is incorporated herein by
reference and forms an integral part of this Annual Information Form.
MARKET FOR SECURITIES
The Trust Units have been listed and posted for trading on the Toronto
Stock Exchange (the "TSX") since July 29, 1996 and trade under the symbol
"UET.UN".
DISTRIBUTION POLICY AND RECORD
Distributable Income is calculated by the Manager and is approved by
the boards of directors of Ventures and AcquireCo. The Trustee distributes
Distributable Income to Unitholders on the 15th day of the month, or if such day
does not fall on a business day, the next business day following the 15th day of
the month. The following cash distributions have been made to Unitholders during
2002, 2003 and 2004:
Period for which Total Cash
Distribution Declared Distribution Per Trust Unit
--------------------- ------------ --------------
2002
January.............................. $ 1,131,000 $ 0.06
February............................. $ 1,131,000 $ 0.06
March................................ $ 1,320,000 $ 0.07
April................................ $ 1,320,000 $ 0.07
May.................................. $ 1,908,571 $ 0.08
June................................. $ 1,908,571 $ 0.08
July................................. $ 1,908,571 $ 0.08
August............................... $ 1,908,571 $ 0.08
September............................ $ 1,908,571 $ 0.08
October.............................. $ 1,908,571 $ 0.08
November............................. $ 1,908,571 $ 0.08
December............................. $ 1,908,571 $ 0.08
C-48
Period for which Total Cash
Distribution Declared Distribution Per Trust Unit
--------------------- ------------ --------------
2003
January.............................. $3,054,553 $ 0.090
February............................. $3,060,103 $ 0.090
March................................ $3,077,038 $ 0.090
April................................ $3,077,038 $ 0.090
May.................................. $3,527,038 $ 0.090
June................................. $3,527,038 $ 0.090
July................................. $4,864,889 $ 0.095
August............................... $4,871,281 $ 0.095
September............................ $4,888,539 $ 0.095
October.............................. $4,901,206 $ 0.095
November............................. $4,388,123 $ 0.085
December............................. $4,898,123 $ 0.085
2004
January.............................. $4,905,206 $ 0.085
February............................. $4,909,853 $ 0.085
March................................ $4,913,625 $ 0.085
DIRECTORS AND OFFICERS
Amendment of Ventures USA and AcquireCo USA
As a result of the Management Internalization Transaction, the boards
of directors of Ventures and AcquireCo determined that the Manager, as a
wholly-owned subsidiary of the Trust, no longer requires special voting rights
in respect of the election of the directors of Ventures and AcquireCo. At the
Annual and Special Meeting of Unitholders held on May 23, 2003, Unitholders
passed a special resolution authorizing the amendment of the Ventures USA and
the AcquireCo USA to increase the number of directors of each of Ventures and
AcquireCo from five to seven, and to provide that Unitholders shall have the
right to elect all of the directors of each of Ventures and AcquireCo.
Ultima Ventures Corp.
Pursuant to the terms of the Ventures USA, the board of directors of
Ventures consists of seven members, all of whom are elected by the Unitholders.
Pursuant to the terms of the Trust Indenture, the board of directors of
Ventures, together with the board of directors of AcquireCo, has the authority
and responsibility to make or approve most significant decisions affecting the
Trust. Each director will hold office until the Trust's next annual meeting of
Unitholders or until his successor is duly elected or appointed.
Ultima Acquisitions Corp.
Pursuant to the terms of the AcquireCo USA, the board of directors of
AcquireCo consists of seven members, all of whom are elected by the Unitholders.
Pursuant to the terms of the Trust Indenture, the board of directors of
AcquireCo (together with the board of directors of Ventures) has the authority
and responsibility to make or approve most significant decisions affecting the
Trust. Each director will hold office until the Trust's next annual meeting of
Unitholders or until his successor is duly elected or appointed.
C-49
Directors and Officers
Ventures and AcquireCo
The boards of directors of Ventures and AcquireCo are composed of the
same directors. The following table sets forth the name, municipality of
residence, positions/offices held, year first elected/appointed and principal
occupation of each of the directors and officers of Ventures and AcquireCo as at
the date hereof. Each director will hold office until the Trust's next annual
meeting of Unitholders or until his successor is duly elected or appointed.
Name and
Municipality of Year First
Residence Position/Office Elected/Appointed Principal Occupation
------------------ --------------- ----------------- --------------------
Marshall M. Williams(1) Director and 1997 Businessman; Chairman of the Board
Calgary, Alberta Chairman of the
Board
S. Brian Gieni(2) Director, President 2000 President and Chief Executive Officer of
Calgary, Alberta and Chief Executive the Manager, Ventures, AcquireCo and
Officer Ultima Energy
Gary Lee(3) Director 2000 Director of North West Capital Inc.
Calgary, Alberta
John M. Gunn(4) Director 1999 Chief Executive Officer & Chief Financial
Calgary, Alberta Officer of Tango Energy Inc.
Arthur E. Dumont(5) Director 2001 Chairman and Chief Executive Officer of
Calgary, Alberta Technicoil Corporation
Henry R. Lawrie(6) Director 2003 Businessman
Calgary, Alberta
David Tuer(7) Director 2003 Chairman and Chief Executive Officer of
Calgary, Alberta Hawker Resources Inc.
Kenneth G. Pinsky(8) Chief Financial 2001 Chief Financial Officer of the Manager,
Calgary, Alberta Officer Ventures, AcquireCo and Ultima Energy
Michael P. Wihak(9) Chief Operating 2001 Chief Operating Officer of the Manager,
Calgary, Alberta Officer Ventures, AcquireCo and Ultima Energy
John H. Kousinioris(10) Secretary 2003 Partner, Bennett Jones LLP
Calgary, Alberta Barristers and Solicitors
Notes:
1. Mr. Williams is a former Chairman of Alberta Treasury Branches. Mr.
Williams has also served as Chairman of the Board and a Director of
TransAlta Corporation and as a director of Stelco Inc. from 1984 to 1996
and as a director of Sun Life Assurance from 1978 to 1995.
C-50
2. Mr. Gieni is a finance and accounting professional who was employed in
various senior management capacities at PanCanadian Petroleum Limited
between 1997 and 2000. Prior to that, he was President, Chief Executive
Officer and a director of Grantham Resources Inc., a junior resource
company listed on the Alberta Stock Exchange.
3. Mr. Lee is a director and officer of North West Capital Inc. Prior to that,
he was a partner with Hoar, Lee, Boers, Barristers & Solicitors, until
December 1998.
4. Mr. Gunn was the Chairman of Renata Resources Inc., a TSX-listed oil and
gas company, from 1996 until it was acquired in 2000. Prior thereto, Mr.
Gunn was President and Chief Executive Officer of Ballistic Energy
Corporation (formerly a TSX-listed oil and gas company).
5. Mr. Dumont was the President and Chief Executive Officer of CenAlta Energy
Services and its predecessor companies from November 1998 until October
2000. He has also worked in senior roles at Western Rock Bit Company,
Precision Drilling, Kenting Energy Services and Trimac Limited.
6. Mr. Lawrie is a Chartered Accountant - FCA. From July 1997 to February 2001
Mr. Lawrie was the Chief Accountant of the Alberta Securities Commission.
Prior to that, Mr. Lawrie spent 35 years as a Chartered Accountant with
PriceWaterhouseCoopers and acted as managing partner of the Calgary office
before retiring in 1997.
7. Mr. Tuer has been Chairman and Chief Executive Officer of Hawker Resources
Inc. since January 2003 and Chairman of the Calgary Health Region since
October 2001. From December 1994 until October 2001, Mr. Tuer was President
and Chief Executive Officer of PanCanadian Energy Corporation. Prior
thereto, Mr. Tuer worked in various senior roles at PanCanadian Petroleum
Limited.
8. Mr. Pinsky is a Chartered Accountant and a Chartered Financial Analyst.
Most recently, Mr. Pinsky held management positions with Altana Exploration
from September 1997 to December 2000 and Price Waterhouse from 1993 to
1997.
9. Mr. Wihak is a professional engineer and holds a Masters in Business
Administration. Most recently, Mr. Wihak held a management position at
Sunoma Energy Corp./Barrington Petroleum Ltd. from 1997 to 2001. Prior to
that, he was a senior exploitation engineer with Summit Resources Ltd. from
1993 to 1996.
10. Mr. Kousinioris joined Bennett Jones LLP in 1990. From February 1997 until
September 1998, Mr. Kousinioris practiced with a leading law firm in
London, England, following which, he returned to Bennett Jones LLP and is
currently a partner in the Corporate/Commercial Department.
The board of directors of each of Ventures and AcquireCo has appointed
a human resources committee, a reserves committee, a governance committee and,
consistent with the requirements for a "distributing corporation" under the
ABCA, an audit committee. The human resources committee consists of Mr. Lee
(Chairman), Mr. Lawrie and Mr. Williams. The reserves committee consists of Mr.
Gunn (Chairman), Mr. Tuer and Mr. Dumont. The governance committee consists of
Mr. Dumont (Chairman), Mr. Tuer and Mr. Williams. The audit committee consists
of Mr. Lawrie (Chairman), Mr. Gunn and Mr. Lee.
The directors and officers of Ventures and AcquireCo beneficially own,
directly or indirectly, or exercise control or direction over 535,921 (1%) of
the Trust Units currently issued and outstanding.
The Manager
The following table sets forth the name, municipality of residence,
positions/offices held, year first elected/appointed and principal occupation of
each of the directors and officers of the Manager as at the date hereof. Each
director will hold office until the next annual meeting of shareholders of the
Manager or until his successor is duly elected or appointed. It is presently
intended that the directors and officers of the Manager will be the same as
those of Ventures and AcquireCo.
Name and
Municipality of Year First
Residence Position /Office Elected/Appointed Principal Occupation
---------------- ---------------- ----------------- --------------------
Marshall M. Williams(1) Director and 2003 Businessman; Chairman
Calgary, Alberta Chairman of the of the Board
Board
S. Brian Gieni(2) Director, President 2001 President and Chief Executive Officer
Calgary, Alberta and Chief Executive of the Manager, Ventures, AcquireCo and
Officer Ultima Energy
Gary Lee(3) Director 2000 Director of North West Capital Inc.
Calgary, Alberta
C-51
Name and
Municipality of Year First
Residence Position /Office Elected/Appointed Principal Occupation
---------------- ---------------- ----------------- --------------------
John M. Gunn(4) Director 2003 Chief Executive Officer & Chief
Calgary, Alberta Financial Officer of Tango Energy Inc.
Arthur E. Dumont(5) Director 2003 Chairman and Chief Executive Officer of
Calgary, Alberta Technicoil Corporation
Henry R. Lawrie(6) Director 2003 Businessman
Calgary, Alberta
David Tuer(7) Director 2003 Chairman and Chief Executive Officer of
Calgary, Alberta Hawker Resources Inc.
Kenneth G. Pinsky(8) Chief Financial 2001 Chief Financial Officer of the Manager,
Calgary, Alberta Officer Ventures, AcquireCo and Ultima Energy
Michael P. Wihak(9) Chief Operating 2001 Chief Operating Officer of the Manager,
Calgary, Alberta Officer Ventures, AcquireCo and Ultima Energy
John H. Kousinioris(10) Secretary 2003 Partner, Bennett Jones LLP
Calgary, Alberta Barristers and Solicitors
Notes:
1. Mr. Williams is a former Chairman of Alberta Treasury Branches. Mr.
Williams has also served as Chairman of the Board and a Director of
TransAlta Corporation and as a director of Stelco Inc. from 1984 to 1996
and as a director of Sun Life Assurance from 1978 to 1995.
2. Mr. Gieni is a finance and accounting professional who was employed in
various senior management capacities at PanCanadian Petroleum Limited
between 1997 and 2000. Prior to that, he was President, Chief Executive
Officer and director of Grantham Resources Inc., a junior resource company
listed on the Alberta Stock Exchange.
3. Mr. Lee is a director and officer of North West Capital Inc. Prior to that,
he was a partner with Hoar, Lee, Boers until December 1998.
4. Mr. Gunn was the Chairman of Renata Resources Inc., a TSX-listed oil and
gas company, from 1996 until it was acquired in 2000. Prior thereto, Mr.
Gunn was President and Chief Executive Officer of Ballistic Energy
Corporation (formerly a TSX-listed oil and gas company).
5. Mr. Dumont was the President and Chief Executive Officer of CenAlta Energy
Services and its predecessor companies from November 1998 until October
2000. He has also worked in senior roles at Western Rock Bit Company,
Precision Drilling, Kenting Energy Services and Trimac Limited.
6. Mr. Lawrie is a Chartered Accountant - FCA. From July 1997 to February 2001
Mr. Lawrie was the Chief Accountant of the Alberta Securities Commission.
Prior to that, Mr. Lawrie spent 35 years as a Chartered Accountant with
PriceWaterhouseCoopers and acted as managing partner of the Calgary office
before retiring in 1997.
7. Mr. Tuer has been Chairman and Chief Executive Officer of Hawker Resources
Inc. since January 2003 and Chairman of the Calgary Health Region since
October 2001. From December 1994 until October 2001, Mr. Tuer was President
and Chief Executive Officer of PanCanadian Energy Corporation. Prior
thereto, Mr. Tuer worked in various senior roles at PanCanadian Petroleum
Limited.
8. Mr. Pinsky is a Chartered Accountant and a Chartered Financial Analyst.
Most recently, Mr. Pinsky held management positions with Altana Exploration
from September 1997 to December 2000 and Price Waterhouse from 1993 to
1997.
9. Mr. Wihak is a professional engineer and holds a Masters in Business
Administration. Most recently, Mr. Wihak held a management position at
Sunoma Energy Corp./Barrington Petroleum Ltd. from 1997 to 2001. Prior to
that, he was a senior exploitation engineer with Summit Resources Ltd. from
1993 to 1996.
10. Mr. Kousinioris joined Bennett Jones LLP in 1990. From February 1997 until
September 1998, Mr. Kousinioris practiced with a leading law firm in
London, England, following which, he returned to Bennett Jones LLP and is
currently a partner in the Corporate/Commercial Department.
CONFLICTS OF INTEREST
Circumstances may arise where members of the board of directors of
Ventures and AcquireCo serve as directors or officers of corporations which are
in competition to the interests of Ventures Trust, AcquireCo and the Trust. No
assurances can be given that opportunities identified by such board members will
be provided to Ventures Trust, AcquireCo and the Trust.
C-52
ADDITIONAL INFORMATION
Additional information relating to the Trust may be found on SEDAR at
www.sedar.com.
Additional information, including information concerning remuneration
and indebtedness of the directors and officers of Ventures, AcquireCo, the
Manager and Ultima Energy, principal holders of Trust Units, any Rights to
purchase Trust Units, and interests of insiders in material transactions, if
applicable, is contained in the Information Circular prepared in relation to the
Annual and Special Meeting of Unitholders to be held on June 4, 2004 and
additional financial information is provided in the financial statements and
Management's Discussion & Analysis of the Trust and the Trust's subsidiaries for
the year ended December 31, 2003.
At any time, upon request made to the Chief Financial Officer of the
Manager, the Manager will provide to any person or company:
a) when the securities of the Trust are in the course of a
distribution under a preliminary short form prospectus or a short
form prospectus,
i) one copy of this Annual Information Form of the Trust, together
with one copy of any document, or the pertinent pages of any
document incorporated by reference in this Annual Information
Form,
ii) one copy of the comparative financial statements of the Trust for
its most recently completed financial year for which financial
statements have been filed together with the accompanying report
of the auditor and one copy of the most recent interim financial
statements of the Trust that have been filed, if any, for any
period after the end of its most recently completed financial
year,
iii) one copy of the information circular of the Trust in respect of
its most recent annual meeting of Unitholders that involved the
election of directors or one copy of any annual filing prepared
instead of the information circular, as appropriate, and
iv) one copy of any other documents that are incorporated by
reference into the preliminary short form prospectus or the short
form prospectus and are not required to be provided under clauses
(i) (ii) or (iii); or
b) at any other time, one copy of any documents referred to in
clauses (a) (i), (ii), and (iii), provided that the Manager may
require the payment of a reasonable charge if the request is made
by a person or company who is not a Unitholder.
The Chief Financial Officer of the Manager can be contacted as follows:
Ultima Management Inc.
1000, 350 - 7th Avenue SW
Calgary, AB T2P 3N9
Attention: Chief Financial Officer
C-53
EXHIBIT "A"
FORM 51-101F2
REPORT ON RESERVES DATA BY
INDEPENDENT QUALIFIED RESERVES
EVALUATOR
Report on Reserves Data
To the board of directors of Ultima Ventures Corp., on behalf of Ultima Energy
Trust and its affiliates (collectively referred to herein as "Ultima"):
1. We have evaluated Ultima's reserves data as at December 31, 2003. The
reserves data consist of the following:
(a) (i) proved and proved plus probable oil and gas reserves
estimated as at December 31, 2003 using forecast prices and
costs; and
(ii) the related estimated future net revenue; and
(b) (i) proved oil and gas reserves estimated as at December 31,
2003 using constant prices and costs; and
(ii) the related estimated future net revenue.
2. The reserves data are the responsibility of Ultima's management. Our
responsibility is to express an opinion on the reserves data based on
our evaluation.
We carried out our evaluation in accordance with standards set out in
the Canadian Oil and Gas Evaluation Handbook (the "COGE Handbook")
prepared jointly by the Society of Petroleum Evaluation Engineers
(Calgary Chapter) and the Canadian Institute of Mining, Metallurgy &
Petroleum (Petroleum Society).
3. Those standards require that we plan and perform an evaluation to
obtain reasonable assurance as to whether the reserves data are free of
material misstatement. An evaluation also includes assessing whether
the reserves data are in accordance with principles and definitions
presented in the COGE Handbook.
4. The following table sets forth the estimated future net revenue (before
deduction of income taxes) attributed to proved plus probable reserves,
estimated using forecast prices and costs and calculated using a
discount rate of 10 percent, included in the reserves data of Ultima
evaluated by us for the year ended December 31, 2003, and identifies
the respective portions thereof that we have evaluated and reported on
to Ultima's board of directors:
C-54
Location of
Reserves
(Country or Net Present Value of Future Net Revenue, M$
Independent Qualified Description and Foreign (before income taxes, 10% discount rate)
Reserves Evaluator or Preparation Date of Geographic --------------------------------------------
Auditor Evaluation Report Area) Evaluated Total
--------------------- ----------------- ----------- -------------------- ---------------
McDaniel & Associates 100% of all reserves Canada $216,479 $216,479
Consultants Ltd. excluding Weyburn
Unit NRI
March 8, 2004
Gilbert Laustsen Weyburn Unit NRI Canada $84,630 $84,630
Jung Associates Ltd. March 1, 2004
Totals $301,109 $301,109
5. In our opinion, the reserves data respectively evaluated by us have, in
all material respects, been determined and are in accordance with the
COGE Handbook. We have no responsibility to update our reports referred
to in paragraph 4 for events and circumstances occurring after their
respective preparation dates.
6. Because the reserves data are based on judgments regarding future
events, actual results will vary and the variations may be material.
Executed as to our report referred to above:
April 28, 2004, Calgary, Alberta, Canada.
McDaniel & Associates Consultants Ltd.
(Signed) P.A. Welch, P.Eng.
Executive Vice President
Gilbert Laustsen Jung Associates Ltd.
(Signed) Dana B. Laustsen, P.Eng.
Executive Vice President
C-55
EXHIBIT "B"
FORM 51-101F3
REPORT OF
MANAGEMENT AND DIRECTORS
ON OIL AND GAS DISCLOSURE
Management of Ultima Ventures Corp. (the "Company"), for and on behalf of Ultima
Energy Trust (the "Trust") are responsible for the preparation and disclosure of
information with respect to the Trust's oil and gas activities in accordance
with securities regulatory requirements. This information includes reserves
data, which consist of the following:
(a) (i) proved and proved plus probable oil and gas reserves estimated as at
December 31, 2003 using forecast prices and costs; and
(ii) the related estimated future net revenue; and
(b) (i) proved oil and gas reserves estimated as at December 31, 2003 using
constant prices and costs; and
(ii) the related estimated future net revenue.
An independent qualified reserves evaluator has evaluated and reviewed the
Trust's reserves data. The report of the independent qualified reserves
evaluator is presented below.
The Reserves Committee of the board of directors of the Company has
(c) reviewed the Company's procedures for providing information to the
independent qualified reserves evaluator;
(d) met with the independent qualified reserves evaluator to determine whether
any restrictions affected the ability of the independent qualified reserves
evaluator to report without reservation; and
(e) reviewed the reserves data with management and the independent qualified
reserves evaluator.
The Reserves Committee of the board of directors has reviewed the Company's
procedures for assembling and reporting other information associated with oil
and gas activities and has reviewed that information with management. The board
of directors has, on the recommendation of the Reserves Committee, approved
(f) the content and filing with securities regulatory authorities of the
reserves data and other oil and gas information;
(g) the filing of the report of the independent qualified reserves evaluator on
the reserves data; and
(h) the content and filing of this report.
C-56
Because the reserves data are based on judgments regarding future events, actual
results will vary and the variations may be material.
(Signed) S. Brian Gieni (Signed) Michael P. Wihak
S. Brian Gieni Michael P. Wihak, P.Eng.
President & Chief Executive Officer Chief Operating Officer
(Signed) John M. Gunn (Signed) Arthur E. Dumont
John M. Gunn, P.Eng. Arthur E. Dumont, P.Eng.
Director, Chairman Reserves Committee Director
April 30, 2004
C-57
EXHIBIT "C"
AUDITORS' REPORT
--------------------------------------------------------------------------------
To the Directors
Trioco Resources Inc.
We have audited the balance sheets of Trioco Resources Inc. as at December 31,
2002 and 2001 and the statements of income and retained earnings and cash flows
for the years ended December 31, 2002 and December 31, 2001. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with Canadian generally accepted auditing
standards. Those standards require that we plan and perform an audit to obtain
reasonable assurance whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
In our opinion, these financial statements present fairly, in all material
respects, the financial position of the Company as at December 31, 2002 and 2001
and the results of its operations and its cash flows for the years ended
December 31, 2002 and December 31, 2001 in accordance with Canadian generally
accepted accounting principles.
(signed) "Collins Barrow Calgary LLP"
CHARTERED ACCOUNTANTS
Calgary, Alberta
March 31, 2003
(except for note 9 which
is dated June 20, 2003)
C-58
TRIOCO RESOURCES INC.
BALANCE SHEETS
-----------------------------------------------------------------------------------------------------------------------
March 31, December 31, December 31,
2003 2002 2001
-----------------------------------------------------------------------------------------------------------------------
(unaudited)
Assets
Current assets
Cash and cash equivalents $ 1,223,850 $ - $ 641,890
Accounts receivable 3,616,027 2,252,365 906,903
Income taxes recoverable - 2,300 -
Prepaid expenses and deposits 199,825 235,588 250,040
-----------------------------------------------------------------------------------------------------------------------
5,039,702 2,490,253 1,798,833
Property and equipment (note 3) 40,854,374 37,782,659 22,590,123
-----------------------------------------------------------------------------------------------------------------------
$45,894,076 $ 40,272,912 $24,388,956
-----------------------------------------------------------------------------------------------------------------------
Liabilities
Current liabilities
Bank overdraft $ - $ 290,684 $ -
Accounts payable and accrued liabilities 4,701,451 3,084,635 1,675,625
Income taxes payable - - 30,375
Bank loan (note 4) 10,000,000 14,090,000 4,000,000
-----------------------------------------------------------------------------------------------------------------------
14,701,451 17,465,319 5,706,000
Future removal and site restoration costs 67,233 53,005 16,919
Future income taxes (note 5) 2,990,442 2,111,128 570,894
-----------------------------------------------------------------------------------------------------------------------
17,759,126 19,629,452 6,293,813
-----------------------------------------------------------------------------------------------------------------------
Shareholders' Equity
Share capital (note 6) 23,350,940 17,343,440 17,343,440
Retained earnings 4,784,010 3,300,020 751,703
-----------------------------------------------------------------------------------------------------------------------
28,134,950 20,643,460 18,095,143
-----------------------------------------------------------------------------------------------------------------------
$45,894,076 $ 40,272,912 $24,388,956
-----------------------------------------------------------------------------------------------------------------------
Approved by the Board,
(signed) "David J. Macfie" , Director
---------------------------
(signed) "Donna J. Yee-Kwan" , Director
---------------------------
C-59
TRIOCO RESOURCES INC.
