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EXHIBIT 99.119
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ADVANTAGE ENERGY INCOME FUND
RENEWAL ANNUAL INFORMATION FORM
2003
May 12, 2004
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TABLE OF CONTENTS
Page
GLOSSARY OF TERMS ......................................................... 1
ABBREVIATIONS ............................................................. 6
CONVERSION ................................................................ 6
ADVANTAGE ENERGY INCOME FUND .............................................. 8
GENERAL DEVELOPMENT OF THE BUSINESS ....................................... 9
DESCRIPTION OF THE BUSINESS AND OPERATIONS ................................ 12
STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION .............. 13
REPORT OF MANAGEMENT AND DIRECTORS ON RESERVES DATA AND OTHER INFORMATION . 27
REPORT ON RESERVES DATA ................................................... 28
ADDITIONAL INFORMATION RESPECTING ADVANTAGE ENERGY INCOME FUND ............ 29
ADDITIONAL INFORMATION RESPECTING ADVANTAGE OIL & GAS LTD ................. 36
ADDITIONAL INFORMATION RESPECTING ADVANTAGE INVESTMENT MANAGEMENT LTD ..... 42
MARKET FOR SECURITIES ..................................................... 48
PROMOTERS ................................................................. 49
LEGAL PROCEEDINGS ......................................................... 49
INTEREST OF INSIDERS AND OTHERS IN MATERIAL TRANSACTIONS .................. 49
AUDITORS, TRANSFER AGENT AND REGISTRAR .................................... 49
MATERIAL CONTRACTS ........................................................ 49
INTEREST OF EXPERTS ....................................................... 50
RISK FACTORS .............................................................. 50
ADDITIONAL INFORMATION .................................................... 59
SCHEDULE "A" - FINANCIAL STATEMENTS OF MARKWEST RESOURCES CANADA CORP.
SCHEDULE "B" - UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS
GLOSSARY OF TERMS
"8 1/4% Debentures" means the 8 1/4% convertible unsecured subordinated
debentures of the Trust due February 1, 2009;
"8 1/2% Note Indenture" means the trust indenture providing for the issuance of
the 8 1/2% Notes dated December 2, 2003 and made between AOG and Computershare
Trust Company of Canada, as trustee;
"8 1/2% Notes" means the 8 1/2% unsecured subordinated promissory notes of AOG
issued pursuant to the 8 1/2% Note Indenture;
"9% Debentures" means the 9.00% convertible unsecured subordinated debentures of
the Trust due August 1, 2008;
"9 3/8% Note Indenture" means the trust indenture providing for the issuance of
the 9 3/8% Notes dated July 8, 2003 and made between AOG and Computershare Trust
Company of Canada, as trustee;
"9 3/8% Notes" means the 9 3/8% unsecured subordinated promissory notes of AOG
issued pursuant to the 9 3/8% Note Indenture;
"10% Debentures" means the 10% convertible unsecured subordinated debentures of
the Trust due November 1, 2007;
"10 3/8% Notes" means the 10 3/8% unsecured subordinated promissory notes of AOG
issued pursuant to the 10 3/8% Note Indenture;
"10 3/8% Note Indenture" means the trust indenture providing for the issuance of
the 10 3/8% Notes dated October 18, 2002 and made between AOG and Computershare
Trust Company of Canada, as trustee;
"14% Note Indenture" means the trust indenture providing for the issuance of the
14% Notes dated May 24, 2001 and made between AcquisitionCo and Computershare
Trust Company of Canada, as trustee and as amended by the supplemental note
indenture dated December 14, 2001;
"14% Notes" means the 14% unsecured subordinated promissory notes of AOG issued
pursuant to the 14% Note Indenture;
"ABCA" means the Business Corporations Act (Alberta), R.S.A. 2000, c. B-9, as
may be amended, including the regulations promulgated thereunder;
"AcquisitionCo" means 925212 Alberta Ltd., a corporation incorporated under the
ABCA that, prior to the Amalgamation, was wholly-owned by the Trust;
"AcquisitionCo Units" means the units of AcquisitionCo, each such unit
consisting of one AcquisitionCo common share and a Note;
"Affiliate" or "Associate" when used to indicate a relationship with a person or
company, means the same as set forth in the Securities Act (Alberta);
"Amalgamation" means the amalgamation of AOG and AcquisitionCo pursuant to the
Arrangement;
"AOG" or "Corporation" means Advantage Oil & Gas Ltd., formerly Search Energy
Corp., a corporation incorporated under the ABCA and a wholly-owned subsidiary
of the Trust. All references to "AOG", unless the context otherwise requires,
are references to Advantage Oil & Gas Ltd. and its predecessors;
"Arrangement" means the transaction described under the heading "General
Development of the Business - History and Development - Advantage Energy Income
Fund";
"Arrangement Agreement" means the agreement dated April 18, 2001 between AOG,
AcquisitionCo and the Trust pursuant to which such parties proposed to implement
the Arrangement;
"ARC" means credits or rebates in respect of Crown royalties which are paid or
credited by the Crown, including those paid or credited under the Alberta
Corporate Tax Act which are commonly known as "Alberta Royalty Credits";
2
"Asset Transfer" means the transactions whereby the Vendors and Gascan
transferred and assigned to Newco all of their respective right, title, estate
and interest in and to the PNG Assets (as defined in the Share Purchase
Agreement) in consideration of the issuance to the Vendors of common shares of
Newco in accordance with the terms and conditions of the Asset Transfer
Agreement;
"Asset Transfer Agreement" means the agreement among the Vendors, Newco and
Gascan providing for the Asset Transfer;
"Audit Committee" means the audit committee of the Trust;
"Best Pacific" means Best Pacific Resources Ltd., a corporation incorporated
under the ABCA;
"Best Pacific Acquisition" means the acquisition of Best Pacific by the Trust;
"Board of Directors" or "Board" means the board of directors of AOG or its
successors;
"Business Day" means a day, which is not a Saturday, Sunday or statutory
holiday, when banks in the place at which any action is required to be taken
hereunder are generally open for the transaction of commercial banking business;
"Common Shares" means voting common shares in the capital of AOG;
"crude oil" or "oil" means a mixture, consisting mainly of pentanes and heavier
hydrocarbons, that may contain sulphur compounds, that is liquid at the
conditions under which its volume is measured or estimated, but excluding such
liquids obtained from the processing of natural gas;
"Debentures" means, collectively, the 8 1/4% Debentures, 9% Debentures and the
10% Debentures;
"Distributable Income" means all amounts distributed or to be distributed in
accordance with the Trust Indenture during any applicable period to Trust
Unitholders;
"Distribution Record Date" means, until otherwise determined by the Trustee, the
last day of each month of each year, provided that if the last day of the month
is not a Business Day, then the Distribution Record Date for such month will be
the first Business Day following the last day of each month of the year or such
other dates in any year determined from time to time by the Trustee, but
December 31 in each year shall be a Distribution Record Date;
"Due West" means Due West Resources Inc., a corporation incorporated under the
ABCA, acquired by AOG on July 26, 2001 and amalgamated with AOG on August 1,
2001;
"Gascan" means Gascan Resources Ltd., a corporation incorporated under the ABCA;
"Gascan Acquisition" means the acquisition by AOG of all of the issued and
outstanding securities of Newco pursuant to the Share Purchase Agreement;
"Gascan Assets" means all of the PNG Assets (as defined in the Share Purchase
Agreement);
"General and Administrative Costs" means the amount in aggregate representing
all expenditures and costs incurred by the Manager in carrying out its
obligations or duties hereunder in respect of AOG, the Royalty or the Trust or
in the management and administration of AOG, the Royalty and the Trust
including, without limitation: (a) all reasonable costs and expenses relating to
AOG, the Royalty and the Trust and paid directly to third parties by or on
behalf of AOG, the Trust or their affiliates, including, without limitation,
Trustee's fees; and (b) all reasonable costs and expenses incurred specifically
for AOG or the Trust relating to AOG, the Royalty or the Trust including
auditing, accounting, bookkeeping, rent and other leasehold expenses, legal,
land administration, engineering, travel, telephone, data processing, reporting
and all other reasonable costs and expenses approved by the Board, from time to
time, and incurred by the Manager in discharging its obligations hereunder in
respect of AOG, the Royalty or the Trust (other than the Management Fees). For
greater clarity, employee bonuses and amounts paid to employees under incentive
plans are not reimbursable;
3
"Initial Permitted Securities" means any equity or debt securities, or rights
thereto, authorized or issued from time to time by AOG including, without
limitation, the Common Shares, Preferred Shares and Notes;