STATEMENTS OF INCOME AND RETAINED EARNINGS
-----------------------------------------------------------------------------------------------------------------------
Three months ended Year ended Year ended
March 31, March 31, December 31, December 31,
2003 2002 2002 2001
-----------------------------------------------------------------------------------------------------------------------
(unaudited)
Revenue
Petroleum and natural gas sales $ 5,857,863 $ 3,807,397 $ 12,314,559 $ 4,971,277
Less: Royalties, net of Alberta Royalty Tax Credit (1,392,521) (420,583) (1,955,588) (969,465)
Interest and other 5,783 1,642 1,921 327,347
-----------------------------------------------------------------------------------------------------------------------
4,471,125 3,388,456 10,360,892 4,329,159
-----------------------------------------------------------------------------------------------------------------------
Expenses
Production 685,417 464,124 1,961,335 763,430
General and administrative 236,899 225,441 983,374 638,505
Interest on bank loan 132,039 58,688 377,472 165,134
Depletion and depreciation 1,036,166 695,547 2,890,292 1,403,262
-----------------------------------------------------------------------------------------------------------------------
2,090,521 1,443,800 6,212,473 2,970,331
-----------------------------------------------------------------------------------------------------------------------
Income before income taxes 2,380,604 1,944,656 4,148,419 1,358,828
-----------------------------------------------------------------------------------------------------------------------
Income taxes (note 5)
Capital 17,300 8,032 59,868 30,375
Future 879,314 697,484 1,540,234 576,450
-----------------------------------------------------------------------------------------------------------------------
896,614 705,516 1,600,102 606,825
-----------------------------------------------------------------------------------------------------------------------
Net income 1,483,990 1,239,140 2,548,317 752,003
Retained earnings (deficit), beginning of period 3,300,020 751,703 751,703 (300)
-----------------------------------------------------------------------------------------------------------------------
Retained earnings, end of period $ 4,784,010 $ 1,990,843 $ 3,300,020 $751,703
-----------------------------------------------------------------------------------------------------------------------
Earnings per share (note 6[g]) $ 0.07 $ 0.07 $ 0.14 $ 0.04
Basic
-----------------------------------------------------------------------------------------------------------------------
Diluted $ 0.07 $ 0.07 $ 0.13 $ 0.04
-----------------------------------------------------------------------------------------------------------------------
C-60
TRIOCO RESOURCES INC.
STATEMENTS OF CASH FLOWS
-----------------------------------------------------------------------------------------------------------------------
Three months ended Year ended Year ended
March 31, March 31 December 31, December 31,
2003 2002 2002 2001
-----------------------------------------------------------------------------------------------------------------------
(unaudited)
Operating activities
Net income $ 1,483,990 $ 1,239,140 $ 2,548,317 $ 752,003
Add items not requiring cash
Depletion and depreciation 1,036,166 695,547 2,890,292 1,403,262
Future income taxes 879,314 697,484 1,540,234 576,450
-----------------------------------------------------------------------------------------------------------------------
Funds from operations 3,399,470 2,632,171 6,978,843 2,731,715
Changes in non-cash working capital (882,033) 425,514 (267,833) (440,913)
-----------------------------------------------------------------------------------------------------------------------
2,517,437 3,057,685 6,711,010 2,290,802
-----------------------------------------------------------------------------------------------------------------------
Financing activities
Proceeds from (repayment of) bank loan, net (4,090,000) (500,000) 10,090,000 4,000,000
Proceeds from issuance of share capital, net 6,007,500 - - 17,087,884
-----------------------------------------------------------------------------------------------------------------------
1,917,500 (500,000) 10,090,000 21,087,884
-----------------------------------------------------------------------------------------------------------------------
Investing activities
Capital, exploration and development
expenditures, net (4,093,653) (1,043,395) (18,042,908) (23,971,666)
Removal and site restoration costs - - (3,834) -
Changes in non-cash working capital 1,173,250 (385,925) 313,158 997,668
-----------------------------------------------------------------------------------------------------------------------
(2,920,403) (1,429,320) (17,733,584) (22,973,998)
-----------------------------------------------------------------------------------------------------------------------
Cash inflow (outflow) 1,514,534 1,128,365 (932,574) 404,688
Cash and cash equivalents (bank overdraft),
beginning of period (290,684) 641,890 641,890 237,202
-----------------------------------------------------------------------------------------------------------------------
Cash and cash equivalents (bank overdraft), end
of period $ 1,223,850 $ 1,770,255 $ (290,684) $ 641,890
-----------------------------------------------------------------------------------------------------------------------
Supplemental cash flows disclosure:
Interest paid $ 132,039 $ 58,688 $ 377,472 $ 165,134
-----------------------------------------------------------------------------------------------------------------------
Capital taxes paid $ 17,300 $ - $92,543 $ -
-----------------------------------------------------------------------------------------------------------------------
C-61
TRIOCO RESOURCES INC.
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2002 AND DECEMBER 31, 2001
(Information as at March 31, 2003 and for the three-month periods ended March
31, 2003 and March 31, 2002 are unaudited)
--------------------------------------------------------------------------------
1. Company activities
The Company was incorporated under the laws of Alberta by Articles of
Incorporation dated October 30, 2000. The Company is engaged in the
exploration for and development of petroleum and natural gas properties in
western Canada.
2. Summary of significant accounting policies
These financial statements have been prepared using accounting principles
generally accepted in Canada which include:
(a) Cash and cash equivalents
Cash and cash equivalents consist of amounts on deposit with banks and
highly liquid investments with maturities of 90 days or less at issue.
(b) Petroleum and natural gas exploration and development expenditures
(i) Capitalized costs
The Company follows the Canadian full cost method of accounting
whereby all costs related to the exploration for and the
development of petroleum and natural gas reserves are initially
capitalized and accumulated in cost centres by country. Costs
capitalized include land acquisition costs, geological and
geophysical expenditures, rentals on undeveloped properties,
costs of drilling productive and non-productive wells, together
with overhead and interest directly related to exploration and
development activities and lease and well equipment. Proceeds
from the disposition of properties will be applied as a reduction
of the cost of the remaining assets, except when a significant
disposition occurs, in which case a gain or loss on disposal is
recorded. Gains or losses are not recognized upon disposition of
petroleum and natural gas properties unless such a disposition
would significantly alter the related cost centre's rate of
depletion and depreciation. A significant disposition would cause
a change of 20% or more in an annual depletion and depreciation
rate.
(ii) Future capital costs
In addition to the capitalized costs incurred to date in the
exploration and development of petroleum and natural gas
properties, the operations and further development require future
expenditures. For purposes of calculating depletion and
depreciation expense and the ceiling test, estimates of future
expenditures and recoveries have been prepared for:
- future development costs of proven developed and undeveloped
reserves as determined by independent and Company engineers;
- site restoration costs as determined by management; and
- net realizable value of production equipment and facilities
after proven reserves are fully produced as determined by
management.
C-62
TRIOCO RESOURCES INC.
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2002 AND DECEMBER 31, 2001
(Information as at March 31, 2003 and for the three-month periods ended March
31, 2003 and March 31, 2002 are unaudited)
--------------------------------------------------------------------------------
(iii) Depletion and depreciation
Costs capitalized are depleted and depreciated using the
unit-of-production method by cost centre based upon gross proven
developed and undeveloped petroleum and natural gas reserves as
determined by independent and Company engineers. For purposes of
the calculation, petroleum and natural gas reserves are converted
to a common unit of measure on the basis of their relative energy
content, whereby one barrel of oil is equivalent to six thousand
cubic feet of natural gas.
The cost of significant unproved properties are excluded from the
depletion and depreciation base until it is determined whether
proved reserves are attributable to the properties, or impairment
has occurred.
(iv) Future removal and site restoration costs
Estimated future removal and site restoration costs are provided
for over the life of the proven reserves on a unit-of-production
basis. Costs which include the cost of production equipment
removal and environmental clean-up are estimated each year by
management based on current regulations, costs, technology and
industry standards. The current site restoration provision
represents the annual recognition of such expense based upon
production volumes of that year. The annual charge is included in
the provision for depletion and depreciation and the actual
restoration expenditures are charged to the accumulated provision
account as incurred.
(v) Ceiling test
In applying the full cost method, the Company performs a ceiling
test which restricts the capitalized costs less accumulated
depletion and depreciation, future income taxes and future site
restoration for each cost centre from exceeding an amount equal
to the estimated undiscounted value of future net revenues from
proven petroleum and natural gas reserves, based on year-end
prices and costs, and after deducting estimated future
production-related general and administrative expenses, estimated
future removal and site restoration costs, financing costs and
applicable income and capital taxes.
(vi) Measurement uncertainty
The amounts recorded for depletion and depreciation of
exploration and development costs, the provision for future
removal and site restoration costs and the ceiling test are based
on estimated proven reserves, production rates, future petroleum
and natural gas prices and future costs. By their nature, these
estimates are subject to measurement uncertainty and the effect
of changes in such estimates in future periods could be
significant.
C-63
TRIOCO RESOURCES INC.
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2002 AND DECEMBER 31, 2001
(Information as at March 31, 2003 and for the three-month periods ended March
31, 2003 and March 31, 2002 are unaudited)
--------------------------------------------------------------------------------
(c) Depreciation
Other assets are depreciated using the straight-line method at an
annual rate of 20%.
(d) Bank loan
Effective for the period commencing January 1, 2002, the Canadian
Institute of Chartered Accountants ("CICA") amended Generally Accepted
Accounting Principles to require all bank loans, where the lender has
the right to demand repayment within 12 months (other than in the
event of default or breach of covenants), to be classified as current
liabilities. Since the Company's debt is of a demand nature, this loan
has been classified as current. The bank loan at December 31, 2001 has
been restated to conform with the current presentation. The Company is
not in breach of any covenants under its credit facility.
(e) Income taxes
Income taxes are accounted for using the liability method of income
tax allocation. Under the liability method, income tax assets and
liabilities are recorded to recognize future income tax inflows and
outflows arising from the settlement or recovery of assets and
liabilities at the carrying values. Income tax assets are also
recognized for the benefits from tax losses and deductions that cannot
be identified with particular assets or liabilities, provided those
benefits are more likely than not to be realized. Future income tax
assets and liabilities are determined based on the tax laws and rates
that are anticipated to apply in the year of realization.
(f) Flow-through shares
The Company, from time to time, issues flow-through shares to finance
a portion of its capital expenditure program. Pursuant to the terms of
the flow-through share agreements, the tax deductions associated with
the expenditures are renounced to the subscribers. Accordingly, share
capital is reduced and a future tax liability is recorded equal to the
estimated amount of future income taxes payable by the Company as a
result of the renunciations, when the expenditures are incurred.
(g) Stock-based compensation
The Company has three stock-based compensation plans as described in
note 6(e).
Stock options granted to non-employees are accounted for using the
fair value method under which compensation expense is recorded based
on the estimated fair value of the options at the grant date.
No compensation expense is recognized when stock options are issued to
directors, officers and employees. Any consideration received by the
Company on exercise of stock options is credited to share capital.
C-64
TRIOCO RESOURCES INC.
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2002 AND DECEMBER 31, 2001
(Information as at March 31, 2003 and for the three-month periods ended March
31, 2003 and March 31, 2002 are unaudited)
--------------------------------------------------------------------------------
On January 1, 2002, the CICA issued Section 3870, Stock-Based
Compensation and Other Stock-Based Payments, which requires
disclosure, on a pro-forma basis, had compensation expense for the
stock options been determined using the fair value method. The Company
elected to defer the application of this Section until fiscal years
beginning after January 1, 2003 as allowed for private companies under
Section 3870.
Effective January 1, 2003, the Company adopted prospectively Section
3870 with respect to accounting for stock-based compensation
arrangements. The Company has elected to use the intrinsic value-based
method of accounting for its stock option plans, whereby, no
compensation expense is recorded for stock options issued to
directors, officers and employees that have an exercise price equal to
the fair value of the stock at the date options are granted. The
Company disclosed in note 6(f) the pro-forma results of using the fair
value method, under which compensation expense is recorded based upon
the estimated fair value of the options. Pro-forma results will be
presented only for the effects of options granted subsequent to
January 1, 2003.
The amounts disclosed related to fair values of stock options issues,
and the resultant pro-forma income effects (note 6[f]) are based on
estimates of future volatility of the Company's share price, expected
lives of the options, expected dividends to be paid by the Company and
other relevant assumptions. By their nature, these estimates are
subject to measurement uncertainty and the effect of changes in such
estimates on the financial statements of future periods could be
significant.
(h) Revenue recognition
Revenue from the sale of petroleum and natural gas is recognized based
on volumes delivered to customers at contractual delivery points and
rates. The costs associated with the delivery, including operating and
maintenance costs, transportation and production-based royalty
expenses are recognized in the same period in which the related
revenue is earned and recorded.
(i) Earnings per share
The treasury stock method is used for the calculation of diluted
earnings per share. This method assumes that the proceeds on the
exercise of stock options are used to repurchase Company shares at a
price of $1.50 (March 31, 2002 - $1.29; December 31, 2002 - $1.50;
December 31, 2001 - $1.29).
(j) Joint venture accounting
Substantially all of the Company's exploration and production
activities are conducted jointly with others, and accordingly, these
financial statements reflect only the Company's proportionate interest
in such activities.
C-65
TRIOCO RESOURCES INC.
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2002 AND DECEMBER 31, 2001
(Information as at March 31, 2003 and for the three-month periods ended March
31, 2003 and March 31, 2002 are unaudited)
--------------------------------------------------------------------------------
(k) Hedging activities
The Company, from time to time, enters into forward contracts and swap
agreements to hedge its exposure to the risks associated with
fluctuating petroleum and natural gas prices. The purpose of the hedge
is to lock in the price for a portion of the Company's production.
Gains and losses associated with risk management activities are
recorded as adjustments to the production revenue at the time the
related production is sold.
The Company identifies all relationships between the hedging
instruments and hedged production, as well as its risk management
objective and strategy for undertaking various risk management
transactions. The Company believes that the risk management activities
are effective hedges, both at inception and over the term of the
contracts. The contracts entered into are not speculative derivative
transactions.
3. Property and equipment
----------------------------------------------------------
March 31, December 31,
2003 2002 2001
----------------------------------------------------------
Petroleum and natural gas properties including
exploration and development thereon $ 35,747,299 $ 32,605,460 $ 18,271,867
Production equipment and facilities 10,275,665 9,340,170 5,640,708
Other 90,063 73,744 63,891
----------------------------------------------------------
46,113,027 42,019,374 23,976,466
Accumulated depletion and depreciation 5,258,653 4,236,715 1,386,343
----------------------------------------------------------
$ 40,854,374 $ 37,782,659 $ 22,590,123
----------------------------------------------------------
Future removal and site restoration costs are estimated in aggregate to be
$675,000 (March 31, 2002 - $300,000; December 31, 2002 - $600,000; December
31, 2001 - $300,000) of which $14,228 (March 31, 2002 - $8,565; December
31, 2002 - $39,920; December 31, 2001 - $16,919) has been charged to income
in the current period.
During the period, the Company capitalized $14,352 (March 31, 2002 -
$29,383; December 31, 2002 - $99,209; December 31, 2001 - $114,134) of a
total of $251,251 (March 31, 2002 - $254,824; December 31, 2002 -
$1,082,583; December 31, 2001 - $752,639) in general and administrative
expenses. No interest has been capitalized.
Costs of unproven petroleum and natural gas properties in the amount of
$1,337,983 (March 31, 2002 - $919,700; December 31, 2002 - $1,337,983;
December 31, 2001 - $919,700) have been excluded from costs subject to
depletion.
C-66
TRIOCO RESOURCES INC.
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2002 AND DECEMBER 31, 2001
(Information as at March 31, 2003 and for the three-month periods ended March
31, 2003 and March 31, 2002 are unaudited)
--------------------------------------------------------------------------------
4. Bank loan
The Company has available a demand revolving credit facility to a maximum
of $17,000,000. The loan is available to the Company by way of prime rate
loans, banker's acceptances and letters of credit. The production loan
bears interest at a Canadian chartered bank's prime rate plus 0.75% per
annum or banker's acceptance rates plus stamping fees of 1.75% per annum.
The Company has provided security for the facility by way of a $25,000,000
floating charge demand debenture on all assets, a general assignment of
book debts and a specific assignment of certain natural gas contracts. As
of March 31, 2003, $10,000,000 has been drawn down on the facility.
The facility revolves for a period of 364 days, is scheduled for renewal on
May 31, 2003 and may be extended upon the written consent of the bank.
Under the terms of the agreement, the Company is required to meet certain
financial and engineering reporting requirements and may not breach certain
financial tests without prior consent of the bank.
5. Income taxes
(a) Significant components of the future income tax liability are as
follows:
----------------------------------------------------------
March 31, December 31,
2003 2002 2001
----------------------------------------------------------
Temporary differences related
to property and equipment
and future site restoration $ 3,049,859 $ 2,175,553 $ 652,867
Share issuance costs (31,052) (47,647) (64,113)
Attributed Royalty Income
deduction carryforward (28,365) (16,778) (17,860)
----------------------------------------------------------
$ 2,990,442 $ 2,111,128 $ 570,894
----------------------------------------------------------
(b) Income tax expense differs from that which would be expected from
applying the combined Canadian federal and provincial income tax rates
of 41.12% (March 31, 2002 - 42.12%; December 31, 2002 - 42.12%;
December 31, 2001 - 42.62%) to income before income taxes. The
difference results from the following:
C-67
TRIOCO RESOURCES INC.
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2002 AND DECEMBER 31, 2001
(Information as at March 31, 2003 and for the three-month periods ended March
31, 2003 and March 31, 2002 are unaudited)
--------------------------------------------------------------------------------
------------------------------------------------------------------------------------------------------------------
Three months ended Year ended Year ended
March 31, March 31, December 31, December 31,
2003 2002 2002 2001
------------------------------------------------------------------------------------------------------------------
Expected income tax provision $ 978,904 $ 819,089 $ 1,747,314 $ 579,132
Increase (decrease) resulting from:
Resource allowance (503,361) (298,225) (886,031) (324,259)
Non-deductible crown payments, net of
Alberta Royalty Tax Credit 453,633 180,542 680,924 319,644
Change in value of tax reserves due
to tax reassessments and change in
tax rates (50,522) (3,922) (3,922) -
Other 660 - 1,949 1,933
------------------------------------------------------------------------------------------------------------------
Future income taxes 879,314 697,484 1,540,234 576,450
Capital tax 17,300 8,032 59,868 30,375
------------------------------------------------------------------------------------------------------------------
Reported tax provision $ 896,614 $ 705,516 $ 1,600,102 $ 606,825
------------------------------------------------------------------------------------------------------------------
6. Share capital
(a) Authorized
Unlimited number of voting common shares
Unlimited number of voting, convertible preferred shares
Preferred shares are converted into common shares on a 1:1 ratio.
Preferred shares share rateably with common shares in any dividends,
as and when declared. The holders of preferred shares and common
shares vote together as a single class.
C-68
TRIOCO RESOURCES INC.
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2002 AND DECEMBER 31, 2001
(Information as at March 31, 2003 and for the three-month periods ended March
31, 2003 and March 31, 2002 are unaudited)
--------------------------------------------------------------------------------
(b) Issued
-------------------------------------------------------------------------------------------------------------------
December 31,
March 31, 2003 2002 2001
Common Shares Number Stated Value Number Stated Value Number Stated Value
-------------------------------------------------------------------------------------------------------------------
Balance, beginning of 921,060 $ 921 921,060 $ 921 5,000,000 $ 250,000
period
Issued for cash 4,005,000 6,007,500 - - 921,060 921
Conversion to
preferred shares
(note 6[c]) - - - - (3,500,000) (175,000)
Surrender of
common shares
(note 6[d]) - - - - (1,500,000) (75,000)
-------------- -------------- -------------- -------------- -------------- --------------
Balance, end of 4,926,060 6,008,421 921,060 921 921,060 921
period
============== -------------- ============== -------------- ============== --------------
Preferred Shares
Balance beginning of
period 17,525,000 17,525,000 17,525,000 17,525,000 - -
Issued for cash - - - - 17,350,000 17,350,000
On conversion of
common shares
(note 6[c]) - - - - 175,000 175,000
-------------- -------------- -------------- -------------- -------------- --------------
17,525,000 17,525,000 17,525,000 17,525,000 17,525,000 17,525,000
============== -------------- ============== -------------- ============== --------------
23,533,421 17,525,921 17,525,921
Less: Share
issuance
costs, net of
income tax
benefit of
$80,141 (107,896) (107,896) (107,896)
Reduction
due to income
tax
deductions
renounced to
subscribers (74,585) (74,585) (74,585)
-------------- -------------- --------------
Balance, end of period $ 23,350,940 $ 17,343,440 $ 17,343,440
============== ============== ==============
(c) In conjunction with financing provided by Natural Gas Partners VI
L.P., the existing shareholders converted 3,500,000 common shares to
175,000 preferred shares.
(d) In conjunction with financing provided by Natural Gas Partners VI
L.P., the existing shareholders surrendered 1,500,000 common shares
for $75,000.
C-69
TRIOCO RESOURCES INC.
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2002 AND DECEMBER 31, 2001
(Information as at March 31, 2003 and for the three-month periods ended March
31, 2003 and March 31, 2002 are unaudited)
--------------------------------------------------------------------------------
(e) Stock option plans
At March 31, 2003 the Company has three stock option plans which are
described below.
(i) Time vesting options
Under the Company's time vesting option plan, the Company may
grant options to its directors, officers, employees and
consultants. The maximum number of shares which may be reserved
for issuance under the plan is 2,071,780 common shares. The
initial exercise price of the options is $1.00 and escalates by a
factor of 10% per annum effective January 23, 2002. Options
granted under the plan will expire January 23, 2006. All options
granted vest one-third on each of the first, second and third
anniversary dates of the granting of the options.
A summary of the status of the Company's time vesting stock
option plan, as at March 31, 2003, December 31, 2002 and December
31, 2001 and changes during the periods then ending are as
follows:
-----------------------------------------------------------------------------------------
December 31,
March 31, 2003 2002 2001
Number of Exercise Number of Exercise Number of Exercise
Options Price Options Price Options Price
-----------------------------------------------------------------------------------------
Outstanding,
beginning of
period 1,707,740 $ 1.13 1,582,740 $ 1.10 - -
Granted - - 125,000 $ 1.10 1,582,740 $ 1.00
-------------- --------------- ---------------
Outstanding,
end of period 1,707,740 $ 1.13 1,707,740 $ 1.10 1,582,740 $ 1.00
============== =============== ===============
Options
exercisable at
period end 1,096,828 527,580 -
============== =============== ===============
(ii) Performance vesting options
Under the Company's performance vesting option plan, the Company
may grant options to its directors, officers, employees and
consultants. The maximum number of shares which may be reserved
for issuance under the plan is 465,180 common shares. The initial
exercise price of the options is $1.00.
Options granted under the plan will expire January 23, 2006. The
performance vesting options are only exercisable upon the Company
meeting a certain financial benchmark.
C-70
TRIOCO RESOURCES INC.
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2002 AND DECEMBER 31, 2001
(Information as at March 31, 2003 and for the three-month periods ended March
31, 2003 and March 31, 2002 are unaudited)
--------------------------------------------------------------------------------
A summary of the status of the Company performance vesting stock
option plan as of March 31, 2003, December 31, 2002, and December
31, 2001 and changes during the periods then ending are as
follows:
---------------------------------------------------------------------------------------
March 31, December 31,
2003 2002 2001
Number of Exercise Number of Exercise Number of Exercise
Options Price Options Price Options Price
---------------------------------------------------------------------------------------
Outstanding,
beginning of
period 381,126 $ 1.00 354,126 $ 1.00 - -
Granted - - 27,000 $ 1.00 354,126 $ 1.00
--------------- ---------------- ----------------
Outstanding,
end of period 381,126 $ 1.00 381,126 $ 1.00 354,126 $ 1.00
=============== ================ ================
Options
exercisable at
period end - - -
=============== ================ ================
(iii) New time vesting options
On January 23, 2003, the Company created a third stock option
plan entitled "New Time Vesting Options". The maximum number of
shares which may be reserved for issuance under the plan is
444,444 common shares. The exercise price of the options is set
at $1.50. Options granted under the plan will expire January 23,
2006. All options granted vest two-thirds on the grant date and
one-third on the first anniversary date of the grant date. On
January 23, 2003, 444,444 options were granted to employees under
the plan and 296,296 are exercisable at March 31, 2003.