"Management Agreement" means the management, advisory and administration
agreement dated May 24, 2001 among AcquisitionCo, the Manager and the Trustee on
behalf of the Trust;
"Management Fees" has the meaning set forth under the heading "Additional
Information Respecting Advantage Investment Management Ltd. - Compensation and
Term";
"Manager" means Advantage Investment Management Ltd., a corporation incorporated
under the ABCA;
"ManagementCo Group" means Affiliates and Associates of the Manager, and
officers and directors (and their respective Associates) of the Manager and
Affiliates of the Manager;
"Market Capitalization" means an amount equal to the weighted average number of
Trust Units outstanding for the Return Period times the Unit Market Price at the
beginning of the Return Period;
"MarkWest" means MarkWest Resources Canada Corp., a corporation incorporated
under the ABCA;
"MarkWest Properties" means the oil and natural gas properties that were owned
by MarkWest;
"Newco" means 960110 Alberta Ltd., being the wound-up, wholly-owned Subsidiary
of AOG, which company was the legal and beneficial owner of the Gascan Assets
upon completion of the Asset Transfer;
"natural gas" means the lighter hydrocarbons and associated non-hydrocarbon
substances occurring naturally in an underground reservoir which, under
atmospheric conditions, is essentially gas but which may contain liquids. The
natural gas reserve estimates are reported on a marketable basis; that is, the
gas which is available to a transmission line after removal of certain
hydrocarbons and non-hydrocarbon compounds present in the raw natural gas and
which meets specifications for use as a domestic, commercial or industrial fuel;
"natural gas liquids" or "NGLs" means those hydrocarbon components recovered
from raw natural gas as liquids by processing through extraction plants or
recovered from field separators, scrubbers or other gathering facilities. These
liquids include the hydrocarbon components ethane, propane, butanes and pentanes
plus, or a combination thereof;
"Note Indentures" means collectively, the 14% Note Indenture, 10 3/8% Note
Indenture, 9 3/8% Note Indenture and the 8 1/2% Note Indenture;
"Note Trustee" means Computershare Trust Company of Canada, or its successor as
trustee under 14% Note Indenture, 10 3/8% Note Indenture, 9 3/8% Note Indenture
and 8 1/2% Note Indenture;
"Notes" means collectively, the 8 1/2% Notes, 9 3/8% Notes, 10 3/8% Notes and
14% Notes;
"Oil and Natural Gas Properties" or "Properties" means the working, royalty or
other interests of AOG in any petroleum and natural gas rights, tangibles and
miscellaneous interests, including properties which may be acquired by AOG from
time to time;
"OPEC" means Organization of the Petroleum Exporting Countries;
"Operating Cash Flow" means, in respect of any period for which Operating Cash
Flow is calculated: (i) the amount received or receivable by AOG (on a
consolidated basis) in respect of the sale of all Petroleum Substances from the
Properties and any oil and gas revenue received in such period, including any
commodity hedging gains and ARC but not including proceeds of the sale of
Properties; plus (ii) income and distributions received by the Trust from any
Permitted Investments, but not including any proceeds of sale of Permitted
Investments; less (iii) expenditures paid or payable by or on behalf of AOG (on
a consolidated basis) in respect of operating the Properties including, without
limitation, the costs of gathering, compressing, processing, transporting and
marketing all Petroleum Substances produced therefrom, commodity hedging losses
and all other amounts paid to third parties which are calculated with reference
to production from the Properties, including, without limitation, crown
4
royalties, gross overriding royalties and lessors' royalties, but for certainty
not deducting the Royalty or any royalties payable to the Trust by AOG in all
other respects;
"Non-Voting Shares" means the non-voting common shares in the capital of AOG;
"Permitted Investments" means, with respect to up to 25% of the total assets of
the Trust, (unless otherwise approved by the Board of Directors from time to
time): (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
institutions (including the Trustee and any affiliate of the Trustee) the
short-term debt or deposits of which have been rated at least A or the
equivalent by Standard & Poor's Corporation, Moody's Investors Service, Inc. or
Dominion Bond Rating Service Limited; (iii) commercial paper rated at least A or
the equivalent by Dominion Bond Rating Service Limited, in each case maturing
within 180 days after the date of acquisition; and (iv) trust units and limited
partnership units in trusts and limited partnerships which invest in energy
related assets including all types of petroleum and natural gas and energy
related assets, and including, without limitation, facilities of any kind, oil
sands interests, coal, electricity or power generating assets, and pipeline,
gathering, processing and transportation assets;
"person" means any individual, partnership, association, body corporate,
trustee, executor, administrator, legal representative, government, regulatory
authority or other entity;
"Petroleum Substances" means petroleum, natural gas and related hydrocarbons
(except coal) including, without limitation, all liquid hydrocarbons, and all
other substances, including sulphur, whether gaseous, liquid or solid and
whether hydrocarbon or not, produced in association with such petroleum, natural
gas or related hydrocarbons;
"Preferred Shares" means first preferred shares in the capital of AOG, which
shares are issuable in series;
"pro rata share" of any particular amount in respect of a holder of a Trust Unit
at any time shall be the product obtained by multiplying the number of Trust
Units that are owned by that Trust Unitholder at that time by the quotient
obtained when the particular amount is divided by the total number of all Trust
Units that are issued and outstanding at that time;
"Reorganization" means the reorganization of AOG into an income trust structure;
"Reorganization Agreement" means the reorganization letter agreement dated April
1, 2001 between AOG and the Manager; "Resource Properties" means Canadian
resource properties as defined in the Tax Act;
"Return Period" means the period for which the management fees under the
Management Agreement are being calculated, which period shall be a calendar
year, except for any year in which the Management Agreement is terminated, in
which case the return period shall commence at the start of such year and end on
the date of such termination;
"Royalty" means the 95% interest in AOG 's Petroleum Substances within, upon or
under certain of its Oil and Natural Gas Properties granted pursuant to the
Royalty Agreement;
"Royalty Agreement" means the amended and restated royalty agreement entered
into between AOG and the Trust dated as of December 2, 2003 and providing for
the creation of the Royalty;
"Settled Amount" means the amount of one hundred dollars in lawful money of
Canada paid by the settlor of the Trust to the Trustee for the purpose of
settling the Trust;
"Share Purchase Agreement" means the share purchase agreement between AOG and
the Vendors dated November 28, 2001 providing for the purchase by AOG of all of
the issued and outstanding shares of Newco;
"Shareholder Agreement" means the shareholder agreement entered into as of May
24, 2001 between AOG and the Trustee, as trustee for and on behalf of the Trust;
5
"Sproule" means Sproule Associates Limited, independent geological and petroleum
engineering consultants of Calgary, Alberta;
"Sproule Report" means the independent engineering evaluation of AOG 's oil, NGL
and natural gas interests prepared by Sproule dated April 19, 2004 and effective
December 31, 2003;
"Subsequent Investment" means those investments which the Trust is permitted to
make pursuant to the Trust Indenture, namely royalties in respect of Properties
and securities of AOG or any other Subsidiary of the Trust to fund the
acquisition, development, exploitation and disposition of all types of petroleum
and natural gas and energy related assets, including without limitation,
facilities of any kind, oil sands interests, coal, electricity or power
generating assets, and pipeline, gathering, processing and transportation assets
and whether effected through an acquisition of assets or an acquisition of
shares or other form of ownership interest in any entity the substantial
majority of the assets of which are comprised of like assets;
"Subsidiary" means, when used to indicate a relationship with another body
corporate:
(a) a body corporate which is controlled by (i) that other, or (ii) that
other and one or more bodies corporate, each of which is controlled
by that other, or (iii) two or more bodies corporate each of which
is controlled by that other, or
(b) a subsidiary of a body corporate that is the other's subsidiary;
(c) and, in the case of the Trust, shall include AOG;
"Tax Act" means the Income Tax Act (Canada), R.S.C. 1985, c.1, 5th Supplement,
as amended;
"Total Return Amount" means, in respect of any Return Period, an amount equal to