(f) Stock-based compensation expense
On January 23, 2003, the Company issued New Time Vesting Options to
employees of the Company to purchase 444,444 common shares at a price of
$1.50 per option. On a pro forma basis, had compensation expense for the
stock options been determined based on the fair value method, the Company's
net income and earnings per share for the period ended March 31, 2003 would
have been as follows:
Net income As reported $ 1,483,990
Pro-forma $ 1,448,435
Earnings per share - As reported - basic $ 0.07
- diluted $ 0.07
Earnings per share - Pro forma - basic $ 0.07
- diluted $ 0.07
The fair value of the stock options at the date of grant was estimated
using the Black-Scholes model with the assumptions being a risk free rate
of 2.83%, an expected option life of three years, a share price volatility
of 0% and a zero dividend yield. The
C-71
TRIOCO RESOURCES INC.
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2002 AND DECEMBER 31, 2001
(Information as at March 31, 2003 and for the three-month periods ended March
31, 2003 and March 31, 2002 are unaudited)
--------------------------------------------------------------------------------
total fair value of the options granted was estimated to be $53,333 of
which $35,555 has been recognized for pro forma disclosure.
(g) Per share amounts
Earnings per share has been calculated based on the weighted average number
of common and preferred shares outstanding during the period of 21,472,060
(March 31, 2002 - 18,446,060; December 31, 2002 - 18,446,060; December 31,
2001 - 17,347,314).
Preferred shares are included in the calculation of weighted average number
of shares outstanding as these shares have the same rights and privileges
as common shares.
A reconciliation of the denominators for the per share calculations is
outlined below:
---------------------------------------------------------------
March 31, December 31,
2003 2002 2002 2001
---------------------------------------------------------------
Basic weighted average shares 21,472,060 18,446,060 18,446,060 17,347,314
Effect of dilutive time vesting options 511,039 465,749 552,475 425,319
---------------------------------------------------------------
Diluted weighted average shares 21,983,099 18,911,809 18,998,535 17,772,633
---------------------------------------------------------------
There is no change to the numerator in the calculation of diluted earnings
per share for either year. Performance vesting options are not included in
the calculation of diluted weighted average shares as the performance
criteria has not been satisfied. New Time Vesting Options have not been
included in the calculation of diluted weighted average shares for the
period ended March 31, 2003 as the effect is anti-dilutive.
7. Commitments
The Company is committed under a lease on its office premise expiring April
30, 2004 for future minimum lease payments including estimated operating
costs for the fiscal years ending as follows:
December 31, 2003 $ 65,423
December 31, 2004 29,447
---------------
$ 94,870
===============
C-72
TRIOCO RESOURCES INC.
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2002 AND DECEMBER 31, 2001
(Information as at March 31, 2003 and for the three-month periods ended March
31, 2003 and March 31, 2002 are unaudited)
--------------------------------------------------------------------------------
8. Financial instruments
(a) Fair values
The fair values of the Company's accounts receivable, deposits, bank
overdraft and accounts payable and accrued liabilities are estimated
to approximate their carrying values due to the immediate or
short-term maturity of these financial instruments. The fair value of
the Company's bank loan approximates its carrying value as it bears
interest at variable market rates.
(b) Credit risk
Substantially all of the Company's accounts receivable are due from
companies involved in the petroleum and natural gas industry in Canada
and are, therefore, subject to the same economic risks as the industry
as a whole.
The Company's maximum credit risk exposure is limited to the carrying
value of its accounts receivable of $3,616,027 (December 31, 2002 -
$2,252,365; December 31, 2001 - $906,903). Credit risk is managed by
the Company through diversification of marketing counter parties and
credit monitoring procedures.
(c) Hedging activities
(i) The Company enters into hedge transactions for natural gas sales.
The agreements entered into are forward financial transactions
providing the Company with a range of fixed prices. Net natural
gas sales for the period ended March 31, 2003 include gains
(losses) of ($1,085,851) (March 31, 2002 - $1,743,239; December
31, 2002 - $1,519,943; December 31, 2001 - $404,330) on these
transactions. The fair market value of the hedge contracts equals
the unrecognized loss as described below.
The following hedge transactions are outstanding at March 31,
2003:
----------------------------------------------------------------------------------------------------------
Notional Strike Unrecognized
Commodity Volume Price Term Loss
----------------------------------------------------------------------------------------------------------
Natural gas 1,000 GJ/day $3.575/GJ March 1, 2002 - $(2,494,706)
February 29, 2004
----------------------------------------------------------------------------------------------------------
As per the terms of the hedge agreement, the Company issued a
letter of credit for Cdn. $600,000.
(ii) In order to manage exposure to fluctuations in petroleum and
natural gas prices, the Company entered into forward physical
contracts during the year fixing market prices.
C-73
TRIOCO RESOURCES INC.
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2002 AND DECEMBER 31, 2001
(Information as at March 31, 2003 and for the three-month periods ended March
31, 2003 and March 31, 2002 are unaudited)
--------------------------------------------------------------------------------
The contracts have firm physical delivery obligations and are,
therefore, considered forward commitment contracts, not financial
instruments.
-----------------------------------------------------------------------------------------------------------------
Physical Strike Floor Ceiling
Commodity Volume Price Price Price Term
-----------------------------------------------------------------------------------------------------------------
100
Oil bbls/day - $25/bbl $27.60/bbl November 1, 2002 -
(physical) U.S. U.S. December 31, 2003
2000
Natural gas GJ/day January 1, 2002 -
(physical) $3.95/GJ CDN - - December 31, 2003
-----------------------------------------------------------------------------------------------------------------
9. Subsequent events
(a) On May 1, 2003, the Company granted 364,040 Time Vesting Options with
an exercise price of $1.13 and 84,054 Performance Vesting Options with
an exercise price of $1.00 to employees of the Company.
(b) On June 19, 2003, the Company's directors entered into an agreement to
sell all of the issued and outstanding common and preferred shares of
the Company to Ultima Acquisition Corp. at a price of $2.47 per share.
The transaction is expected to close June 26, 2003. All options
outstanding will vest immediately.
C-74
EXHIBIT "D"
Compilation Report
To the Directors of Ultima Ventures Corp. and Ultima Acquisitions Corp.:
We have read the accompanying unaudited pro forma combined statement of income
of Ultima Energy Trust (the "Trust") for the year ended December 31, 2003 and
have performed the following procedures:
1. Compared the figures in the columns captioned "Ultima" to the audited
consolidated financial statements of the Trust for the year ended December
31, 2003 and found them to be in agreement.
2. Compared the figures in the columns captioned "Trioco" to the unaudited
financial statements of Trioco Resources Inc. ("Trioco") for the three
months ended March 31, 2003 and the unaudited financial records of Trioco
for the period from April 1, 2003 to June 25, 2003 and found them to be in
agreement.
3. Made enquiries of certain officials of the Trust who have responsibility
for financial and accounting matters about:
(a) the basis for determination of the pro forma adjustment; and
(b) whether the pro forma combined financial statement complies as to form
in all material respects with the regulatory requirements of the
various securities commissions and regulatory authorities in Canada.
The officials of the Trust:
(a) described to us the basis for determination of the pro forma
adjustments, and
(b) stated that the pro forma combined financial statement complies as to
form in all material respects with the regulatory requirements of the
various securities commissions and regulatory authorities in Canada.
4. Read the notes to the pro forma combined financial statement, and found
them to be consistent with the basis described to us for determination of
the pro forma adjustments.
5. Recalculated the application of the pro forma adjustments to the aggregate
of the amounts in the columns captioned "Ultima" and "Trioco" for the year
ended December 31, 2003, and found the amounts in the column captioned "Pro
Forma Combined" to be arithmetically correct.
A pro forma financial statement is based on management assumptions and
adjustments which are inherently subjective. The foregoing procedures are
substantially less than either an audit or a review, the objective of which is
the expression of assurance with respect to management's assumptions, the pro
forma adjustments, and the application of the adjustments to the historical
financial information. Accordingly, we express no such assurance. The foregoing
procedures would not necessarily reveal matters of significance to the pro forma
combined financial statement, and we therefore make no representation about the
sufficiency of the procedures for the purposes of a reader of such statements.
Calgary, Alberta, Canada (Signed) Deloitte & Touche LLP
April 30, 2004 Chartered Accountants
C-75
Comments for United States of America Readers on Differences
Between Canadian and United States Reporting Standards
The above opinion, provided solely pursuant to Canadian requirements, is
expressed in accordance with standards of reporting generally accepted in
Canada. Such standards contemplate the expression of an opinion with respect to
the compilation of pro forma financial statements. United States of America
standards do not provide for the expression of an opinion on the compilation of
pro forma financial statements. To report in conformity with United States of
America standards on the reasonableness of the pro forma adjustments and their
application to the pro forma financial statements would require an examination
or review which would be substantially greater in scope than the review as to
compilation only that we have conducted. Consequently, under United States of
America standards, we would be unable to express any opinion with respect to the
compilation of the accompanying unaudited pro forma combined statement of
income.
Calgary, Alberta, Canada (Signed) Deloitte & Touche LLP
April 30, 2004 Chartered Accountants
C-76
Ultima Energy Trust
Pro Forma Combined Statement of Income
For the year ended December 31, 2003
(Unaudited)
(Expressed in thousands of Canadian dollars except, for per unit amounts)
Total
Trioco Trioco Pro Forma Pro Forma
Ultima March 31, 2003 April 1 to June 25 Adjustments Combined
-------------- -------------- ------------- ---------- ------------
Revenue
Oil and natural gas $ 111,107 $ 5,858 $ 3,412 $ - $ 120,377
Royalties (21,810) (1,393) (1,608) (127)2(f) (24,938)
Other - 6 - - 6
- - - -
-------------- -------------- ------------- ---------- ------------
89,297 4,471 1,804 (127) 95,445
Expenses
Oil and natural gas operating 25,485 685 678 - 26,848
General and administrative 9,914 237 4,502 - 2(g) 14,653
Management fee 487 - - 113 2(c) 600
Interest on long-term debt 3,171 132 121 (198)2(b) 3,226
Unit based compensation 260 - - - 260
Capital taxes 76 17 17 - 110
Depletion and amortization 38,526 1,036 1,070 1,389 2(e) 42,021
-------------- -------------- ------------- ---------- ------------
77,919 2,107 6,388 1,304 87,718
Net income before income taxes 11,378 2,364 (4,584) (1,431) 7,727
Future income tax (recovery)/expense (900) 880 (1,785) (550)2(d) (2,355)
-------------- -------------- ------------- ---------- ------------
-
Net Income/(loss) $ 12,278 $ 1,484 $ (2,799) $ (881) $ 10,082
============== ============== ============= ========== ============
Net income per unit, basic $ 0.29 $ - $ - $ 0.20
============== ============== ============= ========== ============
Net income per unit, diluted $ 0.28 $ - $ - $ 0.20
============== ============== ============= ========== ============
C-77
Ultima Energy Trust
Notes to Pro Forma Combined Statement of Income
DECEMBER 31, 2003
(unaudited)
1. BASIS OF PRESENTATION
The accompanying unaudited pro forma combined statement of income for
the year ended December 31, 2003 ("the "Pro Forma Statement") has been
prepared for inclusion in the Proxy Statement and Information Circular
of Ultima Energy Trust ("Ultima" or the "Trust") dated April 30, 2004
(the "Circular"). The Pro Forma Statement gives effect to the
applicable transactions described in Note 2 as if they had occurred on
January 1, 2003.
The Pro Forma Statement has been prepared from:
o The audited consolidated financial statements of Ultima for the
year ended December 31, 2003;
o The unaudited interim financial statements of Trioco for the
three months ended March 31, 2003;
o The unaudited financial records of Trioco for the period April 1,
2003 to June 25, 2003.
The Pro Forma Statement should be read in conjunction with the audited
consolidated financial statements of Ultima for the year ended
December 31, 2003.
In the opinion of management of Ultima, the Pro Forma Statement
includes all material adjustments necessary for fair presentation in
accordance with Canadian generally accepted accounting principles
("Canadian GAAP"). Accounting policies used in the preparation of the
Pro Forma Statement are in accordance with those disclosed in the
audited consolidated financial statements of Ultima for the year ended
December 31, 2003.
The Pro Forma Statement is not necessarily indicative of the results
of operations that would have occurred for the year ended December 31,
2003 nor are they necessarily indicative of the operations of future
periods. In preparing the Pro Forma Statement, no adjustments have
been made to recognize any operating synergies or general and
administrative cost savings that may be expected to occur as a result
of the transactions noted above.
C-78
2. Pro Forma adjustments and assumptions
The Pro Forma Statement gives effect to the following transactions,
adjustments and assumptions:
a) The acquisition of Trioco by a wholly-owned subsidiary of the
Trust for $71,000,000 including adjustments and other costs on
June 26, 2003. The acquisition is accounted for using the
purchase method and the purchase price is allocated as follows:
(000s)
Current assets $ 5,040
Capital assets 71,000
Goodwill 16,682
Current liabilities (3,863)
Future income taxes (15,298)
Future site restoration (67)
------------------------
------------------------
$ 71,000
========================
Paid by
Cash $ 61,000
Bank indebtedness 10,000
assumed
----------------------------
$ 71,000
============================
b) The interest charge on bank debt related to the acquisition, less
the proceeds from the issue of 12,000,000 Trust units for net
proceeds of $59,130,000 pursuant to a prospectus dated July 7,
2003, has been recorded at 4.5% per annum with no deemed
principal repayments.
c) The 3.0% management fee in effect during 2002 and the first three
months of 2003 has been charged on net operating cash flow.
d) Trioco's current taxes have been eliminated. In Ultima's
structure, payments are made between Ultima's related entities
and Ultima, transferring both income and tax liability from the
entities to the unitholders. The future income tax expense has
been adjusted to reflect the impact on earnings at the maximum
statutory rate.
e) Depletion, depreciation and amortization is calculated using the
unit of production method using the total proven oil and natural
gas reserves ascribed by the Trust.
f) Alberta Royalty Tax Credits claimed by Trioco have been
eliminated as Ultima is not eligible to claim these credits.
C-79
(g) Trioco's general and administrative expenses for the period April
1 to June 25, 2003 include severance costs paid to Trioco's
employees and various other non-recurring expenses. No adjustment
has been recognized in this statement for these one-time costs.
3. Per unit information
The calculation of net income per Trust Unit gives effect to the
issuance of the additional Trust Units as set out in Note 2 b) and c)
above.
Weighted average Trust units December 31, 2003
Basic 49,406,224
Diluted 49,959,620
4. Other significant accounting policies
The acquisition of Trioco results in goodwill. This goodwill represents
the excess of the purchase price over the fair value of the assets
acquired and liabilities assumed. It will be assessed at least annually
for impairment and any excess of the book value of goodwill over the
implied fair value will be the amount of the impairment.
5. Application of United States of America GAAP ("U.S. GAAP")
The application of U.S. GAAP would have the following effects on the
pro-forma combined net income and net income per Trust unit of Ultima:
$ Cdn (000's)
Pro-forma combined net income 10,082
Ultima U.S. GAAP adjustments (1) 951
----------------------------------------------------------------------------------------------
Pro-forma combined net income, as adjusted, before 11,033
cumulative effect of change in accounting principle
Cumulative effect of change in accounting principle, net of (1,484)
income taxes
----------------------------------------------------------------------------------------------
Pro-forma combined net income, as adjusted, after cumulative effect 9,549
----------------------------------------------------------------------------------------------
Net income per unit, as adjusted, before cumulative effect
Basic $ 0.22
Dilutive $ 0.22
Net income per unit, as adjusted, after cumulative effect
Basic $ 0.19
Dilutive $ 0.19
(1) As described in Note 14 to Ultima's audited consolidated financial
statements for the year ended December 31, 2003. No further
differences arose as a result of the acquisition of Trioco or the
application of the pro-forma adjustments.
C-80
[LOGO OMITTED]
For the year ended December 31, 2003
Management's Discussion and Analysis ("MD&A")
The following discussion is management's analysis of Ultima Energy Trust
("Ultima" or "the Trust") operating and financial results for the quarter and
year to date ended December 31, 2003 compared with the comparative periods of
2002. This discussion also contains information and opinions concerning the
Trust's future outlook based on currently available information at February 26,
2004, the date of the MD&A. This discussion should be read in conjunction with
the Trust's audited consolidated financial statements for the year ended
December 31, 2003, together with the accompanying notes.
Management uses cash flow (before changes in non-cash working capital) to
analyze financial performance, as one measure to benchmark performance against
peers, and as one measure to determine distribution levels. Cash flow is
calculated as net income for the period plus charges to income not requiring an
outlay of funds less credits to net income not involving a source of funds. Cash
flow as presented does not have any standardized meaning prescribed by Generally
Accepted Accounting Principles in Canada ("GAAP") and therefore it may not be
comparable with the calculation of similar measures by other entities. Cash flow
as presented is not intended to represent operating cash flows or operating
profits for the period nor should it be viewed as an alternative to cash flow
from operating activities, net income or other measures of financial performance
calculated in accordance with GAAP. All references to cash flow throughout this
report are based on cash flow before changes in non-cash working capital.
Reserve volumes and values at December 31, 2003 are based on Ultima's interest
in its total proved and probable reserves prior to royalties as defined in
National Instrument 51-101 - Standards of disclosure for oil and gas activities
("NI 51-101"). Reserve volumes and values for other years and previously
announced acquisitions for the current year, are based on established (proved
plus 50% probable) reserves prior to royalties. Under those definitions,
probable reserves were discounted by an arbitrary risk factor of 50% in
reporting established reserves. Under NI 51-101 reserves definitions, estimates
are prepared such that the full proved and probable reserves are estimated to be
recoverable (proved plus probable reserves are effectively a "most likely
case"). As such the probable reserves now reported are already "risked". Overall
there were no material revisions to Ultima's reserve volumes in transitioning to
NI 51-101.
Forward-Looking Information
The following discussion contains forward looking information with respect to
Ultima. Because forward-looking information relates to future events and
conditions, it involves risks and uncertainties that could cause actual results
to differ materially from those contemplated. The risks and uncertainties
include commodity price levels; currency-exchange rates; the recoverability of
reserves; transportation availability and costs; operating and other costs;
interest rates; and changes in environmental and other legislation and
regulations. This list of factors should not be construed as exhaustive. Please
refer to the Trust's Annual Report and Renewal Annual Information Form for more
details as to these risks and uncertainties. Management believes the
expectations reflected in these forward looking statements are reasonable.
However, there is no assurance that these expectations will prove to be correct.
All calculations required to convert natural gas to crude oil equivalent (boe)
have been made using a ratio of 6 mcf to 1 barrel of crude oil.
C-81
Change in Accounting Policy
In order to be comparable to the majority of its peer group, in 2003 Ultima
adopted the Full Cost Method of accounting for its capital assets pursuant to
the Canadian Institute of Chartered Accountants ("CICA") Accounting Guideline
("AcG") 16 "Oil and Gas Accounting - Full Cost". The accounting policy change
has been adopted retroactively and as a result net income has been restated for
2002 and 2003. The adoption of the Full Cost Method has resulted in net income
for the 2002 and 2003 being substantially equal with that originally reported
under the Successful Efforts Method. The change to the Full Cost Method had no
effect on cash flow as presented for either period. The Full Cost Method and the
Successful Efforts Method are the only two accounting options for the Trust's
capital assets.
In 2003 Ultima adopted CICA section 3870 "Stock Based Compensation and Other
Stock Based Payments". This standard was effective for fiscal years beginning on
January 1, 2004, but early adoption was recommended. Ultima adopted this
standard in 2003. Pursuant to the transitional provisions provided; unit based
compensation expense is to be determined and accrued in income based upon the
fair value of rights issued since January 1, 2003. As a result of the early
adoption of this standard Ultima's net income decreased by $260,000 in 2003.
There was no effect on cash flow.
In February 2003 the CICA issued AcG 14 "Disclosure of Guarantees". This
guideline requires that all guarantees must be disclosed in the notes to the
financial statements, of which there are none. There was no impact on net income
or cash flow as a result of the implementation of this guideline.
Selected Annual Financial Information
The following table sets forth selected consolidated financial information of
Ultima with respect to each of the last three years. This information has been
restated to conform with the change in accounting policy as discussed above.
Selected Annual Financial Information - restated for change in accounting policy
($ thousands except per trust unit amounts)
2003 2002 2001
-------------------------------------------------------------------------------
Revenue, net of royalties 89,297 38,253 28,397
Partnership income - 4,198 3,104
Cash flow (1) 54,880 24,016 17,728
Cash flow, per unit basic (1) 1.29 1.09 1.17
Cash flow, per unit diluted (1) 1.26 1.08 1.15
Cash distributions, per unit 1.09 0.90 1.00
Net income 12,278 9,224 (5,281)
Net income per unit, basic 0.29 0.42 (0.35)
Net income per unit, diluted 0.28 0.41 (0.34)
Total Assets 326,539 218,175 103,359
Total long-term financial liabilities (2) 81,376 78,238 30,209
(1) Excludes internalization costs of $4.7 million (0.11 per unit) in 2003.
For 2003, cash flow in accordance with GAAP is $54.3 million (2002 - $23.2
million).
(2) Includes net bank debt and the deferred capital obligation, excludes future
income taxes and site restoration provision.
Revenue and cash flow have increased over the three year term due to a number of
acquisitions that were completed. Cash distributions per unit have fluctuated
over the term due to commodity price volatility. Partnership income was not
realized in 2003 as the Trust acquired the assets of
C-82
the Weyburn Limited Partnership ("WLP") late in 2002. A net loss per unit was
incurred in 2001 due to a write-down of capital assets pursuant to the adoption
of the Full Cost Method of accounting for capital assets. Net income per unit
has decreased in 2003 due primarily to the internalization of the management
contract and an increase in the number of trust units outstanding.
Selected Quarterly Financial Information
The following table sets forth selected consolidated financial information of
Ultima with respect to each of the last eight financial quarters ending on March
31 ("Q1"), June 30 ("Q2"), September 30 ("Q3") and December 31 ("Q4"),
respectively. This information has been restated to conform with the change in
accounting policy as discussed above.
Selected Quarterly Financial Information - Restated for change in accounting policy
($ thousands except per trust unit amounts)
2003 Q4 2003 Q3 2003 Q2 2003 Q1 2002 Q4 2002 Q3 2002 Q2 2002 Q1
-------------------------------------------------------------------------------------------------------------------------------
Total revenue, net of
royalties 25,712 24,635 19,100 19,850 13,045 8,644 8,782 7,782
Partnership income - - - - 424 1,267 1,420 1,087
Cash flow 15,923 14,950 11,671 12,336 7,351 5,653 5,980 5,032
Cash flow, per unit basic $ 0.30 $ 0.30 $ 0.33 $ 0.36 $ 0.31 $ 0.24 $ 0.27 $ 0.27
Cash distributions 14,187 14,625 10,131 9,192 6,528 5,726 5,137 3,583
Cash distributions per unit $ 0.265 $ 0.285 $ 0.27 $ 0.27 $ 0.24 $ 0.24 $ 0.23 $ 0.19
Net income 4,765 4,124 3,352 37 2,403 2,373 2,574 1,874
Net income per unit basic $ 0.09 $ 0.10 $ 0.10 $ 0.00 $ 0.10 $ 0.10 $ 0.12 $ 0.10
Highlights
Net income for Q4 2003 was $4.8 million ($0.09 per unit), compared to $2.4
million ($0.10 per unit) in 2002. For 2003, net income was $12.3 million ($0.29
per unit), compared to $9.2 million ($0.42 per unit) in 2002. The 2003 amount is
after management internalization costs of $4.7 million, and a future income tax
recovery of $900,000. Ultima expensed all internalization costs in Q1 2003
except for some minor amounts relating to the acquisition of the Calgary office
furnishings.
Q4 2003 production volumes increased by 7% from the previous quarter and by 105%
from Q4 2002 which, coupled with strong commodity prices, resulted in cash flow
of $15.9 million ($0.30 per unit) in Q4 2003, compared to $7.4 million ($0.31
per unit) in Q4 2002. For 2003, cash flow was $54.9 million ($1.29 per unit),
compared to $24.0 million ($1.09 per unit) in 2002. Cash flow for 2003 is before
deducting internalization charges of $4.7 million and the effect of the recovery
of future income taxes of $900,000.