the Total Return Percentage minus 8.0% if the Return Period is a full calendar
year, and adjusted on a pro rata basis should the Return Period be less than a
full calendar year, multiplied by the Market Capitalization for that Return
Period;
"Total Return Percentage" means the annual rate of return percentage to a holder
of a Trust Unit for a particular Return Period based upon the difference between
the Unit Market Price at the beginning and end of the Return Period plus the
cash distributions per Trust Unit divided by the Unit Market Price at the
beginning of the Return Period;
"Trust", "Fund" or "Advantage" means Advantage Energy Income Fund, a trust
established under the laws of Alberta pursuant to the Trust Indenture. All
references to "Trust", "Advantage" or the "Fund", unless the context otherwise
requires, are references to Advantage Energy Income Fund, its predecessors, and
its subsidiaries;
"Trustee" means Computershare Trust Company of Canada or such other trustee,
from time to time, of Advantage Energy Income Fund;
"Trust Fund", at any time, shall mean such of the following monies, properties
and assets that are at such time held by the Trustee for the purposes of the
Trust under the Trust Indenture: (i) the Settled Amount; (ii) the Initial
Permitted Securities; (iii) the Royalty; (iv) all funds realized from the sale
of, or Permitted Investments obtained in exchange for, Trust Units from time to
time; (v) any Permitted Investments in which funds may from time to time be
invested; (vi) any Subsequent Investments; (vii) any proceeds of disposition of
any of the foregoing property including, without limitation, the Royalty but not
Trust Units in the case of a redemption thereof to which Section 9.5 of the
Trust Indenture applies; and (viii) all income, interest, dividends, return of
capital, profit, gains and accretions and additional assets, rights and benefits
of any kind or nature whatsoever arising directly or indirectly from or in
connection with or accretions to or accruals in respect of any of the foregoing
property or such proceeds of disposition from time to time;
"Trust Indenture" means the amended and restated trust indenture dated as of May
28, 2003 between Computershare Trust Company of Canada and AOG;
"Trust Unit" means a unit of the Trust, each unit representing an equal
undivided beneficial interest therein;
"Trust Unitholders" or "Unitholders" means the holders from time to time of the
Trust Units;
6
"TSX" means the Toronto Stock Exchange;
"Unit Market Price" of the Trust Units at any date means the weighted average of
the trading price per Trust Unit for such Trust Units for the ten (10)
consecutive trading days immediately preceding such date and the ten (10)
consecutive trading days from and including such date, on the TSX or, if on such
date the Trust Units are not listed on the TSX, on the principal stock exchange
upon which such Trust Units are listed, or, if such Trust Units are not listed
on any stock exchange, then on such over-the-counter market as may be selected
for such purposes by the Board of Directors;
"United States" or "US" means the United States of America; and
"Vendors" means the holders of all of the issued and outstanding shares of Newco
following the Asset Transfer and prior to the acquisition of Newco by AOG, and
"Vendor" means any one of them.
Words importing the singular number only include the plural, and vice versa, and
words importing any gender include all genders. All dollar amounts set forth in
this Annual Information Form are in Canadian dollars, except where otherwise
indicated.
ABBREVIATIONS
Oil and Natural Gas Liquids Natural Gas
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bbls barrels mcf thousand cubic feet
mbbls thousand barrels mmcf million cubic feet
mmbbls million barrels bcf billion cubic feet
NGLs natural gas liquids mcf/d thousand cubic feet per day
stb stock tank barrels of oil mmcf/d million cubic feet per day
mstb thousand stock tank barrels of oil m(3) cubic metres
mmboe million barrels of oil equivalent mmbtu million British Thermal Units
boe/d barrels of oil equivalent per day GJ Gigajoule
bbls/d barrels of oil per day
Other
- -----
BOE or boe means barrel of oil equivalent, using the conversion factor of 6 mcf of
natural gas being equivalent to one bbl of oil. The conversion factor used to
convert natural gas to oil equivalent is not necessarily based upon either energy
or price equivalents at this time.
WTI means West Texas Intermediate.
(Degree)API means the measure of the density or gravity of liquid petroleum products derived
from a specific gravity.
psi means pounds per square inch.