Ultima declared distributions of $14.2 million ($0.265 per unit) in Q4 2003 with
the balance of cash flow being used primarily to repay bank debt and contribute
to the reclamation fund. Distributions declared in 2003 were $1.09 per unit,
compared to $0.90 per unit in 2002. The increase in distributions per unit in
2003 is primarily due to higher overall commodity prices realized in 2003.
Ultima completed two major property acquisitions and three equity financings in
2003.
o On June 24, 2003 Ultima closed the purchase of a package of assets in
central Alberta for $16.1 million before adjustments. The assets
produced 600 boed at the time of purchase. The key asset was a 40%
interest and operatorship of the Cherhill Banff A light oil pool. This
acquisition brought the Trust's interest in this pool to 90%. An equity
issue
C-83
of five million trust units for gross proceeds of $25.3 million
was completed in May to fund the acquisition and for general purposes.
o On June 26, 2003 the Trust closed the purchase of Trioco Resources Inc.
("Trioco") for $71 million. Trioco's production at the time of purchase
was approximately 2,050 boed (68% natural gas), concentrated in central
Alberta and the Peace River Arch area of Alberta. The key asset was a
77% interest and operatorship of the Spirit River Charlie Lake E&M Unit
and associated lands. An equity issue of 12 million trust units for
gross proceeds of $62.4 million was completed in July to partially fund
the acquisition.
o On December 17, 2003 the Trust issued six million trust units for gross
proceeds of $34.2 million to partially fund the 2004 capital
expenditure program and for general purposes.
Production Volumes, by product
Q4 2003 Q4 2002 2003 2002
-------------------------------------------------------------------------------------------------------------
Crude oil (barrels per day) 7,233 4,169 6,678 3,257
Natural gas liquids (barrels per day) 447 188 309 96
Natural gas (mcf per day) 15,200 3,795 9,480 2,568
Oil equivalent (boed) 10,214 4,990 8,566 3,781
Production Volumes, by area
Area: boe per day Q4 2003 Q4 2002 2003 2002
-------------------------------------------------------------------------------------------------------------
Central Alberta & the Peace River Arch 5,972 2,546 4,445 1,986
Weyburn Unit NRI 2,684 832 2,517 210
Kindersley 1,286 1,470 1,361 1,448
Other Properties 272 142 243 137
-------------------------------------------------------------------------------------------------------------
Oil equivalent (boed) 10,214 4,990 8,566 3,781
=============================================================================================================
Working interest and royalty interest production volumes (together noted as
"production volumes") increased by 105% in Q4 2003 to 10,214 boed compared to
4,990 boed for Q4 2002 and annual production volumes for 2003 increased by 127%
to 8,566 boed compared to 3,781 boed for 2002. Production volumes are higher due
to a number of acquisitions since the comparative period and Ultima's successful
development program. Ultima has also doubled its weighting of natural gas
production in Q4 2003 to 25% from 13% in Q4 2002.
Ultima had a very active year development drilling on the operated properties of
Spirit River, Cherhill, Westerose and Glenevis in 2003. A total of 15 gross
wells (12.6 net) were drilled on these operated properties by Ultima in 2003.
All the wells drilled were successful and are now on production. At Cherhill,
Ultima drilled two gross (1.8 net) horizontal light oil development wells in
2003 and has plans to drill another five gross (4.5 net) horizontal development
wells in 2004. The Spirit River property was the key asset of the Trioco
acquisition. In 2003, nine gross (6.6 net) wells were drilled by Ultima on this
property and a further nine gross (7.4 net) wells are scheduled to be drilled in
2004.
Capital investment was also ongoing at the non-operated Weyburn Unit, with the
third of seven planned carbon dioxide miscible flood expansion phases completed
in the summer of 2003. Production response from the third phase is anticipated
in mid 2004. Ultima's production at Weyburn increased by approximately 10% in
2003 and is anticipated to continue to increase each year until 2007.
Ultima's Q4 2003 average volume of 10,214 boed was a milestone for the Trust.
Ultima anticipates average production volumes for 2004 to be approximately
10,100 boed, before any acquisitions of producing properties.
C-84
Provided below is a summary of production growth and capital expenditures by
quarter for 2003.
Q1 Q2 Q3 Q4
--------------------------------------------------------------------------------------------------------------
Production volumes, boed 6,877 7,606 9,522 10,214
Capital expenditures ($ millions)
Drilling and facilities 2.0 1.2 9.7 6.7
Weyburn Unit 2.4 3.1 3.7 4.3
Acquisitions, net 1.4 86.9 0.2 0.3
--------------------------------------------------------------------------------------------------------------
Total capital expenditures 5.8 91.2 13.6 11.3
==============================================================================================================
Capital expenditures as presented above reflects capital expenditures accrued,
paid for with cash and financed pursuant to the Weyburn Unit NRI agreement, and
therefore differs from capital asset additions shown on the Statement of Cash
flows which only reflects capital additions that have been paid for with cash.
Commodity Prices
The average commodity prices realized by Ultima for 2003 compared to 2002 are
provided below:
Q4 2003 Q4 2002(1) 2003 2002(1)
-----------------------------------------------------------------------------------------------------
Crude oil, before hedging ($ per bbl) 34.90 40.46 37.83 37.63
Crude oil, net of hedging ($ per bbl) 32.68 34.70 35.05 33.15
Natural gas liquids ($ per bbl) 27.58 34.67 29.84 30.00
Natural gas, before hedging ($ per mcf) 6.07 5.23 6.40 4.27
Natural gas, net of hedging ($ per mcf) 6.36 5.23 6.45 4.27
Price per boe, before hedging ($ per boe) 34.96 39.10 37.65 36.08
Price per boe, net of hedging ($ per boe) 33.82 34.28 35.53 32.23
(1) The 2002 amounts are before the effect of the WLP income.
Commodity prices remained strong in the last quarter of 2003. However, overall
the price per boe, before the effects of hedging gains and losses, received by
Ultima in Q4 2003 decreased by 11% to $34.96 per boe, compared to $39.10 per boe
in the comparative period in 2002. The decrease in the average price per boe in
Q4 2003 was primarily a result of the appreciation of the Canadian dollar over
the US dollar. For 2003 Ultima's realized price per boe before hedging effects
increased by 4%, largely due to higher realized natural gas prices.
The appreciation of the Canadian dollar over the US dollar during the year has
had a negative effect on the Trust's cash flow in 2003 and we expect that the
dollar will remain strong in 2004. For every $0.01 increase in the Cdn/US
exchange rate, the Trust's cash flow from operations decreased by $0.03 per unit
per year in 2003. Accordingly even though US$ West Texas Intermediate ("WTI")
per bbl oil prices increased by 10% in Q4 2003 (US $31.16 per barrel) compared
to Q4 2002 (US $28.27 per barrel), Ultima's realized Canadian dollar oil price
per barrel decreased by 14% to $34.90 in Q4 2003 from $40.46 in Q4 2002. For the
year oil prices averaged US $31.06 per barrel, compared to US $26.17 per barrel
in 2002, however Cdn/US exchange rates averaged $0.71 in 2003, compared to $0.64
in 2002. At December 31, 2003 WTI crude oil was US $32.52 per barrel and the
Cdn/US exchange rate was $0.77. As world crude oil prices increased in 2003 the
Canadian dollar has also appreciated against the US dollar.
In 2004 should WTI crude oil prices increase management expects it would likely
cause the US economy to slow and result in the US dollar depreciating against
other currencies, including Canada's. Should WTI crude oil prices decline
management expects that it would provide a stimulus to the US economy and the
Canadian dollar would likely depreciate against the US dollar, all other factors
remaining equal. Overall management expects that in 2004 the effect on Ultima's
realized crude oil price resulting from volatility in the WTI crude oil price to
be reduced by a movement in the Cdn/US exchange rate.
C-85
Oil and Natural Gas Hedging
Ultima follows a disciplined approach to risk management of its exposure to the
volatility of commodity prices. The objectives of Ultima's risk management
program are as follows:
o Provide greater certainty to cash flow;
o Support acquisition price parameters; and
o Layer up a hedge portfolio by entering into staggered smaller positions
that, in aggregate, form a larger position.
For Q4 2003 Ultima incurred a hedging loss of $1.14 per boe compared to a
hedging loss of $4.82 per boe in Q4 2002. For 2003, Ultima reported hedging
losses of $2.12 per boe, compared to $3.86 per boe in 2002. Ultima's current
commodity price hedge arrangements for 2004 are summarized below:
Crude Oil Hedges (US$/bbl except as indicated)
Daily Quantity Fixed Price Sold Call Purchased Put Sold Put Term
------------------------------------------------------------------------------------------------------------
1,000 bbls Cdn$ 35.00 Calendar 2004
------------------------------------------------------------------------------------------------------------
800 bbls $ 27.50 $ 24.00 $ 20.00 Calendar 2004
------------------------------------------------------------------------------------------------------------
700 bbls (1) $ 30.00 $ 25.00 $ 21.00 Calendar 2004
------------------------------------------------------------------------------------------------------------
1,000 bbls $27.00 Jan. 1 to June 30, 2004
------------------------------------------------------------------------------------------------------------
(1) For clarity and illustration:
If WTI Price is (US$/bbl) Ultima receives (US$/bbl)
---------------------------------------------------------------------------------------------------
Greater than $30 $30 per bbl
Between $25 per bbl and $30 per bbl Actual price
Between $21 per bbl and $25 per bbl $25 per bbl
Less than $21 per bbl Actual price plus $4.00 per bbl
Natural Gas Hedges ($CDN/GJ)
Daily Quantity Fixed Price Term
-------------------------------------------------------------------------------------------------------------
1,000 GJs $ 7.00 Apr. 1, 2003 to Mar. 31, 2004
-------------------------------------------------------------------------------------------------------------
4,000 GJs $ 6.15 Aug. 1, 2003 to Mar. 31, 2004
As at December 31, 2003 the fair value of these commodity price hedge
arrangements was a loss of $3.6 million, based on quoted market prices and if
not available, on estimates from third-party brokers or dealers or amounts
derived from valuation models. This unrealized loss is not reflected in the 2003
financial results. As the actual gain or loss attributable to the hedges is
realized it will be included in income.
The Trust will likely hedge additional volumes for the second half of 2004 to
bring the total volumes hedged in 2004 to range from 40% to 50% of production.
Revenue
Revenue after hedging losses increased to $111.1 million in 2003 compared to
$44.5 million for 2002. Revenue for 2003 increased due to higher production
volumes as a result of the Trioco and Cherhill acquisitions and higher overall
realized commodity prices for 2003. Revenue and royalties for 2003 and 2002 are
summarized below:
($ thousands) Q4 2003 Q4 2002 (1) 2003 2002 (1)
--------------------------------------------------------------------------------
Gross revenue 31,777 15,736 111,107 44,472
Royalties (6,065) (2,692) (21,810) (6,219)
--------------------------------------------------------------------------------
Revenue, net of royalties 25,712 13,044 89,297 38,253
================================================================================
C-86
(1) Amounts exclude the WLP distributions earned by the Trust of $424,000
in Q4 2002 and $4.2 million for 2002.
Oil and Natural Gas Gross Revenue Variance Analysis
In order to better understand the effect the change in production volumes and
commodity prices has had on revenue compared to the prior reporting period we
provide the following variance analysis:
($ thousands) Q4 2003 Q4 2002 2003 2002
--------------------------------------------------------------------------------
Prior period ending December 31 15,736 7,443 44,472 30,526
Volume variance 16,090 4,901 54,484 19,333
Price variance (49) 3,392 12,151 (5,387)
--------------------------------------------------------------------------------
Current period ending December 31 31,777 15,736 111,107 44,472
================================================================================
Both increased volumes and increased overall realized prices have resulted in
higher revenue for 2003. In Q4 2003 lower average prices reduced revenue.
Royalties
($ thousands) Q4 2003 Q4 2002 2003 2002
--------------------------------------------------------------------------------
Royalty expense 6,065 2,692 21,810 6,219
Royalties as % of gross revenue, before hedging 18.5% 15.0% 18.5% 12.5%
Royalties as a percentage of revenue have increased as the properties acquired
since 2002 have had higher overall royalty rates due to a higher weighting of
natural gas production, and higher average productivity per well. Ultima
anticipates maintaining the Q4 2003 level of royalty rates going into 2004.
Oil and Natural Gas Operating Expense
($ thousands) Q4 2003 Q4 2002 2003 2002
--------------------------------------------------------------------------------
Operating costs 7,279 4,443 25,485 13,603
$'s per boe 7.75 9.68 8.15 9.86
On a per boe basis, operating expenses have decreased by 20% in Q4 2003 compared
to Q4 2002. For 2003 operating expenses on a per boe basis decreased by 17%
compared to 2002. Operating costs per boe have decreased because the properties
being acquired by the Trust in 2002 and 2003 have lower operating cost
structures. Management has targeted acquisitions with lower operating cost
structures in order to decrease the Trust's overall operating costs on a per boe
basis.
For 2004, operating costs on a per boe basis are expected to average
approximately $7.85 per boe, in line with Q4 2003.
General and Administrative Expense
General and administrative ("G&A") expense for Q4 2003 was $1.65 million ($1.76
per boe), compared to $1.1 million ($2.32 per boe) in Q4 2002. For 2003, G&A
expense totaled $9.9 million, including a $4.7 million charge related to the
internalization of the management contract through the purchase of Ultima
Management Inc., compared to $3.2 million for 2002. Excluding internalization
costs, 2003 G&A expense per boe decreased by 28% to $1.66 per boe compared to
$2.29 per boe for 2002. G&A expense per boe has decreased as the increased
production has not resulted in a corresponding increase in G&A.
C-87
It is anticipated that G&A expense per boe will be approximately $1.50 per boe
for 2004.
Internalization of Management Contract
On March 26, 2003 the Trust purchased all of the shares of Ultima Management
Inc., thereby eliminating the payment of future management and acquisition fees.
The purchase included an obligation to pay a retention bonus to the executive
team of $750,000. The retention bonus is to be paid out over the three year
period ending March 26, 2006 should the officers remain employed by the Trust.
The costs incurred to internalize the management contract were expensed in Q1
2003 with the exception of $137,000 allocated to the acquisition of capital
assets. The costs paid were as follows:
Cash payment to WhitePass Capital Inc.(1) $ 3,000,000
Value of trust units issued to WhitePass Capital Inc.(1) 800,000
Retention obligation paid, cash and trust units 750,000
Other transaction costs (2) 303,000
Less: capital assets purchased (137,000)
--------------------------------------------------------------------------------
Total $ 4,716,000
================================================================================
(1) WhitePass Capital Inc. was the previous owner of Ultima Management Inc.
(2) Fees incurred for financial and legal advisors.
Management fees paid in 2003 compared to 2002 are as follows:
($ thousands) Q4 2003 Q4 2002 2003 2002
--------------------------------------------------------------------------------
Management fee - 315 487 856
On a per unit basis - 0.01 0.01 0.04
Management and acquisition fees would have been approximately $3.3 million in
2003 had the internalization of the management contract not occurred.
Interest Expense
Interest expense for Q4 2003 totaled $804,000 versus $295,000 for the
corresponding period in 2002. For 2003 interest expense was $3.2 million,
compared to $817,000 in 2002. The increase in interest expense is a result of
the higher average debt levels in 2003 over 2002 due to a number of acquisitions
in 2003 and the latter half of 2002. Interest associated with the deferred
capital obligation is capitalized pursuant to the Weyburn Unit NRI agreement.
On a per boe basis, 2003 interest expense was $1.01 per boe compared to $0.59
per boe for 2002.
The Trust's bank credit facility interest charge is based on prime lending rates
and the Trust has not hedged or fixed any portion of its bank interest rate for
2004.
Unit Based Compensation Expense
In Q4 2003 the Trust adopted the expensing of unit based compensation. The Trust
recorded $260,000 as a charge to income for 2003. The charge is based on the
rights issued to employees since January 1, 2003. Included in Unitholders'
Equity is Contributed Surplus of the same amount. The Trust has also provided
pro-forma disclosure in respect of the unit based compensation expense that
would have been incurred on rights issued in 2002.
There were approximately two million rights issued and outstanding at year end
pursuant to the trust unit rights incentive plan. These rights had an average
adjusted exercise price of $4.78 per
C-88
unit, before the available right exercise price reduction of $0.38 per unit and
$4.40 per unit if the reduction is included.
Netback and Net Income per boe
The operating netback on a per boe basis remained basically unchanged in Q4 2003
and for the year 2003 compared to the prior periods. Funds from operations per
boe in Q4 2003 was higher than in Q4 2002 even though commodity prices realized
were slightly lower compared to Q4 2002. The elimination of the WLP income per
boe in 2003 was offset by the reduction in per boe operating costs. Net income
per boe for 2003 compared to 2002 decreased primarily as a result of the
internalization of the management contract and higher depletion and amortization
expense on a per boe basis.
($ per boe) Q4 2003 Q4 2002 2003 2002
------------------------------------------------------------------------------------------------------------
Oil and natural gas revenues, net of hedging 33.82 34.28 35.53 32.23
Royalties (6.45) (5.86) (6.98) (4.51)
Income from the WLP - 0.92 - 3.04
------------------------------------------------------------------------------------------------------------
27.37 29.34 28.55 30.76
Oil and natural gas operating expense (7.75) (9.68) (8.15) (9.86)
------------------------------------------------------------------------------------------------------------
Operating netback 19.62 19.66 20.40 20.90
General and administrative (1.76) (2.32) (1.66) (2.29)
Management fees - (0.69) (0.16) (0.62)
Internalization of Management Contract - - (1.51) -
Interest, taxes and unit based compensation (0.91) (0.64) (1.04) (0.59)
------------------------------------------------------------------------------------------------------------
16.95 16.01 16.03 17.40
Unit based compensation (0.28) - (0.08) -
Future income tax recovery 0.93 - 0.29 -
Depletion and amortization (12.52) (10.78) (12.32) (10.71)
------------------------------------------------------------------------------------------------------------
Net Income 5.08 5.23 3.92 6.69
============================================================================================================
Income Tax
During 2003, the Ultima trust units were deemed to be foreign property for
purposes of Canadian income tax exempt plans such as RRSPs, DPSPs, and RRIFs.
The Ultima trust units are not foreign property for purposes of exempt plans
effective January 1, 2004. For a full explanation of this matter, see Ultima's
2002 Annual Information Form, which was filed in May 2003.
A future income tax liability of $14.4 million was recorded in connection with
the Trioco acquisition. Management does not expect the future income tax
liability to be paid by the Trust because royalties paid by the corporate
subsidiary to the Trust and future distributions paid to unitholders will
effectively transfer this liability to the unitholders.
Income taxes are comprised of a current income tax provision of $nil and a
recovery of future income taxes of $900,000 (2002 - $nil). The Trust has also
accrued capital taxes of $76,000 for 2003, compared to $nil in 2002. Capital
taxes relate to a corporate subsidiary, which resulted from the acquisition of
Trioco in June 2003. In 2004 the Trust expects to record a further income tax
recovery. There is no effect on 2003 cash flow due to the recovery of future
income taxes.
For 2003, it is anticipated that distributions paid to unitholders will have a
taxable component and a return of capital component. At this time, the taxable
component is expected to range between 20% and 30% of the distributions paid.
The taxability of distributions is sensitive to commodity price volatility; the
higher the commodity prices, the more likely the taxable component will be
higher, all other factors remaining equal.
C-89
For 2004, the taxable component of distributions is expected to range from 25%
to 35%.
Capital Expenditures
Capital expenditures in Q4 2003 totaled $11.3 million, compared to $104.4
million in Q4 2002. For 2003 capital expenditures totaled $121.9 million,
approximately equal with 2002 capital expenditures of $121.0 million. Capital
expenditures by quarter in 2003 are summarized below.
($ millions) Q1 Q2 Q3 Q4 Total
-----------------------------------------------------------------------------------------------------------
Development drilling and facilities (1) 2.0 1.2 9.7 6.7 19.6
Weyburn Unit 2.4 3.1 3.7 4.3 13.5
Acquisitions, net of dispositions 1.4 86.9 0.2 0.3 88.8
-----------------------------------------------------------------------------------------------------------
Total 5.8 91.2 13.6 11.3 121.9
===========================================================================================================
(1) Includes all operated and non-operated development drilling and
facilities capital expenditures, excluding the capital expenditures
attributable to the Weyburn Unit NRI.
Depletion, Depreciation and Amortization ("DD&A")
The Trust adopted the Full Cost Method of accounting for capital assets in 2003.
The effect of this change is that the reported DD&A rate per boe is largely
unchanged for 2003 and lower for 2002 than that under the previously used
Successful Efforts Method of accounting for capital assets. Under the Full Cost
Method, included in the DD&A calculation are expected future capital costs of
approximately $86.6 million of which $80.0 million is attributable to the
Weyburn Unit enhanced recovery process. The expected future capital costs are
taken from the reserve evaluations prepared by the Trust's independent
engineers. Under the Trust's previous method of accounting for capital assets
these expected future development costs would not have been reflected in the
DD&A calculation until they were incurred.
DD&A calculated on a unit of production basis totaled $11.8 million for Q4 2003,
including a site restoration charge of $1.0 million. DD&A in the corresponding
period of 2002 was $4.9 million, including $420,000 of site restoration expense.
The higher DD&A and site restoration charge in 2003 is due to increased capital
costs and production levels. The DD&A rate per boe was $12.52 per boe in Q4
2003, compared to $10.78 per boe in Q4 2002. The DD&A rate per boe has increased
in Q4 2003 due to the acquisition cost per proven boe of reserves being higher
in 2003 than the historical DD&A rate per boe. DD&A per boe for 2003 was $12.32
per boe, compared to $10.71 per boe for 2002. The foregoing amounts are based on
the Full Cost Method of accounting.
Capital assets of $11.3 million associated with the Weyburn Unit NRI were
excluded from the DD&A calculation as this amount relates to unproven property.
This amount and related proved reserves are expected to be reflected in the DD&A
calculation when the majority of the probable reserves attributable to the
Weyburn Unit NRI reserve evaluation have become proved.
For 2004, DD&A per boe is expected to decrease due to the increase in proved oil
and natural gas reserves as at January 1, 2004 being greater than the
corresponding increase in net capital assets. Also future capital associated
with the Weyburn Unit has been forecast to decrease due to the appreciation of
the Canadian dollar versus the US dollar decreasing the Canadian dollar cost of
future carbon dioxide purchases. The carbon dioxide is purchased in US dollars.
Cash Distributions
Ultima declared cash distributions to the unitholders in Q4 2003 in the amount
of $14.2 million ($0.265 per unit) compared to $6.5 million ($0.24 per unit) in
Q4 2002. Distributions for 2003 were $48.1 million ($1.09 per unit), compared to
$21.0 million ($0.90 per unit) for 2002. The increase in distributions per unit
is primarily due to higher production volumes in 2003 compared to 2002.
C-90
The payout ratio, defined as distributions declared over cash flow as presented,
was approximately 87% in both 2003 and 2002. Ultima's distributions are highly
dependent on commodity prices, primarily the price of crude oil. Ultima reduces
the effect of crude oil price volatility on its cash flow by following a
disciplined approach to hedging the price of crude oil. Ultima's cash
distributions are also highly dependent upon production volumes. Further,
Ultima's monthly cash distributions are comprised of a return of capital
component and a return on capital component.
A monthly history of cash distributions declared for 2003 and 2002 is provided
below.
2003 Distributions Distribution per unit
Record Date Payment Date 2003 2002
-----------------------------------------------------------------------
January 31, 2003 February 17, 2003 $0.09 $0.06
February 28, 2003 March 17, 2003 $0.09 $0.06
March 31, 2003 April 15, 2003 $0.09 $0.07
April 30, 2003 May 15, 2003 $0.09 $0.07
May 30, 2003 June 16, 2003 $0.09 $0.08
June 30, 2003 July 15, 2003 $0.09 $0.08
July 31, 2003 August 15, 2003 $0.095 $0.08
August 29, 2003 September 15, 2003 $0.095 $0.08
September 30, 2003 October 15, 2003 $0.095 $0.08
October 31, 2003 November 17, 2003 $0.095 $0.08
November 28, 2003 December 15, 2003 $0.085 $0.08
December 31, 2003 January 15, 2004 $0.085 $0.08
-----------------------------------------------------------------------
Total Distributions Declared per unit for
the year: $1.09 $0.90
=======================================================================
Balance Sheet
Assets
As at December 31, 2003, total assets were $326.5 million consisting of net
capital assets of $294.5 million, current assets of $14.2 million, goodwill of
$16.7 million and a reclamation fund of $1.1 million. Net capital assets have
increased from 2002 primarily due to the acquisition of the Cherhill properties
and the Trioco acquisition. Goodwill arose on the Trioco acquisition.