CONVERSION
The following table sets forth certain 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 kilometres 1.609
kilometres miles 0.621
acres hectares 0.405
hectares acres 2.471
gigajoules mmbtu 0.950
7
YOU SHOULD NOT RELY ON FORWARD-LOOKING STATEMENTS
BECAUSE THEY ARE INHERENTLY UNCERTAIN
This annual information form contains forward-looking statements. These
statements relate to future events or the Trust's future performance. All
statements other than statements of historical fact are forward-looking
statements. The use of any of the words "anticipate", "plan", "continue",
"estimate", "expect", "may", "will", "project", "predict", "potential",
"should", "believe" and similar expressions are intended to identify
forward-looking statements. These statements involve known and unknown risks,
uncertainties and other factors that may cause actual results or events to
differ materially from those anticipated in such forward-looking statements. The
Trust and AOG believe the expectations reflected in those 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, or
incorporated by reference into, this annual information form should not be
unduly relied upon. These statements speak only as of the date of this annual
information form or as of the date specified in the documents incorporated by
reference into this annual information form, as the case may be.
In particular, this annual information form, and the documents incorporated by
reference, contain forward-looking statements pertaining to the following:
o oil and natural gas production levels;
o the size of the oil and natural gas reserves;
o projections of market prices and costs and the related sensitivities of
distributions;
o supply and demand for oil and natural gas;
o expectations regarding the ability to raise capital and to continually add
to reserves through acquisitions and development;
o treatment under governmental regulatory regimes; and
o capital expenditures programs.
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 annual information form:
o volatility in market prices for oil and natural gas;
o liabilities inherent in oil and natural gas operations;
o uncertainties associated with estimating oil and natural gas reserves;
o competition for, among other things, capital, acquisitions of reserves,
undeveloped lands and skilled personnel;
o incorrect assessments of the value of acquisitions;
o geological, technical, drilling and processing problems; and
o the other factors discussed under "Risk Factors".
These factors should not be construed as exhaustive. None of the Trust, the
Manager, nor AOG undertakes any obligation to publicly update or revise any
forward-looking statements.
8
ADVANTAGE ENERGY INCOME FUND
Corporate Structure
Advantage Energy Income Fund, Advantage Oil & Gas Ltd. and Advantage Investment
Management Ltd.
Advantage Energy Income Fund is an entity that provides monthly cash
distributions to its Unitholders. Advantage was created under the laws of the
province of Alberta pursuant to the Trust Indenture. It is, for Canadian tax
purposes, an open-ended mutual fund trust and is categorized as a "natural
resource issuer" for the purposes of Canadian securities laws. The Trust is
administered by the Trustee. The beneficiaries of the Trust are the Unitholders.
AOG is an oil and natural gas exploitation and development company that is
wholly-owned by the Trust. It was originally incorporated in 1979 as Westrex
Energy Corp. ("Westrex"). Through a plan of arrangement under the ABCA, Westrex
merged with Search Energy Inc. on December 31, 1996, and changed its name to
Search Energy Corp. ("Search") on January 2, 1997. The management of Westrex
was, for the most part, replaced with the management of Search. The merger was
accounted for as a "reverse take-over" in accordance with Canadian generally
accepted accounting principles.
Effective May 24, 2001, all of the issued and outstanding common shares of
Search were acquired by AcquisitionCo, a corporation wholly-owned by the Trust,
and Search and AcquisitionCo were then amalgamated and continued as "Search
Energy Corp.". On July 26, 2001, Search acquired all of the shares of Due West.
Due West's oil and natural gas properties were comprised of mainly long life
natural gas and light oil reserves, many of which are operated by major
exploration and development companies. Effective August 1, 2001, Search and Due
West were amalgamated and continued as "Search Energy Corp.". Effective January
1, 2002 Search acquired the Gascan Assets. On June 26, 2002 Search changed its
name to Advantage Oil & Gas Ltd. On November 18, 2002 AOG acquired all of the
issued and outstanding shares of Best Pacific. On December 2, 2003 AOG acquired
all of the issued and outstanding shares of Markwest Resources Canada Corp.
In accordance with the Management Agreement, the Manager has agreed to act as
manager of the Trust and AOG. The Manager is a Canadian-owned energy advisory
management corporation, incorporated on March 19, 2001, pursuant to the
provisions of the ABCA.
The head office of the Trust and the Manager and the head office and the
registered office of AOG is located at Suite 3100, 150 -6th Avenue S.W.,
Calgary, Alberta T2P 3H7. The registered office of the Manager is located at
Suite 3700, 400 - 3rd Avenue S.W., Calgary, Alberta, T2P 4H2.