Liabilities and Unitholders' Equity
Liabilities totalled $118.1 million at December 31, 2003, consisting of a $45.0
million long-term bank loan, $22.5 million in current liabilities, a deferred
capital obligation of $28.1 million, a future income tax liability of $14.4
million and a site restoration accrual of $8.1 million. The future income tax
liability arose on the Trioco acquisition and represents the tax effect with
respect to the excess of the fair value of the assets acquired, excluding
goodwill, compared to their tax basis at the date of purchase.
The authorized capital of the Trust consists of an unlimited number of trust
units. Unitholders' capital was $324.8 million at December 31, 2003, compared to
$206.2 million at December 31, 2002. Provided below is a summary of the equity
financings completed by the Trust in 2003.
Price Issued Gross Proceeds
Date Units Issued ($/unit) ($ thousands)
-------------------------------------------------------------------------
May 5,000,000 5.05 25,250
July 12,000,000 5.20 62,400
December 6,000,000 5.70 34,200
-------------------------------------------------------------------------
23,000,000 121,850
=========================================================================
C-91
Provided below is a schedule of the change in trust units outstanding for 2003
and 2002.
2003 2002
Number of Trust Number of Trust
Units Value Units Value
------------------------------------------------------------------------------------------------------
Balance, beginning of year 33,873,808 $ 206,154 18,447,142 $ 134,314
Issued for cash, net of costs 23,000,000 115,197 15,350,000 71,564
Issued on exercise of rights 512,998 3,301 16,666 73
Issued for internalization 188,169 - - -
Issued on exercise of options 50,000 169 60,000 203
-------------------------------------------------------------------------------------------------------
Balance, end of year 57,624,975 $ 324,821 33,873,808 $ 206,154
=======================================================================================================
Cash flow
Cash flow on a per unit basis remained relatively unchanged in Q4 2003 at $0.30
per unit, compared to $0.31 per unit in Q4 2002. For 2003, cash flow per unit
excluding internalization costs increased by 27% to $1.29 per unit, compared to
$1.09 per unit in 2002. Higher production volumes were the primary driver of the
increase in cash flow per unit.
Provided below is a summary of the calculation of cash flow for 2003 and 2002.
($ thousands) Q4 2003 Q4 2002 2003 2002
--------------------------------------------------------------------------------
Net Income 4,765 2,403 12,278 9,224
Add items not affecting cash flow
DD&A 11,770 4,948 38,526 14,792
Internalization costs - - 4,716 -
Recovery of future income taxes (872) - (900) -
Unit based compensation expense 260 - 260 -
--------------------------------------------------------------------------------
15,923 7,351 54,880 24,016
================================================================================
Liquidity and Capital Resources
($ thousands) December 31, 2003 December 31, 2002
--------------------------------------------------------------------------------
Long term bank debt 45,007 55,358
Working capital deficiency 8,243 2,436
--------------------------------------------------------------------------------
Net bank debt 53,250 57,794
Deferred capital obligation 28,126 20,444
Market value of Trust Units (1) (2) 359,420 174,450
--------------------------------------------------------------------------------
Total capitalization 440,796 252,688
================================================================================
Net bank debt as a % of total capitalization 12% 23%
================================================================================
Total debt as a % of total capitalization 19% 31%
(1) The number of trust units issued at December 31, 2003 was 57.6 million
and the closing price was $6.24.
(2) Total capitalization as represented in this table includes the market
value of the Trust's equity, and does not represent the historical cost
of the Trust's Unitholders' equity. Therefore total capitalization may
not be comparable with the calculation of similar measures by other
entities. A GAAP measure would use the book value of Unitholders'
Equity, which at December 31, 2003 was $208.4 million, and total
capitalization would therefore be $289.8 million. Management has
presented debt as a function of total capitalization because management
uses this measure to benchmark the financial position of the Trust.
Working capital deficit was $8.2 million at December 31, 2003. The deficit is
primarily due to Q4 capital expenditures being accrued but unpaid in the amount
of $3.2 million and accounts payable being paid on a 60 day basis. The Trust
would normally expect a minor working capital deficit for any given month. A
working capital deficit could be remedied by available unutilized bank
facilities. At year end the Trust had approximately $43 million in available
credit with its banking syndicate. This balance includes the pro-forma
elimination of the working capital deficit.
C-92
Total debt outstanding at December 31, 2003 was $81.4 million, which includes
net bank debt of $53.3 million and the deferred capital obligation associated
with the Trust's Weyburn Unit NRI of $28.1 million. Ultima's oil and gas
properties secure the bank debt. The Trust has a maximum bank credit facility of
$95 million. The Trust is currently in compliance with all covenants and expects
to remain so in the future. In the event that the banking syndicate requires
repayment of the loan there is a two year term out, with no payments being
required in the first year. The banking syndicate based upon the estimated value
of the Trust's oil and natural gas reserves determines the amount of the maximum
banking facility. The value of the maximum facility is evaluated and confirmed
by the banking syndicate on a semi-annual basis.
The deferred capital obligation is a term of the Weyburn Unit NRI agreement and
its payment is non-recourse in nature to the Trust's other properties. The Trust
has the ability to defer up to $9.3 million of additional capital expenditure
payments associated with the Weyburn Unit NRI until January 1, 2006. For 2004,
the Trust anticipates that the deferred capital obligation will increase by $7.8
million, before accrued interest. Subsequent to January 1, 2006 management
anticipates refinancing the deferred capital obligation. The parameters of this
future refinancing will be dependent upon the capital market and interest rate
environments at that time.
Capital Commitments
The Trust anticipates investing approximately $32 million in respect of
development activities on its properties in 2004. These development activities
include $16.5 million of development planned for drilling and waterflood
optimization at Spirit River, Cherhill, Westerose and Glenevis. A total of 17
gross wells (14.8 net wells) are budget to be drilled by Ultima in 2004 on these
properties. The carbon dioxide miscible flood project will continue to be
expanded at the Weyburn Unit with the Trust's share of expenditures budget to be
$15.5 million, compared to $13.5 million in 2003. The Trust anticipates funding
its planned 2004 capital program from a combination of cash flow, available bank
credit and the deferred capital program associated with the Trust's Weyburn Unit
NRI. It is expected that cash flow generated during 2004 will be used primarily
to pay distributions to unitholders.
Other Commitments
For 2004, the Trust has entered into a fixed price purchase commitment for one
megawatt per hour ("mwh") of electricity at a price of $51 per mwh. Currently
the Trust is incurring a power cost of approximately $55 per mwh. The contract
represents a commitment of approximately $447,000.
The Trust has entered into an office lease agreement in respect of the Calgary
head office that has a six year term, expiring on May 31, 2009. Minimum annual
lease payments, before occupancy costs, range from $257,000 in 2004 to $291,000
in 2009.
Provided below is a table which details the contractual and/or balance sheet
obligations of the Trust and the expected timing of when these items are
anticipated to be paid.
Less than 1 After 5
($ thousands) Total year 1 to 3 years 4 to 5 years years
-----------------------------------------------------------------------------------------------------
Long-term bank debt 45,007 - - - 45,007
Office lease 1,910 257 523 548 582
Electricity contract 447 447 - - -
Deferred capital obligation (1) 28,126 - 28,126 - -
Future Weyburn Unit NRI carbon
dioxide purchases (2) 59,508 6,851 14,859 11,344 26,454
Site restoration provision 8,076 - - - 8,076
(1) The Trust expects to refinance this obligation on or shortly after
January 1, 2006 by a combination of new debt and equity. However, if
the obligation is not refinanced, payments are based upon a
C-93
blend of interest and principle over 15 years, plus an income tax
equalization component. A pre-payment bonus of 7% of the pre paid
amount is also due in the event the obligation is refinanced.
(2) These amounts represent the Trust's net share of future payments for
carbon dioxide associated with the Weyburn Unit miscible flood enhanced
recovery process. The operator has entered into a take-or-pay
arrangement for the purchase of the carbon dioxide. These costs were
determined by the Trust's independent engineers and are attributable to
the total proved case for the oil and natural gas reserves. The Weyburn
Unit NRI agreement has a provision that for any given month cash flow
attributable to the NRI cannot be negative. Accordingly, the Trust's
share of the Weyburn Unit carbon dioxide purchases is recourse only to
the Weyburn Unit NRI, and is non-recourse in nature to the balance of
the Trust's assets.
Reclamation Fund
Upon inception, Ultima established a reclamation fund into which cash is
contributed at a rate of $0.20 per boe of production. For 2003, a total of
$625,000 was contributed to the fund. During 2003 a total of $296,000 of
abandonment and reclamation costs were incurred and funded from the fund
balance. At year end the fund balance was $1.1 million.
Ultima has also begun to improve the quality of the assets of the Trust by
selling its lesser quality production, which has a shorter reserve economic life
and higher operating costs. These factors combine to provide a higher
probability of resulting in a shorter time period for the abandonment of the
property.
Future Trends and Risk Factors
The development and production of oil and natural gas reserves is inherently
uncertain and subject to numerous operational and competitive risks. Evaluations
of oil and natural gas reserves represent estimates only and include a number of
assumptions, including assumptions regarding the future price of crude oil and
natural gas and the success of exploitation and development and tertiary
recovery activities intended to be undertaken on the Trust's properties in
future years.
The economic performance of the Trust will be affected by a variety of market
conditions that are beyond the Trust's control, including commodity pricing,
interest rates, exchange rates and the ability to acquire suitable oil and
natural gas properties. In particular, the price received for oil and natural
gas production is market determined and has been subject to considerable
volatility in the recent past. Ultima has taken steps to mitigate this risk as
disclosed above under "Oil and Natural Gas Hedging".
The future oil and natural gas reserves and production are highly dependent on
the success in exploiting the current reserve base. Future cash flows are highly
dependent on both of these factors, together with the Trust's success in
acquiring additional reserves. Without the addition of reserves, production is
subject to continued decline. Accordingly, all other factors remaining equal,
without the acquisition of additional reserves the Trust's future cash flows are
expected to decline as the Trust's existing oil and natural gas reserves
decline.
Future acquisitions will depend on the availability of economically attractive
properties. Acquisitions must generally comply with certain pre-established
guidelines or otherwise be approved by the Boards of Directors. All acquisitions
with a purchase price of $2 million or greater must be approved by the Board of
Directors, and be substantiated by a reserve evaluation prepared by independent
engineers.
The oil and natural gas industry is subject to extensive controls and
regulations imposed by various levels of government. All current legislation is
a matter of public record and Ultima is unable to predict what additional
legislation or amendments may be enacted
The oil and natural gas industry is also subject to environmental regulation
pursuant to local, provincial and federal legislation. Ultima is committed to
meeting its responsibilities to protect the
environment. The Board of Directors has put in place an environment and safety
management system designed to ensure appropriate policies and procedures are
maintained.
Effect of Future Changes in Accounting Policies
Effective for January 1, 2004, the Trust will adopt the CICA Handbook Section
3110 "Asset Retirement Obligations" accounting policy in respect of asset
retirement and reclamation obligations associated with the Trust's oil and
natural gas properties. The new policy is expected to increase the recorded
amount of net capital assets and the site restoration obligation on the balance
sheet. The effect on net income has not been determined at this time. There is
expected to be no effect on cash flow as a result of the adoption of the new
accounting policy.
Effective for January 1, 2004, the Trust will adopt AcG 13 "Hedging
Relationships". This guideline requires that in order for a hedge to be
considered "effective" for accounting purposes and qualify for hedge accounting
treatment, specific and detailed criteria must first be met. Should a hedge not
qualify for hedge accounting treatment the fair value of the hedge at the
balance sheet date is recorded as an asset or liability on the balance sheet.
All the Trust's hedges are deemed by management to be effective economic hedges.
However, not all the Trust's hedges will be deemed to be effective hedges
pursuant to AcG 13's criterion. Specifically the Trust's "three-way" crude oil
hedges are not deemed to be effective hedges for accounting purposes as they do
not provide by design a direct correlation between the change in the price of
WTI crude oil and the hedged price received.
All or a portion of hedges that the Trust may enter into at a future date may be
deemed not to be effective hedges for accounting purposes pursuant to AcG 13 and
in that event those hedges would be recorded on the balance sheet at their fair
value, along with the three-way crude oil hedges already in existence. Changes
in the fair value of these hedges will be accounted for in the income statement.
Effective March 31, 2004 National Instrument 51-102 "Continuous Disclosure
Obligations" comes into effect for reporting issuers. The primary impact of NI
51-102 is that it will bring forward reporting deadlines for annual and interim
financial statements, oil and gas reserve reports, the Annual Information Form
("AIF") and the MD&A. The new instrument also will require additional disclosure
compared to prior requirements for the annual and interim financial statements,
AIF and MD&A.
Further, pursuant to NI 51-102 annual and interim financial statements will only
be mailed to unitholders on the receipt of a formal request.
This MD&A has been prepared in accordance with NI 51-102 disclosure
requirements.
Critical Accounting Assumptions and Estimates
The financial and operating results of Ultima incorporate certain critical
estimates and assumptions. The following is a list of these critical assumptions
and estimates:
o Estimates of oil and natural gas reserves that the Trust expects to
recover in the future, which effect the determination of depletion,
depreciation and amortization. Independent engineers pursuant to NI
51-101 prepare the estimate of oil and natural gas reserves.
o Estimates of production volumes, prices, royalties and operating costs
as at a reporting date but for which actual production volumes,
royalties and operating costs have not yet been received or paid.
o Estimates of development capital expenditures, which is in progress and
for which actual costs have not yet been received or paid.
o Estimates of future development capital associated with the oil and
natural gas reserves the Trust expects to recover in the future.
C-95
In order to allow the Trust to make reasonable estimates, appropriately trained
and skilled staff and consultants are engaged, and provided with the appropriate
systems to utilize their skills. A key part of the process of making reasonable
estimates is a review of past estimates to actual results. However, there is a
level of uncertainty inherent with any assumption.
Off Balance Sheet Arrangements and Guarantees
There are no undisclosed off balance sheet arrangements or undisclosed
guarantees that the Trust is a party to.
Related Party Transactions
There are no undisclosed and material related party transactions. The only
material related party transaction in 2003 was the internalization of the
management contract and the purchase of Ultima Management Inc.
Trading Statistics
In order to understand the liquidity and price movement of the Ultima trust
units in 2003, we provide a summary of trading statistics by quarter.
2003 Q1 Q2 Q3 Q4
--------------------------------------------------------------------------------
High, $ per unit 5.68 5.52 6.23 6.28
Low, $ per unit 5.15 5.15 5.27 5.73
Close, $ per unit 5.30 5.42 6.13 6.24
Average Daily Trading Volume, thousands 152 204 395 266
2004 Outlook
It is the Trust's objective to provide value to unitholders by focusing on the
key strategic objectives of the business plan. This focus has resulted in Ultima
achieving exceptional results since revitalization in December 2000, by
providing unitholders with cash distributions of $3.05 per unit and capital
appreciation of $2.31 per unit, for a total return of $5.36 per unit.
The key future objectives of the business plan include:
o Annual reserve replacement;
o Ensuring acquisitions are strategic and enhance unitholder returns;
o Controlling costs: new reserve acquisition costs, operating costs and
G&A
o Actively hedging a portion of the Trust's production;
o Frugal utilization of debt;
o Being an industry leader in health, safety and the environment; and
o Supporting community initiatives in the areas we operate and live.
In 2003, Ultima was successful in meeting these objectives and will continue to
focus on and closely monitor these core objectives in 2004 and beyond.
The Boards of Directors has approved an operating budget for 2004 the highlights
of which are summarized below:
($ millions)
-------------------------------------------------------------------
Revenues, net of royalties 101.0
Operating costs (29.0)
General and Administrative (5.4)
Interest (2.5)
-------------------------------------------------------------------
Cash flow 64.1
===================================================================
C-96
The Trust has assumed a WTI crude oil price of $US 28 per barrel, an AECO
natural gas price of $5.50 per GJ and a Cdn/US exchange rate of 0.75.
Production is anticipated to average 10,100 boed, and there are no acquisitions
reflected in the operating budget. However, the Trust anticipates completing
further acquisitions in 2004 in order to broaden the Trust's asset base and add
development opportunities. Acquisition criteria include that acquisitions are
anticipated to be accretive to net asset value.
The Boards of Directors set the January 2004, February 2004 and March 2004
distributions at $0.085 per trust unit per month. Beyond this time frame the
Boards of Directors will determine a distribution, which is in line with cash
flow expectations and anticipated cash requirements of the Trust.
2004 Sensitivities
The following table summarizes the variables that are expected to have the most
material effect on 2004 cash flow from operations.
Cash flow Impact Cash flow impact
Variable Change ($ thousands) per unit
--------------------------------------------------------------------------------
Oil price, including hedging $US1/bbl 2,300 4 cents
Natural gas price $0.10/mmbtu 500 1 cent
Oil production 100 bbl/day 1,750 3 cents
Exchange rate (Cdn/US) $0.01 1,000 2 cents
Interest rate 1% 600 1 cent
For reference purposes only, the mean crude oil price for the three year period
2000 to 2003 was approximately US $27.73 per barrel, and the standard deviation
from the mean crude oil price was approximately US $3.95 per barrel.
Additional Information
Additional information on the Trust including previously released financial
reports, Annual Information Forms and press releases can be found on SEDAR at
www.sedar.com.
C-97
ULTIMA ENERGY TRUST
CONSOLIDATED FINANCIAL STATEMENTS
As at and for the Years Ended December 31, 2003 and 2002
C-98
AUDITORS' REPORT
To the Directors of Ultima Ventures Corp. and Ultima
Acquisitions Corp.:
We have audited the consolidated balance sheet of Ultima Energy Trust as at
December 31, 2003 and 2002 and the consolidated statements of income and deficit
and cash flows for the years then ended. These financial statements are the
responsibility of the Trust's management. Our responsibility is to express an
opinion on these financial statements based on our audits.
We conducted our audits in accordance with Canadian generally accepted auditing
standards. Those standards require that we plan and perform an audit to obtain
reasonable assurance whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
In our opinion, these consolidated financial statements present fairly, in all
material respects, the financial position of the Trust as at December 31, 2003
and 2002 and the results of its operations and its cash flows for the years then
ended in accordance with Canadian generally accepted accounting principles.
Calgary, Alberta (signed) Deloitte & Touche LLP
February 24, 2004 (except as to Notes 14 and 15 Chartered Accountants
which are as of April 30, 2004)
C-99
ULTIMA ENERGY TRUST
CONSOLIDATED BALANCE SHEET
(thousands of dollars)
December 31
-----------------------------------------
2003 2002
--------------------------------------------------------------------------------
ASSETS
Current assets
Accounts receivable $ 12,442 $ 8,969
Prepaid expenses 1,803 528
--------------------------------------------------------------------------------
14,245 9,497
Reclamation fund (note 7) 1,077 748
Goodwill (note 5) 16,682 -
Capital assets, net (note 4) 294,535 207,930
--------------------------------------------------------------------------------
Total Assets $ 326,539 $ 218,175
--------------------------------------------------------------------------------
LIABILITIES and UNITHOLDERS' EQUITY
LIABILITIES
Current liabilities
Bank indebtedness $ 977 $ 19
Accounts payable 16,613 9,204
Cash distributions payable 4,898 2,710
--------------------------------------------------------------------------------
22,488 11,933
Accumulated site restoration 8,076 5,066
Deferred capital obligation (note 6) 28,126 20,444
Future Income Taxes (notes 5 and 13) 14,398 -
Long-term bank debt (note 8) 45,007 55,358
Contingencies and Commitments (note 12)
--------------------------------------------------------------------------------
118,095 92,801
--------------------------------------------------------------------------------
UNITHOLDERS' EQUITY
Unitholders' capital (note 9) 324,821 206,154
Contributed surplus (note 9) 260 -
Deficit (4,944) (17,222)
Accumulated cash distributions (note 3) (111,693) (63,558)
--------------------------------------------------------------------------------
208,444 125,374
--------------------------------------------------------------------------------
Total Liabilities and Unitholders' Equity $ 326,539 $ 218,175
--------------------------------------------------------------------------------
C-100
The accompanying notes are an intergral part of these consolidated financial
statements
ULTIMA ENERGY TRUST
CONSOLIDATED STATEMENT OF INCOME AND DEFICIT
(thousands of dollars except for per unit amounts)
Year Ended December 31
---------------------------------------
2003 2002
--------------------------------------------------------------------------------
Revenue:
Oil and natural gas $ 111,107 $ 44,472
Royalties (21,810) (6,219)
Income from Weyburn Limited Partnership (note 6) - 4,198
--------------------------------------------------------------------------------
89,297 42,451
--------------------------------------------------------------------------------
Expenses:
Oil and natural gas operating 25,485 13,603
General and administrative (note 10) 9,914 3,159
Management fee (note 10) 487 856
Interest on long-term debt (note 8) 3,171 817
Unit based compensation (note 9) 260 -
Capital taxes 76 -
Depletion and amortization (note 4) 38,526 14,792
--------------------------------------------------------------------------------
77,919 33,227
--------------------------------------------------------------------------------
Net income before income taxes 11,378 9,224
Future income tax recovery (note 13) $ 900 $ -
--------------------------------------------------------------------------------
Net income 12,278 9,224
Deficit, beginning of year (note 2(l)) (17,222) (26,446)
--------------------------------------------------------------------------------
Deficit, end of year $ (4,944) $ (17,222)
--------------------------------------------------------------------------------
Net income per unit, basic (note 2(k)) $ 0.29 $ 0.42
Net income per unit, diluted (note 2(k)) $ 0.28 $ 0.41
The accompanying notes are an intergral part of theses consolidated financial
statements
C-101
ULTIMA ENERGY TRUST
CONSOLIDATED STATEMENT OF CASH FLOWS
(thousands of dollars)
Year Ended December 31
-------------------------------------------
20033 2002
--------------------------------------------------------------------------------
Operating Activities:
Net income $ 12,278 $ 9,224
Add/(less) items not involving cash:
Future income tax recovery (900) -
Unit based compensation 260 -
Internalization of management contract (note 10) 4,716 -
Depletion and amortization 38,526 14,792
--------------------------------------------------------------------------------
54,880 24,016
Changes in non-cash operating working capital (572) (816)
--------------------------------------------------------------------------------
54,308 23,200
--------------------------------------------------------------------------------
Financing Activities:
Issuance of Trust units, net 117,617 71,840
Bank loan (10,351) 26,068
Cash distributions paid to unitholders (45,947) (19,371)
--------------------------------------------------------------------------------
61,319 78,537
--------------------------------------------------------------------------------
Investing Activities:
Capital asset additions (23,884) (5,690)
Investment in Weyburn Limited Partnership - 1,042
Acquisitions of properties, net of divestments (88,410) (96,504)
Internalization of management contract (3,666) -
Reclamation fund contributions (625) (325)
--------------------------------------------------------------------------------
(116,585) (101,477)
--------------------------------------------------------------------------------
Increase/(Decrease) in bank indebtedness (958) 260
Bank indebtedness, beginning of year (19) (279)
--------------------------------------------------------------------------------
Bank indebtedness, end of year $ (977) $ (19)
--------------------------------------------------------------------------------
Supplemental Information
Cash income taxes paid $ - $ -
Cash interest paid $ 3,171 $ 817
The accompanying notes are an intergral part of these consolidated financial
statements
C-102
ULTIMA ENERGY TRUST
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years ended December 31, 2003 and 2002
(Tabular amounts in thousands of dollars except for per unit amounts)
1. Basis of Presentation
a. Structure
Ultima Ventures Corp. (the "Corporation"), Ultima Ventures
Trust ("Ventures Trust") Ultima Energy Inc. ("Energy Inc."),
Ultima Management Inc. ("the Manager") and Ultima Acquisitions
Corp. ("Acquisitions Corp.") operate under common management.
The financial statements include the accounts of Ultima Energy
Trust ("the Trust"), and the accounts of its subsidiaries, the
Corporation, Ventures Trust, Energy Inc., the Manager and
Acquisitions Corp., on a consolidated basis. Inter-entity
transactions and balances have been eliminated. These
consolidated financial statements are prepared following
accounting principles generally accepted in Canada.
The Trust is an open-ended, unincorporated investment trust
formed under the laws of the Province of Alberta. The
beneficiaries of the Trust and its subsidiaries are the
unitholders. Ventures Trust and Energy Inc. hold oil and
natural gas properties. The Trust acquires an interest in the
cash flow generated by these properties in the form of a
royalty with each of Ventures Trust and Energy Inc. The Trust
was set up to acquire and hold the royalty(s) and to issue
trust units. Each royalty consists of 99% of the net cash flow
generated by the underlying properties, less certain
expenditures, including capital expenditures funded by cashflow
and any debt repayments.
2. Significant Accounting Policies
a. Joint Interests
Certain oil and natural gas activities are conducted jointly
with others and, these consolidated financial statements
reflect the Trust's proportionate interest in such activities.
b. Oil and Natural Gas Properties
The Trust follows the Full Cost Method of accounting whereby
all costs relating to the acquisition and development of oil
and natural gas reserves are capitalized. The Trust does not
capitalize general and administration expenses. Interest
relating to the Weyburn Unit NRI deferred capital obligation is
capitalized pursuant to the terms of the agreement.
No gains or losses are recognized in income during the year in
which oil and natural gas properties are sold unless the
depletion and amortization rate changes by more than 20% as a
result of the sale.
c. Depletion and Amortization
Capital costs of oil and natural gas properties, net of
estimated salvage values, are depleted using the unit of
production method. These capital costs are depleted based on
estimated gross proved oil and natural gas reserves as
determined by independent engineers. For purposes of these
calculations production of crude oil, natural gas, natural gas
liquids and proved reserves are converted to a common unit of
measure on the basis of 6 thousand cubic feet of natural gas to
1 barrel of oil equivalent.
C-103
d. Future Site Restoration
Estimated future costs of site restoration are provided for
over the life of the proved reserves on a unit of production
basis. Costs are estimated each period by management using
current costs and in accordance with existing legislation and
underlying practice. The provision is included with depletion
and amortization expense and actual site restoration
expenditures are charged against the accumulated provision.
e. Ceiling Test
The Trust places a limit on the aggregate carrying amount of
capital assets, which may be depleted against revenues of
future periods (the "ceiling test"). Capitalized costs plus the
estimated future capital associated with proved undeveloped
reserves, less accumulated depletion and amortization are
limited to an amount equal to the discounted future net
revenues of the estimated proved and risked probable reserves.
f. Goodwill
The Trust recorded goodwill relating to a corporate
acquisition. The goodwill was determined as the excess of the
purchase price over the fair value of the acquired assets less
liabilities, including future income taxes, of the acquired
company. The goodwill balance is assessed for impairment at
each balance sheet reporting date. Impairment would be charged
to earnings in the period it was incurred. Goodwill is reported
at cost less any impairment and is not subject to amortization.
g. Investment in Weyburn Limited Partnership ("WLP")
Effective November 1, 2002, the Trust increased its ownership
in the WLP and immediately redeemed its entire interest (see
Note 6) in the WLP. Prior to this time, the Trust's interest in
the WLP was accounted for using the cost method. Pursuant to
this method, no income with respect to the WLP was recorded in
the accounts of the Trust except for cash distributions
received or receivable. Cash distributions received or
receivable were recorded as a reduction of the investment to
the extent that such distributions represented a return of
capital.
h. Hedging Contracts
From time to time the Trust enters into various arrangements to
hedge against possible fluctuations in commodity prices,
interest rates and exchange rates. Gains or losses from these
arrangements, which constitute effective economic hedges, are
reported as adjustments to the related revenue or expense
accounts as they are settled.
i. Unit-Based Compensation Plan
The Trust has a Trust Unit Rights Incentive Plan ("the Plan"),
which is described in Note 9. The exercise price of the rights
awarded pursuant to the plan may be reduced in future periods
in accordance with the terms of the Plan. The reduction is
primarily a function of distributions to unitholders and the
net book value of the Trust's capital assets. The reduction is
calculated as the excess, if any, of quarterly distributions
greater than 2.5% of the net book value of capital assets. It
is not possible to determine a fair value for the rights
awarded pursuant to the Plan at inception using an
option-pricing model because the exercise reduction feature of
the Plan is dependent upon a number of factors, including, but
not limited to, future prices realized on the sale of oil and
natural gas, future production levels of oil and natural gas,
amounts withheld from future distributions and the purchase and
sale of capital assets. Compensation expense has been
determined based upon the intrinsic value of the rights at the
date of exercise or at the date of the financial statements for
unexercised rights.
The compensation expense associated with rights awarded under
the Plan is deferred and recorded in earnings over the average
vesting period of the rights awarded along with an equal
increase or decrease in contributed surplus. Changes in the
intrinsic
C-104
value of the unexercised rights after the vesting period will
be recognized in the corresponding period of the change, along
with an accompanying increase or decrease to contributed
surplus.
On the actual exercise of the rights by the holder the
consideration paid and the amount of contributed surplus
attributable to the exercised right will be recorded as an
increase to Unitholders' capital.
j. Income Taxes
The Trust follows the liability method of accounting for income
taxes. Under this method, income tax liabilities and assets are
recognized for the estimated tax consequences attributable to
differences between the amounts reported in the financial
statements of the Trust's corporate subsidiaries and their
respective tax base, using enacted income tax rates. The effect
of a change in income tax rates on future tax liabilities and
assets is recognized in income in the period in which the
change occurs. Temporary differences arising on corporate
acquisitions could result in future income tax assets and
liabilities. It is anticipated that any future assets or
liabilities would be for the account of the unitholders.
The Trust is a taxable entity under the Income Tax Act (Canada)
and is taxable only on income that is not distributed or
distributable to unitholders. As the Trust expects to
distribute its taxable income to the unitholders and meets the
requirements of the Income Tax Act (Canada) applicable to the
Trust, no current provision for income taxes has been made.
k. Weighted Average Number of Units Outstanding
The Trust uses the treasury stock method to determine the
dilutive effect of "in the money" options, rights and other
dilutive instruments issued. The basic and diluted calculations
presented in these financial statements are based on the
following weighted average units outstanding:
2003 2002
---------------------------------------------------------------
Basic 42,732,252 22,099,613
Diluted 43,285,647 22,334,714
All outstanding rights have been included in the calculation of
diluted weighted average units outstanding.
l. Change in Accounting Policies
1. Capital Assets
In late 2003 Ultima retroactively adopted the Full Cost Method
of accounting for its capital assets pursuant to the Canadian
Institute of Chartered Accountants ("CICA") Accounting
Guideline ("AcG") 16 "Oil and Gas Accounting - Full Cost".
Previously the Trust used the Successful Efforts Method of
accounting for its capital assets. The effect of the change in
accounting policy on the financial statements of the Trust as
previously presented is as follows:
As at December 31 2003 (1) 2002
---------------------------------------------------------------
Capital Assets, net
As reported $ 301,904 $ 212,092
Adjustment (7,369) (4,162)
---------------------------------------------------------------
As restated $ 294,535 $ 207,930
---------------------------------------------------------------
Net Income
As reported $ 14,644 $ 9,191
Adjustment (2,366) 33
---------------------------------------------------------------
C-105
As restated $ 12,278 $ 9,224
---------------------------------------------------------------
Deficit
Beginning of year $ (13,060) $ (22,251)
Adjustment (4,162) (4,195)
---------------------------------------------------------------
As restated (17,222) (26,446)
Net Income as restated 12,278 9,224
---------------------------------------------------------------
End of year $ (4,944) $ (17,222)
---------------------------------------------------------------
(1) For 2003, the amounts noted as "As reported" reflect the
Successful Efforts Method of accounting for capital assets
as if it had been applied for the full year.
There is no effect on cashflow in either period presented due
to the adoption of the Full Cost Method.
2. Unit Based Compensation Plan
The Trust elected to prospectively adopt amendments to the CICA
Handbook Section 3870, "Stock-Based Compensation and Other
Stock-Based Payments". Pursuant to this accounting standard the
Trust must account for compensation expense based upon the fair
value of the rights awarded under the Plan. As the Trust is
unable to determine the fair value of the rights upon issuance
compensation expense has been determined based upon the
intrinsic value of the rights at the exercise date or at the
date of the financial statements for unexercised rights.
Previously the Trust accounted for compensation expense based
upon the intrinsic value of the rights at the award date.
Because the rights were awarded at fair market value, no
compensation expense was charged to net income at the time of
the award under the previous method of accounting.
The intrinsic value is determined as the excess of the trading
price of the Trust's trust units over the exercise price of the
unexercised rights. For exercised rights the intrinsic value is
determined as the excess of the trading price of the Trust's
trust units over the exercise price of the rights at the time
the rights were exercised.
For rights granted prior to 2003 the Trust elected to continue
accounting for the compensation expense based upon the
intrinsic value at the award date. For rights awarded in 2002
the Trust has disclosed the pro-forma results for 2002 and
2003. However, the net income for 2002 has not been restated.
The pro-forma results are presented in Note 10.
For 2003 the Trust has recorded $260,000 as compensation
expense, noted as a separate line in the income statement.
Included in Unitholders' Equity is contributed surplus of the
same amount. No amounts would have been recorded under the
prior method of accounting.
There was no material effect on net income per unit as a result
of adopting this method of accounting for unit based
compensation.
3. Disclosure of Guarantees
The Trust has adopted AcG-14 "Disclosure of Guarantees". This
guideline requires the Trust to disclose all guarantees to
third parties, of which there are none. There is no effect on
net income or cashflow as a result of adopting this guideline.
C-106
3. Cash Distributions to Unitholders
2003 2002
-----------------------------------------------------------------------
Net income $ 12,278 $ 9,224
Future income tax recovery (note 13) (900) -
Unit based compensation 260 -
Internalization of Management (note 10) 4,716 -
Depletion and amortization 38,526 14,792
-----------------------------------------------------------------------
Cash available for distributions 54,880 24,016
Reclamation fund contributions (note 7) (625) (325)
Cash applied to financing and investing activities (6,120) (2,717)
-----------------------------------------------------------------------
Cash distributions declared 48,135 20,974
Accumulated cash distributions, beginning of year 63,558 42,584
Accumulated cash distributions, end of year $ 111,693 $ 63,558
-----------------------------------------------------------------------
Cash distributions declared per unit $ 1.09 $ 0.90
4. Capital Assets
Accumulated
Oil and natural gas Depletion and
properties Cost Amortization Net Book Value
----------------------------------------------------------------------
2003 $ 443,550 $ 149,015 $ 294,535
2002 321,659 113,729 207,930
The balances shown above have been restated due to the change in
accounting policy whereby the Trust adopted the Full Cost Method of
accounting for its capital assets. See note 2 (l).
Estimated future capital costs included in the 2003 depletion and
amortization calculation were $83,642,000 (2002 - $3,211,000),
primarily attributable to the Weyburn Unit Net Royalty Interest
("Weyburn Unit NRI") acquired on the redemption of the Trust's interest
in the WLP. Excluded from the calculation of depletion and amortization
for 2003 is unproved property attributable to the Weyburn Unit NRI in
the amount of $11,300,000 (2002 - $nil).
Included in the 2003 provision for depletion and amortization is a
provision for future site restoration of $3,239,000 (2002 -
$1,200,000).
5. Trioco Acquisition
On June 26, 2003, the Trust acquired all the issued and outstanding
shares of Trioco Resources Inc. ("Trioco") a private company engaged in
the exploration and development of oil and natural gas in Alberta. The
transaction has been accounted for using the purchase method of
accounting (results of operations have been included as at June 26,
2003) and the allocation of the purchase price is as follows:
C-107
Net assets acquired
Current assets $ 2,546
Capital assets 71,000
Goodwill 16,682
Current liabilities (3,863)
Future income taxes (15,298)
Future site restoration (67)
-----------------------------------------------------------------
$ 71,000
-----------------------------------------------------------------
Paid by
Cash $ 61,000
Bank debt assumed 10,000
-----------------------------------------------------------------
$ 71,000
-----------------------------------------------------------------
6. Weyburn Limited Partnership and Deferred Capital Obligation
Effective November 1, 2000, the Trust acquired a 92% interest in the
WLP in a transaction involving the sale to the WLP of the Trust's Plato
property for $3.3 million and the investment of the proceeds of sale in
the WLP. The capital assets of the WLP were comprised of the Plato
property, the Ferrybank property acquired from another partner and an
11.7% net royalty interest ("Weyburn Unit NRI") in the Weyburn Unit.
The Weyburn Unit NRI was acquired by the WLP from EnCana Resources, the
managing partner of the WLP, in consideration for a note payable for
$77.8 million ($66.9 million as at November 1, 2002). The note payable
is a non-recourse instrument with respect to the Trust's assets held
outside of the WLP.
Effective November 1, 2002, the Trust contributed additional capital of
approximately $66.9 million in cash, before adjustments, to the WLP to
allow repayment in full of the outstanding note payable to EnCana
Resources. The Trust subsequently redeemed its entire limited
partnership interest. As consideration for the redemption, the Trust
received 100% of the WLP's interest in the Weyburn Unit NRI, the
interest in the Plato property, cash and working capital. The Trust
funded the additional capital contribution from the net proceeds of an
equity offering of $46,550,000 along with approximately $20,383,000 of
borrowings drawn from the bank credit facility of Ventures Trust.
The redemption price and consideration paid was as follows:
Net assets acquired on redemption:
Cash and working capital $ 1,042
Capital Assets 84,731
--------------------------------------------------------------------
Total net assets $ 85,773
--------------------------------------------------------------------
Financed by:
Bank borrowings $ 20,383
Trust Units issued 46,550
Deferred capital obligation assumed 18,840
--------------------------------------------------------------------
Total purchase price $ 85,773
--------------------------------------------------------------------
C-108
The deferred capital obligation arose pursuant to the Weyburn Unit NRI
agreement whereby payment for capital costs incurred in connection with
the Weyburn Unit's operations prior to January 1, 2003 was deferred
until the earlier of the date when the costs deferred totalled
$18,778,000 or December 31, 2002. Interest was accrued on the amount
deferred at a base rate of 8.5% per annum. Pursuant to an agreement
with EnCana Resources in connection with the redemption, payment of up
to an additional $15 million of capital expenditures applicable to the
Weyburn Unit NRI will be deferred for the years 2003, 2004 and 2005.
The Trust has the right to select the amount of the payment to be
deferred each year to a maximum of $8 million of deferred expenditures
for any given year. Also beginning January 1, 2003, interest will
accrue on the deferred capital obligation at a base rate of 7% per
annum. Repayment will commence on the earlier of January 1, 2006, or
the date on which the deferred capital payments total $33,778,000. The
deferred capital obligation will be amortized over a 15 year period.
Interest will continue to accrue over the amortization period at a base
rate of 7%, however, the deferred capital obligation repayment terms
include an after-tax equalization component. This component provides
for an effective interest rate over the amortization period of
approximately 10%. The income tax equalization component will primarily
affect the payments made in the latter half of the amortization period.
At December 31, 2003, the capital costs that have been deferred in
accordance with the agreement were $24,437,000. This amount plus
interest of $3,689,000, for a total of $28,126,000, has been recorded
as a long-term obligation. Pursuant to the Weyburn Unit NRI agreement,
the Trust has the right at any time to pre-pay all or any part of the
obligation along with an additional 7% of the amount being prepaid.
Unless the deferred capital obligation is prepaid, the deferred capital
obligation is only payable out of future income from the Weyburn Unit
NRI, and as such the other assets of the Trust do not secure the
deferred capital obligation.
7. Reclamation Fund
Funds have been deducted from cash distributions to unitholders to
provide for the future cost of abandonments and reclamation work on
wells, plants and facilities. The amount of the contribution for 2003
and 2002 was $0.20 per boe of production.
2003 2002
-----------------------------------------------------------------
Reclamation fund, beginning of year $ 748 $ 472
Contributions 625 325
Reclamation expenditures (296) (49)
-----------------------------------------------------------------
Reclamation fund, end of year $ 1,077 $ 748
-----------------------------------------------------------------
8. Long-Term Bank Debt
2003 2002
-----------------------------------------------------------------
Bankers' acceptance notes $ 42,007 $ 30,000
Revolving line of credit 3,000 25,358
-----------------------------------------------------------------
$ 45,007 $ 55,358
-----------------------------------------------------------------
Pursuant to a loan agreement dated June 26, 2003 between Ventures Trust
and a syndicate comprised of the Alberta Treasury Branches and the
National Bank of Canada ("the Syndicate"), Ventures Trust has a
revolving term production loan facility ("the facility") with a maximum
limit of $95,000,000, including a $10,000,000 operating line of credit.
The facility has a 364-day extendable revolving period and a two year
term. Borrowings under the facility bear interest from bank prime plus
0.125% to bank prime plus 1.875%, dependent upon the level of trailing
net debt to operating cashflow. The borrowings are secured by a
$150,000,000 floating charge debenture over all the assets and
undertakings of Ventures Trust, Energy Inc., the Manager, the
Corporation and Acquisitions Corp. The credit facilities are subject to
a semi annual review on May 31 and November 1 each year and upon review
the Syndicate determines if it will extend the revolving period for
another six months. In the event that the Syndicate does not extend the
facility for another six months, there is a two year payment period
with no payments being required for the first year.
C-109
Pursuant to a subordination agreement entered into on June 26, 2003,
the Syndicate has been provided with security over all of the assets of
Ventures Trust, Energy Inc., the Manager, the Corporation and
Acquisitions Corp. in priority to the royalty payable to the Trust by
each of Ventures Trust and Energy Inc. The facility is the legal
obligation of Ventures Trust. Principal and interest payments are
deducted in the calculation of cash available for distribution to
unitholders. In the event that the oil and natural gas properties of
Ventures Trust and Energy Inc. do not generate sufficient income to
discharge the obligation, the unitholders of the Trust will have no
direct liability.
9. Unitholders' Capital
a. Authorized
Unlimited number of trust units
b. Issued
2003 2002
Number of Number of
Trust Units Amount Trust Units Amount
--------------------------------------------------------------------------------------------------
Balance, beginning of year 33,873,808 $ 206,154 18,447,142 $ 134,314
Issued for cash, net of costs 23,000,000 115,197 15,350,000 71,564
Issued on exercise of rights 512,998 3,301 16,666 73
Issued for internalization (note 10) 188,169 - - -
Issued on exercise of options 50,000 169 60,000 203
--------------------------------------------------------------------------------------------------
Balance, end of year 57,624,975 $ 324,821 33,873,808 $ 206,154
--------------------------------------------------------------------------------------------------
In 2003, the Trust issued 23.0 million Trust units for net
proceeds of $115.8 million, before legal and other costs in three
separate equity offerings. These offerings are summarized below:
Number of
Date Trust Units Net Proceeds
-----------------------------------------------------------------------
May 2003 5,000,000 $ 23,988
July 2003 12,000,000 59,280
December 2003 6,000,000 32,490
-----------------------------------------------------------------------
23,000,000 $ 115,758
-----------------------------------------------------------------------
Trust units are retractable at any time on demand by the holders
thereof at a price based on an established formula. The aggregate cash
retraction price payable by the Trust during any calendar month shall
not exceed $100,000 provided that such limitation may be waived at the
discretion of the Boards of Directors of the Corporation (the trustee
for Ventures Trust) and Acquisitions Corp. If a unitholder is not
entitled to receive cash upon the retraction of trust units as a result
of the foregoing limitations, then the retraction price for such trust
units shall be the fair market value thereof as determined by the
Boards of Directors of the Corporation and Acquisitions Corp. and
shall, subject to any applicable regulatory approvals, be paid and
satisfied by way of a distribution in specie of the Trust's interests
in Ventures Trust and Acquisitions Corp., a corporation as yet
inactive, incorporated for the purpose of holding future acquired
corporate shares and facilities, if any.
C-110
c. Trust Unit Options
2003 2002
Exercise Exercise
Number of price per Number of price per
Options unit Options unit
------------------------------------------------------------------------------------------------
Beginning Balance 50,000 $ 3.38 110,000 $ 3.38
Issued during the year - - - -
Less: exercised during the year 50,000 $ 3.38 60,000 $ 3.38
------------------------------------------------------------------------------------------------
Ending Balance - - 50,000 $ 3.38
------------------------------------------------------------------------------------------------
No further options have been issued pursuant to this plan.
d. Trust Unit Rights Incentive Plan
A Trust Units Rights Incentive Plan (the "Plan") was established in
2001. The Trust is authorized to award up to an additional 881,597
rights to the employees of the Manager, and directors of the Trust to
purchase trust units, as a form of long-term performance incentive. The
rights awarded pursuant to the Plan may not be granted at a price that
is less than the prevailing market price of the trust units at the time
of the date of the award, and the maximum term of each right may not
exceed ten years.
The exercise price of each right may be adjusted downwards at the
option of the rights holder from time to time by the amount, if any,
that distributions in any calendar quarter exceed 2.5% of the Trust's
net book value of capital assets.
During the year, the Trust granted 1,044,000 rights to employees of the
Manager and directors of the Corporation and Acquisitions Corp. to
purchase trust units at an average price of $5.27 per unit. Rights
awarded pursuant to the Plan have terms ranging from five to 10 years
and vest equally over three years, commencing on the first anniversary
date of the grant.
A summary of the rights issued, exercised, cancelled and
outstanding pursuant to the Plan is as follows:
2003 2002
Weighted Weighted
Average Average
Number of Exercise Number of Exercise
Rights Price Rights Price
-----------------------------------------------------------------------------------------------------
Balance beginning of year 1,476,667 $ 4.30 1,310,000 $ 4.34
Granted 1,044,000 5.27 240,000 5.23
Exercised 512,998 4.40 16,666 4.40
Cancelled - - 56,667 4.34
-----------------------------------------------------------------------------------------------------
Balance before reduction in
exercise price 2,007,669 4.78 1,476,667 4.49
Reduction of exercise price - (0.38) - (0.19)
-----------------------------------------------------------------------------------------------------
Balance, end of year 2,007,669 $ 4.40 1,476,667 $ 4.30
-----------------------------------------------------------------------------------------------------
A summary of the Plan as at December 31, 2003 is as follows:
Exercise Number of Remaining Number of
Price at Adjusted Rights Contractual Life Rights
Grant Date Exercise Price Outstanding of Rights (years) Exercisable
------------------------------------------------------------------------
$ 4.40 $ 3.70 738,335 8 331,669
$ 5.23 $ 4.69 225,334 9 65,334
$ 5.27 $ 4.85 1,044,000 5 to 10 -
------------------------------------------------------------------------
2,007,669 397,003
------------------------------------------------------------------------
C-111
The Trust has recorded compensation expense and contributed
surplus of $260,000 based upon the year-end trust unit trading
price of $6.24 per trust unit in respect of the rights awarded in
2003.
For rights awarded in 2002 compensation cost for pro forma
disclosure purposes has been determined based on the excess of the
unit price over the exercise price at the date of the financial
statements.
Provided below is the pro forma net earnings and net earnings per
trust unit for the year ended December 31, 2003 and 2002.
(Thousands of dollars) 2003 2002
----------------------------------------------------------------------
Net earnings:
As reported 12,278 9,224
Pro forma 12,014 9,199
Net earnings per share
Basic
As reported 0.29 0.42
Pro forma 0.28 0.42
Diluted
As reported 0.28 0.41
Pro forma 0.28 0.41
10. Related Party Transactions
On March 26, 2003 the Trust, through its subsidiary 1032213 Alberta
Ltd, purchased from WhitePass Capital Inc. all of the issued and
outstanding common shares of the Manager for total consideration of
$3,000,000 in cash and the issuance of 143,365 trust units (valued at
$800,000). The Manager provided the management and administrative
services to the Trust. For 2003 up to the time of the purchase by the
Trust, the Manager was paid $487,000 in management fees. For 2002, it
was paid $1.3 million of management fees and administration fees by the
Trust and the WLP respectively, plus acquisition fees of $1.4 million.
The purchase price of $3,800,000 was recorded as a charge to general
and administrative expense in the quarter, except for furniture and
fixtures in the amount of $137,000, which was capitalized as part of
capital assets.
On July 31, 2003, 1032213 Alberta Ltd. was amalgamated with the Manager
and the resulting entity was named Ultima Management Inc.
In conjunction with the purchase of the Manager and internalization of
the Management Agreement, retention payments of $500,000 in cash and
44,803 trust units with a market value of $250,000 was paid to the
officers and management of the Manager. The three officers will earn an
additional $750,000 to be paid by the issuance of trust units over the
next three anniversary dates of the closing of the transaction should
the Manager still employ them.
The retention paid at the close of the transaction was charged to
general and administrative expense. The remaining retention will be
charged to general and administrative expense when it is incurred.
C-112
11. Financial Instruments
Financial instruments of the Trust include accounts receivable, cash
distributions payable, accounts payable, bank indebtedness, the bank
loan and the deferred capital obligation. There are no significant
differences between the carrying value of these amounts and their
estimated fair value.
Substantially all of the Trust's accounts receivable are due from
customers in the oil and gas industry, and are subject to normal
industry credit risks. The carrying value of the accounts receivable
reflects management's assessment of the associated credit risks.
The Trust is exposed to risks arising from fluctuations in commodity
prices, foreign exchange rates and interest rates. The Trust utilizes a
variety of derivative instruments to reduce its exposure to changes in
commodity prices. The fair values of these derivative instruments are
based on an estimate of the amounts that would have been received from
or paid to counterparties to settle these instruments at year end.
The Trust is exposed to losses in the event of default by the
counterparties to these derivative instruments. The Trust manages this
risk by dealing only with financially sound counterparties and by
utilizing more than one counterparty to build its derivative position.
During 2003, the Trust entered into or assumed as part of a corporate
acquisition, six separate crude oil commodity price hedge arrangements
which are summarized below:
(US$/bbl except as indicated)
Fixed Sold Purchased Sold
Daily Quantity Price Call Put Put Term
------------------------------------------------------------------------
500 bbls 23.40 - - - Calendar 2003
------------------------------------------------------------------------
500 bbls 24.30 - - - Calendar 2003
------------------------------------------------------------------------
1,000 bbls 25.98 - - Jan.1 to June 30, 2003
------------------------------------------------------------------------
1,500 bbls - 30.00 25.00 20.50 Feb.1 to Dec.31 2003
------------------------------------------------------------------------
1,000 bbls 28.05 - - - July 1 to Dec. 31, 2003
------------------------------------------------------------------------
100 bbls - 27.60 25.00 - Calendar 2003
------------------------------------------------------------------------
During 2003, the Trust entered into three separate natural gas
commodity price hedge arrangements, which are summarized below:
Fixed Price
Daily Quantity $Cdn/GJ Term
-------------------------------------------------------------------
4,000 GJ 6.15 Aug.1, 2003 to March 31, 2004
-------------------------------------------------------------------
1,000 GJ 5.69 Jan. 1 to Oct. 31, 2003
-------------------------------------------------------------------
1,000 GJ 7.00 April 1, 2003 to March 31, 2004
-------------------------------------------------------------------
A realized hedging loss of $6.6 million was recorded in oil and natural
gas revenue 2003 (2002 -realized hedging loss of $5.3 million).
The Trust has entered into a variety of crude oil and natural gas
commodity price hedge arrangements for 2004 as summarized below:
Crude Oil Hedges
(all amounts are in US$/bbl except as indicated)
Purchased
Daily Quantity Fixed Price Sold call Put Sold put Term
----------------------------------------------------------------------------------------
1,000 bbls(1) Cdn$ 35.00 - - - Calendar 2004
----------------------------------------------------------------------------------------
1,000 bbls(1) 27.00 - -- - Jan. 1 to June 30, 2004
----------------------------------------------------------------------------------------
800 bbls(1) - 27.50 24.00 20.00 Calendar 2004
----------------------------------------------------------------------------------------
700 bbls(1)&(2) - 30.00 25.00 21.00 Calendar 2004
----------------------------------------------------------------------------------------
C-113
Natural Gas Hedges
Fixed Price
Daily Quantity $/GJ Term
------------------------------------------------------------------
4,000 GJ (1) 6.15 Aug.1, 2003 to March 31, 2004
------------------------------------------------------------------
1,000 GJ (1) 7.00 April 1, 2003 to March 31, 2004
------------------------------------------------------------------
(1) Hedges outstanding as at December 31, 2003. The fair value of
these commodity price hedge arrangements was a loss of $3.6
million, based on quoted market prices and if not available, on
estimates from third-party brokers or dealers or amounts derived
from valuation models.
(2) For clarity:
If WTI Price is (US$/bbl) Ultima receives (US$/bbl)
------------------------------------------------------------------
Greater than $30 $30 per bbl
Between $25 per bbl and $30 per bbl Actual price
Less than $21 per bbl Actual price plus $4.00 per bbl
12. Contingencies and Commitments
The Trust is involved in litigation and claims associated with normal
operations and is of the opinion that any resulting settlements would
not materially affect its financial position or reported results of
operations.
The Trust has entered into an office lease agreement for the Calgary
head office for the period June 1, 2003 to May 31, 2009. The minimum
annual lease payments, before occupancy costs, over the next six years
range from $247,000 at the beginning of the term to $291,000 at the end
of the term.
The Trust has entered into a fixed price purchase contract with its
electricity supplier in central Alberta for 2004 for the purchase of
one megawatt hour per hour ("mwh") at a price of $51.00 per mwh. The
total purchase commitment is $447,000.
Pursuant to the Weyburn Unit NRI agreement the Trust has future
development capital costs associated with carbon dioxide purchases of
$59.5 million, to be incurred over the next 15 years. This amount was
determined by the Trust's independent engineers and is attributable to
the total proved case for the oil and natural gas reserves. The Weyburn
Unit NRI agreement has a provision that, for any given month, cashflow
attributable to the NRI cannot be negative. Accordingly, the Trust's
share of the Weyburn Unit carbon dioxide purchases is only recourse to
the Weyburn Unit NRI, and is non-recourse in nature to the balance of
the Trust's assets.
13. Income Taxes
The provision for current and future income taxes is different than
what would have been calculated by applying the combined federal and
provincial statutory rates to net income before income taxes.
2003
------------------------------------------------------------------
Net income before income taxes $ 11,378
Income tax provision calculated at statutory rates (4,508)
Income attributable to the Trust 5,436
Internalization of management (1,550)
Non-deductible crown charges (9,524)
Resource allowance 10,219
Income tax rate reductions on opening balances 827
------------------------------------------------------------------
Recovery of future taxes $ 900
------------------------------------------------------------------
C-114
The future income tax liability includes the following temporary
differences:
2003
--------------------------------------------------------------
Oil and natural gas properties $ 14,398
--------------------------------------------------------------
There is no 2002 comparative balances presented as the future income
tax is only attributable to a corporate acquisition which closed in
2003.
The crude oil and natural gas properties and related facilities owned
by the corporate subsidiary have a tax basis of $26.7 million (2002 -
$nil) available for future use as deductions in the determination of
taxable income for the subsidiary. There are no loss carry forwards
included in this amount.
14. Differences Between Canadian and United States Generally Accepted
Accounting Principles ("GAAP")
The Trust's consolidated financial statements have been prepared in
accordance with Canadian generally accepted accounting principles
("Canadian GAAP"). These principles, as they pertain to the Trust's
consolidated financial statements, differ from United States generally
accepted accounting principles ("U.S. GAAP") as follows:
a. The Canadian GAAP ceiling test is comparable to the Securities and
Exchange Commission ("SEC") method using constant prices, costs
and tax legislation except that the SEC requires the resulting
amounts to be discounted at 10%.
b. U.S. GAAP utilizes the concept of comprehensive income, which
includes items not included in net income. At the current time,
there is no similar concept under Canadian GAAP. The Trust's net
income under U.S. GAAP is the same as its comprehensive income.
c. U.S. GAAP accounting and reporting standards require that all
derivative instruments (including derivative instruments embedded
in other contracts), as defined, be recorded in the balance sheet
as either an asset or a liability measured at fair value and
requires that changes in fair value be recognized currently in
income unless specific hedge accounting criteria are met. There
are no similar standards under Canadian GAAP at this time.
Hedge accounting treatment allows unrealized gains and losses to
be deferred in other comprehensive income (for the effective
portion of the hedge) until such time as the forecasted
transaction occurs and requires that an entity formally document,
designate and assess effectiveness of derivative instruments that
receive hedge accounting treatment. The Trust has elected to use
fair value accounting for its derivative instruments for U.S. GAAP
and the change in fair value of these contracts has been reported
in income.
d. Prior to January l, 2003, for Canadian GAAP purposes, compensation
expense for options granted under the Trust Unit Rights Incentive
Plan ("the Plan") was measured based on the intrinsic value of the
award at the grant date. For the years ended December 31, 2003 and
2002, pro forma disclosures are included in the notes to the
financial statements of the impact on net income and net income
per Trust unit had the Trust accounted for compensation expense
based on the fair value of rights awarded during 2002. Effective
January l, 2003, the Trust accounts for compensation expense for
rights awarded on or after January 1 , 2003, based on the fair
value method of accounting as described in Note 2.
For U.S. GAAP purposes, the Plan is a variable compensation plan
as the exercise price of the rights is subject to downward
revisions from time to time. Accordingly, compensation expense is
determined as the excess of the market price of the Trust units
over the adjusted exercise price of the rights at each financial
reporting date and is deferred and recognized in income over the
vesting period of the rights. After the rights have vested,
compensation expense is recognized in income in the period in
which a change in the market price of the Trust units or the
exercise price of the rights occurs.
C-115
e. U.S. GAAP accounting and reporting standards requires recognition
of a liability for the retirement obligations associated with
capital assets. These obligations are initially measured at fair
value, which is the discounted future value of the liability. The
liability is accreted each period for the change in present value
and the accretion expense is charged to income. The fair value of
the liability is capitalized as part of the cost of the related
asset and amortized to expense over its useful life. The Trust
adopted these U.S. standards effective January 1, 2003 and the
cumulative effect adjustment has been charged to net income in the
current year. Under current Canadian GAAP and U.S. GAAP prior to
January 1, 2003, asset retirement obligations are accrued using
the unit-of-production method based on the undiscounted value of
the liability.
f. In November 2002, the FASB issued Interpretation No.45,
"Guarantors' Accounting and Disclosure Requirements for
Guarantees, Including Indirect Guarantees of Indebtedness of
Others" (FIN 45). FIN 45 elaborates on the disclosures that must
be made regarding obligations under certain guarantees issued by
the Trust. It also requires that the Trust recognize, at the
inception of a guarantee, a liability for the fair value of the
obligations undertaken in issuing the guarantee. The initial
recognition and initial measurement provisions are to be applied
to guarantees issued or modified after December 31, 2002. There
are no guarantees outstanding at December 31, 2003.
g. The Trust presents cash flow before changes in non-cash operating
working capital as a subtotal in the Consolidated Statement of
Cash Flows. This line item would not be presented in a cash flow
statement prepared in accordance with U.S. GAAP. This difference
does not result in an adjustment to the financial results as
reported under the Canadian GAAP.
h. The following standards issued by the FASB do not have an impact
on the Trust, at the current time:
o FAS 150 "Accounting for Certain Instruments with
Characteristics of Both Liabilities and Equity".
o FIN 46 and FIN 46-R "Consolidation of Variable Interest
Entities".
The Trust will continue to assess the applicability of these
standards in the future.
The application of US GAAP would have the following effects on net
income as reported:
2003 2002
Net Income as reported $ 12,278 $ 9,224
Adjustments:
Unrealized loss on derivatives (3,600) (4,987)
Compensation expense (1,993) (550)
Depletion and depreciation (1,065) -
Asset retirement obligation 2,362 -
--------------------------------------------------------------------------
Net income as adjusted, before 7,982 3,687
cumulative effect of change in
accounting principle
Culmulative effect of change in (1,484) -
accounting principle
--------------------------------------------------------------------------
Net income as adjusted, after $ 6,498 $ 3,687
cumulative effect
--------------------------------------------------------------------------
Net income per unit, as adjusted,
before cumulative effect
Basic $ 0.19 $ 0.17
Diluted $ 0.18 $ 0.17
Net income per unit, as adjusted,
after cumulative effect
Basic $ 0.15 $ 0.17
Diluted $ 0.15 $ 0.17
--------------------------------------------------------------------------
C-116
The application of US GAAP would have the following effects on the
consolidated balance sheets as reported:
Increase
As reported (Decrease) U.S. GAAP
------------------------------------------
December 31, 2003
Oil and gas derivative $ - $ 3,600 $ 3,600
instruments
Capital assets, net 294,535 7,757 302,292
Future Income Taxes 14,398 - 14,398
Accumulated site restoration 8,076 7,944 16,020
Unitholders' Equity $ 208,444 $(3,787) $ 204,657
December 31, 2002
Oil and gas derivative $ - $ 4,987 $ 4,987
instruments
Capital assets, net 207,930 - 207,930
Unitholders' Equity $ 125,374 $(4,987) $ 120,387
15. Subsequent Event
On March 29, 2004, Ultima and Petrofund Energy Trust ("Petrofund")
announced that that they had entered into an agreement providing for
the combination of Petrofund and Ultima. Under the terms of the
agreement, each Ultima unit will be exchanged for 0.442 of a Petrofund
unit on a tax-deferred rollover basis. Ultima unitholders will also
receive an aggregate $10 million in the form of a one-time special
distribution, payable prior to closing the transaction. Subject to
regulatory approval and the approval of Ultima unitholders by a
majority of at least two thirds voting at a meeting to be held on or
about June 4, 2004, the transaction is expected to close on or about
June 16, 2004.
C-117
APPENDIX "D"
UNAUDITED PRO FORMA COMBINED
FINANCIAL STATEMENTS OF PETROFUND ENERGY TRUST
COMPILATION REPORT
To the Directors of Petrofund Corp.:
We have read the accompanying unaudited pro forma combined balance sheet of
Petrofund Energy Trust (the "Trust") as at December 31, 2003 and unaudited pro
forma combined statement of operations for the year then ended, and have
performed the following procedures.
1. Compared the figures in the columns captioned "Petrofund Energy" to the
audited consolidated financial statements of the Trust as at December 31,
2003 and for the year then ended and found them to be in agreement.
2. Compared the figures in the columns captioned "Ultima Energy" to the
audited consolidated financial statements of Ultima Energy Trust as at
December 31, 2003 and for the year then ended and found them to be in
agreement.
3. Made enquiries of certain officers of the Trust who have responsibility for
financial and accounting matters about:
(a) the basis for determination of the pro forma adjustments; and
(b) whether the pro forma combined financial statements comply as to form
in all material respects with the regulatory requirements of the
various securities commissions and regulatory authorities in Canada.
The officers of the Trust:
(a) described to us the basis for determination of the pro forma
adjustments, and
(b) stated that the pro forma statements comply as to form in all material
respects with the regulatory requirements of the various securities
commissions and regulatory authorities in Canada.
4. Read the notes to the pro forma combined financial statements, and found
them to be consistent with the basis described to us for determination of
the pro forma adjustments.
5. Recalculated the application of the pro forma adjustments to the aggregate
of the amounts in the columns captioned "Petrofund Energy" and "Ultima
Energy" as at December 31, 2003 and for the year then ended, and found the
amounts in the column captioned "Pro forma Combined" to be arithmetically
correct.
A pro forma financial statement is based on management assumptions and
adjustments which are inherently subjective. The foregoing procedures are
substantially less than either an audit or a review, the objective of which is
the expression of assurance with respect to management's assumptions, the pro
forma adjustments, and the application of the adjustments to the historical
financial information. Accordingly, we express no such assurance. The foregoing
procedures would not necessarily reveal matters of significance to the pro forma
financial statements, and we therefore make no representation about the
sufficiency of the procedures for the purposes of a reader of such statements.
Calgary, Alberta (signed) Deloitte & Touche LLP
April 30, 2004 Chartered Accountants
D-1
Comments for United Sates of America Readers on Differences
Between Canadian and United States Reporting Standards
The above opinion, provided solely pursuant to Canadian requirements, is
expressed in accordance with standards of reporting generally accepted in
Canada. Such standards contemplate the expression of an opinion with respect to
the compilation of pro forma financial statements. United States of America
standards do not provide for the expression of an opinion with respect to the
compilation of pro forma financial statements. To report in conformity with the
United States of America standards on the reasonableness of the pro forma
adjustments and their application to the pro forma financial statements would
require an examination or review which would be substantially greater in scope
than the review as to compilation only that we have conducted. Consequently,
under the United States of America standards, we would be unable to express any
opinion with respect to the compilation of the accompanying unaudited pro forma
combined financial statements.
Calgary, Alberta (signed) Deloitte & Touche LLP
April 30, 2004 Chartered Accountants
D-2
PRO FORMA COMBINED BALANCE SHEET AS AT DECEMBER 31, 2003
(thousands of Canadian dollars)
(unaudited)
Petrofund Ultima Pro Forma Pro Forma
Energy Energy Adjustments Combined Notes
-----------------------------------------------------------------------------------------------------------------------------------
ASSETS
Current Assets
Cash $ 2,182 $ - $ 732 $ 2,914 2.2
Accounts receivable 48,268 12,442 - 60,710
Prepaid expenses 10,036 1,803 - 11,839
-----------------------------------------------------------------------------------------------------------------------------------
Total current assets 60,486 14,245 732 75,463
Reclamation and Abandonment Reserve 3,779 1,077 - 4,856
Goodwill - 16,682 177,396 194,078 2.1
Oil and Gas Royalty and Property
Interests, net 879,633 294,535 73,599 1,247,767 2.1
-----------------------------------------------------------------------------------------------------------------------------------
$ 943,898 $ 326,539 $ 251,727 $ 1,522,164
===================================================================================================================================
LIABILITIES AND UNITHOLDERS' EQUITY
Current Liabilities
Bank overdraft $ - $ 977 $ (977) $ - 2.2
Accounts payable and accrued
liabilities 36,684 16,613 5,569 58,866
Current portion of capital lease
obligations 356 - - 356
Distributions payable
to Unitholders 53,452 4,898 - 58,350
-----------------------------------------------------------------------------------------------------------------------------------
Total current liabilities 90,492 22,488 4,592 117,572
Long-Term Debt 109,707 45,007 39,000 193,714 2.2
Deferred Capital Obligation - 28,126 (28,126) - 2.2
Capital Lease Obligations 608 - - 608
Future Income Taxes 77,005 14,398 - 91,403
Accrued Reclamation and
Abandonment Costs 16,846 8,076 (8,076) 16,846 2.1
-----------------------------------------------------------------------------------------------------------------------------------
Total liabilities 294,658 118,095 7,390 420,143
Unitholders' Equity 649,240 208,444 244,337 1,102,021 2.1
-----------------------------------------------------------------------------------------------------------------------------------
$ 943,898 $ 326,539 $ 251,727 $ 1,522,164
===================================================================================================================================
The accompanying notes are an integral part of this financial statement.
D-3
PRO FORMA COMBINED STATEMENT OF OPERATIONS AS AT
DECEMBER 31, 2003
(thousands of Canadian dollars, except per unit amounts)
(unaudited)
Petrofund Ultima Pro Forma Pro Forma
Energy Energy Adjustments Combined Notes
-----------------------------------------------------------------------------------------------------------------------------------
REVENUES
Oil and gas sales $ 393,109 $ 111,107 $ - $ 504,216
Royalties, net of incentives (84,804) (21,810) - (106,614)
-----------------------------------------------------------------------------------------------------------------------------------
308,305 89,297 - 397,602
-----------------------------------------------------------------------------------------------------------------------------------
EXPENSES
Lease operating 91,251 25,485 - 116,736
Management fee - 487 (487) - 2.3
Interest on long-term debt 8,748 3,171 1,755 13,674 2.5
General and administrative 13,047 9,914 (4,716) 18,245 2.6
Unit based compensation - 260 - 260
Capital taxes 2,454 76 - 2,530
Depletion and depreciation 113,899 35,286 33,090 182,275 2.4
Site reclamation and abandonment 6,199 3,240 1,724 11,163 2.4
provision
Internalization of management contract 30,850 - 4,716 35,566 2.6
-----------------------------------------------------------------------------------------------------------------------------------
266,448 77,919 36,082 380,449
-----------------------------------------------------------------------------------------------------------------------------------
Income (Loss) Before Provision for Income
Taxes 41,857 11,378 (36,082) 17,153
-----------------------------------------------------------------------------------------------------------------------------------
Provision for (recovery of) income taxes
Current 569 - - 569
Future (44,516) (900) - (45,416)
-----------------------------------------------------------------------------------------------------------------------------------
(43,947) (900) - (44,847)
-----------------------------------------------------------------------------------------------------------------------------------
Net Income $ 85,804 $ 12,278 $ (36,082) $ 62,000
-----------------------------------------------------------------------------------------------------------------------------------
Net Income per Trust unit (Note 3)
Basic $ 1.41 $ 0.71
Diluted $ 1.40 $ 0.71
The accompanying notes are an integral part of this financial statement.
D-4
NOTES TO PRO FORMA COMBINED FINANCIAL STATEMENTS
DECEMBER 31, 2003
(unaudited)
1. BASIS OF PRESENTATION
The accompanying unaudited pro forma combined financial statements (the
"Pro Forma Statements") of Petrofund Energy Trust ("Petrofund") have been
prepared by management in accordance with Canadian generally accepted
accounting principles ("GAAP") for inclusion in the Proxy Statement and
Information Circular (the "Circular") of Ultima Energy Trust ("Ultima")
dated April 30, 2004, with respect to the proposed acquisition of all of
the assets and assumption of all of the liabilities of Ultima by Petrofund.
The Pro Forma Statements have been prepared from, and should be read in
conjunction with, the audited consolidated financial statements of each of
Petrofund and Ultima as at and for the year ended December 31, 2003. Other
information which was available at the time of preparation of the Pro Forma
Statements has also been considered. In the opinion of management, these
Pro Forma Statements include all material adjustments necessary for fair
presentation.
The Pro Forma Statements are not necessarily indicative either of the
results of operations that would have occurred for the year ended December
31, 2003 had the acquisition of Ultima been effected on January 1, 2003, or
of the results of operations expected in 2004 and future years.
In preparing these Pro Forma Statements, no adjustments have been made to
recognize any operating synergies or general and administrative cost
savings which would be expected to occur as a result of combining the
operations of Petrofund and Ultima.
2. PRO FORMA ASSUMPTIONS AND ADJUSTMENTS
The unaudited pro forma combined balance sheet as at December 31, 2003
gives effect to the acquisition by Petrofund of all of the assets of
Ultima, the assumption of all liabilities of Ultima and the redemption of
all of the outstanding trust units of Ultima (other than one trust unit
held by Petrofund) and other adjustments as if they had occurred on
December 31, 2003, while the unaudited pro forma combined statement of
operations for the year ended December 31, 2003 gives effect to such
transactions and other adjustments as if they had occurred on January 1,
2003.
Accounting policies used in the preparation of the Pro Forma Statements are
in accordance with those used in the preparation of the audited financial
statements of Petrofund as at and for the year ended December 31, 2003.
The Pro Forma Statements give effect to the following assumptions and
adjustments:
D-5
NOTES TO PRO FORMA COMBINED FINANCIAL STATEMENTS
AS AT DECEMBER 31, 2003
(unaudited)
2.1 Pursuant to the terms of the combination agreement, Petrofund will issue
approximately 26.4 million Petrofund trust units which will distributed to
the unitholders of Ultima on redemption of their Ultima trust units. After
giving effect to the acquisition, Petrofund will have acquired all of the
assets and assumed all of the liabilities of Ultima, and Ultima Unitholders
will become holders of Petrofund trust units on the basis of 0.442
Petrofund Trust units for each Ultima trust unit. The value assigned to
each Petrofund trust unit of $17.12 was based on the weighted average
trading price of the trust units for the period commencing five days before
and ending five days after the acquisition was announced. The transaction
will be accounted for as an acquisition of Ultima by Petrofund. The
following table illustrates the assumptions made with respect to the
allocation of the purchase price to Ultima's assets and liabilities as at
December 31, 2003.
Purchase Price Allocation $ Cdn (000's)
---------------------------------------------------------------------------
Current assets $ 14,977
Reclamation and abandonment reserve 1,077
Current liabilities (27,080)
Goodwill 194,078
Oil and gas royalty and property interest 368,135
Long-term debt (84,007)
Future income taxes (14,398)
--------------------------------------------------------------------------------
$ 452,782
--------------------------------------------------------------------------------
Approximately $9.0 million in expenses are expected to be incurred to
complete the acquisition and have been included in the determination of the
purchase price.
2.2 Petrofund is to assume Ultima's debt of $45.0 million and it is assumed
that $39.0 million will be borrowed by Petrofund to pay out the deferred
capital obligation, the special distribution of $10 million, transaction
and other costs, less proceeds to be received on the exercise of trust unit
incentive rights.
2.3 The management fees payable to Ultima Management Inc. have been eliminated
to reflect the internalization on January 1, 2003.
2.4 The provision for depletion, depreciation and site reclamation has been
adjusted to reflect the value assigned to Ultima's oil and gas royalty and
property interests and the consolidated oil and gas reserve volumes.
2.5 Interest expense has been adjusted to reflect the increase in long-term
debt.
D-6
2.6 Ultima's costs for the management internalization transaction have been
reclassified for presentation purposes.
3. PER UNIT INFORMATION
Pro forma net income per trust unit has been calculated using the weighted
average number of Petrofund trust units and exchangeable shares of
Petrofund Corp. outstanding during the year ended December 31, 2003 plus
Petrofund trust units to be issued to acquire Ultima as if they had been
outstanding for all of 2003, as follows:
Petrofund Petrofund Trust Pro Forma
(000's) Energy Units Issued Combined
---------------------------------------------------------------------------
Basic 61,010 26,448 87,458
Diluted 61,153 26,448 87,601
4. APPLICATION OF UNITED STATES OF AMERICA GAAP ("US GAAP")
The application of US GAAP would have the following effects on the pro
forma combined net income and net income per trust unit of Petrofund:
($Cdn (000'S) other than per unit amounts)
---------------------------------------------------------------------------
Pro forma combined net income $ 62,000
Petrofund US GAAP adjustments (1) 11,312
Ultima US GAAP adjustments (2) (4,296)
---------------------------------------------------------------------------
Pro forma combined net income, as adjusted, before
cumulative effect of change in accounting principles $69,016
Petrofund cumulative effect of change in accounting
principles, net of income taxes (2,419)
Ultima cumulative effect of change in accounting
principles, net of income taxes (1,484)
Pro Forma combined net income, as adjusted, after
cumulative effect 65,113
Unrealized gain on derivatives, net of income tax expense
of $330 451
---------------------------------------------------------------------------
Pro forma comprehensive income $ 65,564
---------------------------------------------------------------------------
Net income per unit, as adjusted, before cumulative effect:
Basic $ 0.79
Diluted $ 0.79
Net income per unit, as adjusted, after cumulative effect:
Basic $ 0.74
Diluted $ 0.74
D-7
The application of US GAAP would have the following effects on the pro
forma combined balance sheet of Petrofund:
$ Cdn (000's) As reported Petrofund (1) Ultima (2) US GAAP
------------------------------------------------------------------------------------------------------------------------------
Increase/(Decrease)
Oil and gas derivative instruments $ - $ (6,774) $ (3,600) $ 10,374
Oil and gas royalty and property
interests, net 1,247,767 (157,172) 7,757 1,098,352
Future income taxes 91,403 (52,450) 38,953
Accrued reclamation and abandonment costs 16,846 17,517 7,944 42,307
Unitholders' equity 1,102,021 (129,013) (3,787) 969,221
(1) Petrofund's US GAAP adjustments as per its audited financial
statements.
(2) Ultima's US GAAP adjustments as per its audited financial statements.
No other Canadian to US GAAP adjustments arose as a result of the pro
forma adjustments.
D-8
APPENDIX "E"
FAIRNESS OPINION OF CIBC WORLD MARKETS INC.
[LOGO OMITTED]
CIBC World Markets
9th Floor
Bankers Hall East
855 - 2nd Street S.W.
Calgary Alberta
Canada T2P 4J7
Tel. 403-260-0500
April 30, 2004
The Board of Directors
Ultima Ventures Corp.
1000, 350 - 7th Avenue S.W.
Calgary, Alberta T2P 3N9
Dear Sirs:
CIBC World Markets Inc. ("CIBC World Markets" or "we") understand that:
(a) Ultima Energy Trust (together with its subsidiaries, "Ultima") and
Ultima Ventures Corp. have entered into an agreement, as amended (the
"Combination Agreement"), with Petrofund Energy Trust (together with
its subsidiaries, "Petrofund") and Petrofund Corp. providing for the
payment of the Special Distribution (as defined below) and combination
of the businesses of Ultima and Petrofund (collectively with the
Special Distribution, the "Transaction");
(b) pursuant to the Combination Agreement, Ultima will declare and pay a
special distribution (the "Special Distribution") to each Ultima
unitholder ("Ultima Unitholder") of record on the business day
immediately preceding the closing date of the Transaction (the "Closing
Date") equal to such Ultima Unitholder's pro rata share, on the basis
of their holdings of Ultima trust units ("Ultima Units"), of
$10,000,000;
(c) on the Closing Date, among other things:
(i) the assets of Ultima will be transferred to Petrofund in
consideration for the payment to Ultima of 0.442 of a Petrofund
Energy Trust trust unit ("Petrofund Unit") for each Ultima Unit
outstanding (the "Payment Units") and the assumption of the
liabilities of Ultima; and
(ii) Ultima will distribute the Payment Units upon and as consideration
for the redemption and cancellation of the Ultima Units by Ultima,
such that Ultima Unitholders will receive 0.442 of a Petrofund
Unit for each Ultima Unit held on the Closing Date;
(d) the completion of the Transaction will be conditional upon, among other
things, approval by a minimum of 66 2/3% of the votes cast by the
Ultima Unitholders voting at the annual and special meeting of Ultima
Unitholders to be held on June 4, 2004 (the "Annual and Special
Meeting");
CIBC World Markets Inc.
(e) the Closing Date will be June 16, 2004 or such other date mutually
agreed to by Ultima and Petrofund, provided that the Closing Date shall
follow a record date for the payment of a regular monthly cash
distribution by Ultima to the Ultima Unitholders which precedes the
next following record date for the payment of a cash distribution by
Petrofund to the Petrofund unitholders ("Petrofund Unitholders"), and
in any event the Closing Date is no later than July 16, 2004; and
(f) the directors and senior officers of Ultima Ventures Corp. have entered
into support agreements whereby they have agreed to vote all of their
Ultima Units held at the date of the Annual and Special Meeting in
favour of the Transaction.
The terms and conditions of the Transaction are more fully described in the
Notice of Annual and Special Meeting of Unitholders and Proxy Statement and
Information Circular of Ultima dated April 30, 2004 (the "Information Circular")
which will be mailed to Ultima Unitholders in connection with the Annual and
Special Meeting.
Engagement of CIBC World Markets
By letter agreement dated February 12, 2004 and effective January 19, 2004 (the
"Engagement Agreement"), Ultima retained CIBC World Markets to act as financial
advisor to Ultima in connection with its review of specific strategic
alternatives for Ultima to create value for Ultima's Unitholders.
As part of our engagement, we solicited proposals from a number of parties
regarding business combination transactions and we assisted and advised Ultima's
management and the board of directors of Ultima Ventures Corp. (the "Board of
Directors") regarding the relative financial merits of the expressions of
interest received as part of that process. Pursuant to the Engagement Agreement,
Ultima has requested that we prepare and deliver this opinion (the "Opinion") to
the Board of Directors as to the fairness, from a financial point of view, of
the consideration to be received by Ultima Unitholders pursuant to the
Transaction.
CIBC World Markets will be paid a fee for work performed in connection with the
Transaction, a fee for rendering this Opinion and a fee that is contingent upon
completion of the Transaction or certain alternative extraordinary transactions.
CIBC World Markets will also be reimbursed for reasonable expenses. In addition,
Ultima has agreed to indemnify CIBC World Markets in respect of certain
liabilities that might arise out of our engagement.
We are familiar with Ultima and its business. In the two years prior to
commencing this engagement, CIBC World Markets was a participant in the
underwriting syndicate for Ultima's public offerings of Ultima Units pursuant to
short form prospectuses dated May 1, 2002, December 20, 2002, May 22, 2003, July
14, 2003 and December 10, 2003. We are also familiar with Petrofund and its
business. In the two years prior to commencing this engagement, CIBC World
Markets was a co-lead underwriter for Petrofund's public offerings of Petrofund
Units pursuant to short form prospectuses dated March 19, 2002, May 14, 2003 and
December 2, 2003. We also acted as financial advisor to NCE Energy Trust in
connection with its merger with Petrofund effective May 30, 2002 and to the
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CIBC World Markets Inc.
special committee of the board of directors of Petrofund Corp. in connection
with the internalization of the management of Petrofund effective January 1,
2003. Canadian Imperial Bank of Commerce, the sole shareholder of CIBC World
Markets, may, from time to time, provide banking services to Ultima and
Petrofund and their respective affiliates and subsidiaries in the normal course
of its business. As a full-service financial institution, CIBC World Markets and
its affiliates act as trader and dealer, both as principal and agent, in all
major financial markets in Canada and the United States and, as such, may trade
in securities of Ultima and Petrofund.
Credentials of CIBC World Markets
CIBC World Markets is one of Canada's largest investment banking firms with
operations in all facets of corporate and government finance, mergers and
acquisitions, equity and fixed income sales and trading and investment research.
The Opinion expressed herein is the opinion of CIBC World Markets and the form
and content herein have been approved for release by a committee of its managing
directors, each of whom is experienced in merger, acquisition, divestiture and
valuation matters.
Scope of Review
In connection with rendering our Opinion, we have reviewed and relied upon,
among other things, the following:
Transaction Documents:
(a) The Combination Agreement; and
(b) A draft dated April 30, 2004 of the Information Circular.
Financial disclosure of Ultima and Petrofund:
(c) Audited consolidated financial statements of Ultima and Petrofund as at
and for the years ended December 31, 2003, 2002 and 2001;
(d) Annual reports to Ultima Unitholders for the years ended December 31,
2002 and 2001 and to Petrofund Unitholders for the years ended December
31, 2003, 2002 and 2001;
(e) Interim unaudited consolidated financial statements and reports of
Ultima and Petrofund for the three and nine months ended September 30,
2003, three and six months ended June 30, 2003 and three months ended
March 31, 2003;
(f) Annual information forms of Ultima dated April 30, 2004, May 7, 2003
and April 2, 2002;
(g) Annual information forms of Petrofund dated March 15, 2004, March 10,
2003 and March 5, 2002;
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CIBC World Markets Inc.
(h) Information circulars for annual and special meetings of Ultima
Unitholders held on May 23, 2003 and May 27, 2002 and for the annual
and special meetings of Petrofund Unitholders held on April 14, 2004,
April 16, 2003 and May 29, 2002;
(i) Final short form prospectuses of Ultima dated December 10, 2003, July
14, 2003, May 22, 2003, December 20, 2002 and May 1, 2002;
(j) Final short form prospectuses of Petrofund dated December 2, 2003, May
14, 2003 and March 19, 2002; and
(k) Public information related to the business, operations, financial
performance and trading histories of Ultima, Petrofund and other
selected oil and gas companies and royalty trusts, as we considered
relevant.
Reserve and other evaluation information of Ultima and Petrofund:
(l) The evaluation report, effective January 1, 2004, of Gilbert Laustsen
Jung Associates Ltd., independent engineering consultants of Calgary,
Alberta ("GLJ"), regarding certain of the petroleum and natural gas
reserves of Ultima;
(m) The evaluation report, effective January 1, 2004, of McDaniel &
Associates Consultants Ltd., independent engineering consultants of
Calgary, Alberta, regarding the petroleum and natural gas reserves of
Ultima other than those evaluated by GLJ; and
(n) The evaluation report, effective December 31, 2003, of GLJ, regarding
the petroleum and natural gas reserves of Petrofund.
Other Information, Interviews and Discussions:
(o) Financial and operating information, including internal management
forecasts, prepared by or obtained from Ultima and Petrofund;
(p) Discussions with the President and Chief Executive Officer, Vice
President, Chief Financial Officer and Vice President, Chief Operating
Officer of Ultima Ventures Corp. and various senior officers of
Petrofund regarding financial results, budgets and business plans, key
assets and obligations, development projects and abandonment and site
reclamation obligations;
(q) Due diligence meetings with the management, auditors and legal counsel
of Ultima and Petrofund;
(r) Separate letters of representation addressed to us and dated the date
hereof, as to matters of fact relevant to the Transaction from senior
officers of Ultima Ventures Corp. and Petrofund as to the completeness
and accuracy of the information upon which this Opinion is based; and
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CIBC World Markets Inc.
(s) Such other financial, market, corporate and industry information,
research reports, investigations, discussions and analysis, research
and testing of assumptions as we considered necessary or appropriate in
the circumstances.
In addition to the information described above, CIBC World Markets also
participated in discussions with the senior officers of Ultima and Petrofund
with regard to the Transaction and other potential transactions. CIBC World
Markets has also participated in discussions with Bennett Jones LLP, Ultima's
external legal counsel, regarding the Transaction and other potential
transaction alternatives and has participated in discussions with Petrofund's
management, external counsel and financial advisors concerning the Transaction
and related matters.
Assumptions and Limitations
Our Opinion is subject to the assumptions, explanations and limitations set
forth below.
We have not been asked to prepare and have not prepared a formal valuation or
appraisal of Ultima or Petrofund or any of their assets or securities and our
Opinion should not be construed as such.
We have relied upon, and have assumed the completeness, accuracy and fair
presentation of all financial and other information, data, advice, opinions and
representations obtained by us from public sources, or provided to us by Ultima
and Petrofund and their respective advisors or otherwise obtained pursuant to
our engagement, and our Opinion is conditional upon such completeness, accuracy
and fair presentation. We have not been requested or attempted to verify
independently the accuracy, completeness or fairness of presentation of any such
information, data, advice, opinions and representations. With respect to
operating and financial forecasts and budgets provided to us and relied upon in
our analysis, we have assumed that they have been reasonably prepared on bases
reflecting the most reasonable assumptions, estimates and judgements of Ultima's
and Petrofund's management, having regard to their respective plans, financial
condition and prospects. We have also assumed that the Transaction will be
completed substantially in accordance with the Combination Agreement.
Ultima and Petrofund have represented to us, in separate certificates of their
respective senior officers, among other things, that the information, data and
other material (financial and otherwise) provided to us by or on behalf of
Ultima and Petrofund, including the written information and discussions referred
to above under the heading "Scope of Review" (collectively, the "Information"),
was complete, true and correct in all material respects at the date the
Information was provided to us, and that since the dates that the Information
was provided to us, there has been no material change, financial or otherwise,
in the financial condition, assets, liabilities (contingent or otherwise),
business, operations or prospects of Ultima and Petrofund or any of their
affiliates, each taken as a whole, and no material change has occurred in the
Information or any part thereof which would have or which would reasonably be
expected to have a material effect on the Opinion.
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CIBC World Markets Inc.
Our Opinion is rendered on the basis of securities markets, economic and general
business and financial conditions prevailing as at the date hereof and the
conditions and prospects, financial and otherwise, of Ultima and Petrofund as
they are reflected in the Information and as they were represented to us in our
discussions with the senior officers of Ultima and Petrofund. In our analyses
and in connection with the preparation of our Opinion, we made numerous
assumptions with respect to industry performance, general business, market and
economic conditions and other matters, many of which are beyond the control of
any party involved in the Transaction.
The Opinion has been provided to the Board of Directors for its use only and may
not be relied upon by any other person without the prior written consent of CIBC
World Markets. Our Opinion is not to be construed as a recommendation to any
Ultima Unitholder as to how to vote at the Annual and Special Meeting. In
addition, we are not expressing any opinion as to the trading price or value of
the Petrofund Units after completion of the Transaction.
The Opinion is given as of the date hereof and, although we reserve the right to
change or withdraw the Opinion if we learn that any of the information that we
relied upon in preparing the Opinion was inaccurate, incomplete or misleading in
any material respect, we disclaim any obligation to change or withdraw the
Opinion, to advise any person of any change that may come to our attention or to
update the Opinion after the date of this Opinion.
Opinion
Based upon and subject to the foregoing and such other matters as we considered
relevant, it is our opinion, as of the date hereof, that the consideration to be
received by Ultima Unitholders pursuant to the Transaction is fair, from a
financial point of view, to Ultima Unitholders.
Yours very truly,
CIBC World Markets Inc.
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QUESTIONS AND OTHER ASSISTANCE
If you have any questions about the information contained in this
Information Circular or require assistance in completing your form of proxy
(printed on blue paper) or letter of transmittal (printed on yellow paper),
please contact Georgeson Shareholder, the Corporation's proxy solicitation
agent, at:
66 Wellington Street West
TD Tower - Suite 5210
Toronto Dominion Centre
P.O. Box 240
Toronto, Ontario, Canada M5K 1J3
Toll Free Number in Canada and U.S.A.:
1-866-800-4722
PART II
INFORMATION NOT REQUIRED TO BE DELIVERED TO OFFEREES OR PURCHASERS
Under the provisions of the Amended and Restated Trust
Indenture dated as of April 16, 2003 providing for the creation of Petrofund
Energy Trust (the "Registrant"), the trustee is entitled to be indemnified by
the Registrant for any liability and costs, charges and expenses incurred in
respect of any action, suit or proceeding against the trustee in respect of
anything done or the performance by the trustee of its duties, responsibilities
and powers and in respect of the administration and termination of the trust,
unless the trustee shall not have exercised its powers and carried out its
functions honestly, in good faith and in the best interests of the trust and
unitholders.
Under the provisions of the Business Corporations Act
(Alberta), the directors and officers of Petrofund Corp., former directors and
officers and persons who act or acted at the request of Petrofund Corp. as a
director or officer of a corporation of which Petrofund Corp. is or was a
shareholder or creditor, and his or her heirs and legal representatives, are
entitled to be indemnified by Petrofund Corp. against any costs, charges and
expenses including an amount paid to settle an action or satisfy a judgement,
reasonably incurred by him or her in respect of any civil, criminal or
administrative action or proceeding to which he or she is made a party by reason
of being or having been such a director or officer (except in respect of an
action by or on behalf of Petrofund Corp. to procure a judgement in its favor),
if (a) he or she acted honestly and in good faith with a view to the best
interests of Petrofund Corp.; and (b) in the case of a criminal or
administrative action or proceeding that is enforced by a monetary penalty, he
or she had reasonable grounds for believing that his or her conduct was lawful.
Such indemnification may be made in respect of an action by or on behalf of
Petrofund Corp. to procure a judgement in its favor only with prior approval of
the court having jurisdiction and only if such director or officer fulfils the
conditions set forth in (a) and (b) above. Such director or officer is entitled
to such indemnification as a matter of right if he or she was substantially
successful on the merits in his or her defense in the proceeding and fulfils the
conditions set forth in (a) and (b) above.
Liability insurance is in place for the benefit of the
directors and officers, former directors and officers of Petrofund Corp. and
every person who acts or acted at its request as a director or officer of a body
corporate of which Petrofund Corp. is or was a shareholder or creditor, and
their respective heirs and legal representatives, in the amount of Cdn.
$25,000,000 subject to a deductible of Cdn. $150,000 per claim.
Insofar as indemnification for liabilities arising under the
Securities Act of 1933, as amended (the "Securities Act") may be permitted to
directors, officers or persons controlling the Registrant pursuant to the
foregoing provisions, the Registrant has been informed that, in the opinion of
the U.S. Securities and Exchange Commission, such indemnification is against
public policy as expressed in the Securities Act and is therefore unenforceable.
II-1
Exhibits
--------
Exhibit
Number Description
------ -----------
1.1 The form of proxies accompanying the Information Circular
1.2 Letter of Transmittal accompanying the Information Circular
2.1 The Combination Agreement among Ultima Energy Trust, Ultima
Ventures Corp., Petrofund Energy Trust and Petrofund Corp. dated
March 29, 2004
2.2 The Amending Agreement among Ultima Energy Trust, Ultima Ventures
Corp., Petrofund Energy Trust and Petrofund Corp. dated April 30,
2004, amending the Combination Agreement dated March 29, 2004
5.1 Consent of Bennett Jones LLP
5.2 Consents of Deloitte & Touche LLP
5.3 Consent of Collins Barrow Calgary LLP
5.4 Consents of Gilbert Laustsen Jung Associates Ltd.
5.5 Consent of McDaniel & Associates Consultants Ltd.
5.6 Consent of CIBC World Markets Inc.
6.1 Power of Attorney (included on the signature page of this
Registration Statement)
II-2
PART III
UNDERTAKING AND CONSENT TO SERVICE OF PROCESS
Item 1. 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 F-10 or to transactions
in said securities.
Item 2. Consent to Service of Process
Concurrently with the filing of this Registration Statement on Form
F-10, the Registrant and Computershare Trust Company of Canada, as trustee with
respect to the securities registered hereby, are filing with the Commission a
written irrevocable consent and power of attorney on Form F-X.
III-1
SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, the
Registrant certifies that it has reasonable grounds to believe that it meets all
of the requirements for filing on Form F-10 and has duly caused this
Registration Statement to be signed on its behalf by the undersigned, thereunto
duly authorized, in the City of Calgary, Province of Alberta, Canada, on April
30, 2004.
PETROFUND ENERGY TRUST
By: PETROFUND CORP.
By: /s/ Jeffery E. Errico
-------------------------------
Jeffery E. Errico
President and Chief Executive Officer
III-2
POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS, that each person whose signature
appears below constitutes and appoints each of Jeffery E. Errico and Vince P.
Moyer, his true and lawful attorney-in-fact and agent, with full power of
substitution and resubstitution, for him in his name, place and stead, in any
and all capacities, to sign any and all amendments (including post-effective
amendments) and supplements to this Registration Statement, and to file the
same, with all exhibits hereto, and other documents in connection therewith,
with the Securities and Exchange Commission, granting unto said
attorneys-in-fact and agents, and each acting alone, full power and authority to
do and perform each and every act and thing requisite and necessary to be done,
as fully to all intents and purposes as they might or could do themselves,
hereby ratifying and confirming all that said attorneys-in-fact and agents or
any of them acting alone, or his or their substitute or substitutes, may
lawfully do or cause to be done by virtue hereof.
Pursuant to the requirements of the Securities Act of 1933, this
Registration Statement has been signed by the following persons in the
capacities indicated on April 30, 2004:
Signature Title
--------- -----
/s/ Jeffery E. Errico President and Chief Executive Officer,
-------------------------------- Petrofund Corp.
Jeffery E. Errico (principal executive officer)
/s/ Vince P. Moyer Senior Vice President, Finance and,
-------------------------------- Chief Financial Officer
Vince P. Moyer Petrofund Corp.
(principal financial and accounting officer)
/s/ James E. Allard Director, Petrofund Corp.
--------------------------------
James E. Allard
/s/ Sandra S. Cowan Director, Petrofund Corp.
--------------------------------
Sandra S. Cowan
/s/ John F. Driscoll Director, Petrofund Corp.
--------------------------------
John F. Driscoll
/s/ Jeffery E. Errico Director, Petrofund Corp.
--------------------------------
Jeffery E. Errico
/s/ Wayne M. Newhouse Director, Petrofund Corp.
--------------------------------
Wayne M. Newhouse
/s/ Frank Potter Director, Petrofund Corp.
--------------------------------
Frank Potter
/s/ Peter N. Thomson Director, Petrofund Corp.
--------------------------------
Peter N. Thomson
III-3
Pursuant to the requirements of Section 6(a) of the Securities Act of
1933, the Authorized Representative has signed this Registration Statement,
solely in his capacity as the duly authorized representative of Petrofund Energy
Trust in the United States, in the City of Newash, State of Delaware, on April
30, 2004.
PUGLISI & ASSOCIATES
(Authorized U.S. Representative)
By: /s/ Donald J. Puglisi
----------------------------------
Name: Donald J. Puglisi
Title: Managing Director
III-4
Exhibits
--------
Exhibit
Number Description Page Number
------ ----------- -----------
1.1 The form of proxies accompanying the Information Circular
1.2 Letter of Transmittal accompanying the Information
Circular
2.1 The Combination Agreement between Ultima Energy Trust,
Ultima Ventures Corp., Petrofund Energy Trust and
Petrofund Corp. dated March 29, 2004
2.2 The Amending Agreement among Ultima Energy Trust, Ultima
Ventures Corp., Petrofund Energy Trust and Petrofund
Corp. dated April 30, 2004, amending the Combination
Agreement dated March 29, 2004
5.1 Consent of Bennett Jones LLP
5.2 Consents of Deloitte & Touche LLP
5.3 Consent of Collins Barrow Calgary LLP
5.4 Consents of Gilbert Laustsen Jung Associates Ltd.
5.5 Consent of McDaniel & Associates Consultants Ltd.
5.6 Consent of CIBC World Markets Inc.
6.1 Power of Attorney (included on the signature page of this
Registration Statement)