Organizational Structure of the Trust
The following diagram sets forth the organizational structure of the Trust as at
the date hereof.
9
[GRAPHIC OMITTED]
Notes:
(1) The Unitholders own 100% of the Trust.
(2) Cash distributions are made to Unitholders monthly based upon the Trust's
cash flow.
(3) AOG has two wholly-owned subsidiaries, namely Best Pacific Resources
(U.S.) Inc. and Spirit Waste Management Inc., both of which corporations
do not own any material assets.
In accordance with the terms of the Trust Indenture and the Shareholder
Agreement, holders of Trust Units are entitled to direct the Trust as to how to
vote in respect of all matters to be placed before the Trust, including the
selection of directors of AOG, approving AOG's financial statements, and
appointing the auditors of AOG, who shall be the same as the auditors of the
Trust. The Shareholder Agreement provides that the Unitholders are entitled to
elect a majority of the Board of Directors and the Manager has the right to
designate two of such directors.
GENERAL DEVELOPMENT OF THE BUSINESS
History and Development
Search Energy Corp.
2001
During the fall of 2000 and in early 2001, management of Search reviewed
strategic alternatives and considered possible methods for enhancing value for
shareholders and ensuring the continued growth of Search. In February 2001,
after reviewing a variety of alternatives and proposals, management of Search
began to evaluate the benefits that might accrue to its shareholders if it
reorganized itself into an income trust. Management requested that the Board of
Directors give consideration to such reorganization. On February 23 and February
26, 2001, the Board of Directors met to consider various alternatives for
Search, including the reorganization of Search into an income trust. After due
deliberation and consideration of other alternatives available to Search, on
February 28, 2001 the Board of Directors retained a third party advisor to
assist Search in the evaluation of the reorganization proposal. The Board of
Directors met on three further occasions and, after extensive review of Search's
asset base and detailed production cash flow modeling, the Board of Directors
concluded that the best alternative available to Search for maximizing value for
shareholders would be to convert Search into an oil and gas income trust. See
"General Development of the Business - History and Development - Advantage
Energy Income Fund".
On April 1, 2001, the Board of Directors unanimously approved the Reorganization
Agreement and on April 12, 2001, the Board of Directors unanimously approved the
Arrangement Agreement.
10
Advantage Energy Income Fund
2001
The Arrangement Agreement provided for implementation of the Arrangement
pursuant to Section 193 of the ABCA. On May 24, 2001, each of the following
events occurred in the following sequence:
1. the shareholder rights plan of Search and all outstanding rights issued
pursuant thereto were terminated;
2. all of the right, title and interest of shareholders in the Common Shares
were transferred to AcquisitionCo in exchange for AcquisitionCo Units on
the basis of one AcquisitionCo Unit for every four Common Shares held,
resulting in the acquisition by AcquisitionCo of all of the issued and
outstanding Common Shares;
3. all of the right, title and interest of former shareholders in the
AcquisitionCo Units were transferred to the Trust in exchange for Trust
Units of the Trust on the basis of one Trust Unit for each AcquisitionCo
Unit, resulting in the acquisition by the Trust of all of the issued and
outstanding AcquisitionCo common shares and 14% Notes;
4. all right, title and interest of former Search optionholders who executed
an option cancellation agreement exchanged their options with
AcquisitionCo for AcquisitionCo Units which were, in turn, transferred to
the Trust in exchange for Trust Units on the basis of one Trust Unit for
each AcquisitionCo Unit. Any remaining options which were not subject to
an option cancellation agreement and which had not, as at May 24, 2001,
been exercised by the optionholder, were deemed to have been exchanged
with the Trust for options to purchase Trust Units which were, in turn,
exercised for Trust Units on May 25, 2001; and
5. Search and AcquisitionCo amalgamated and continued as one corporation,
and:
(a) all of the issued and outstanding Common Shares of Search, all of
which were then held by AcquisitionCo, were cancelled without any
repayment of capital; and
(b) the amalgamated corporation continued as "Search Energy Corp." and
adopted the articles of incorporation of AcquisitionCo.
The Trust Units commenced trading on the TSX on May 29, 2001 under the symbol
"AVN.UN".
On July 26, 2001 Advantage acquired all of the issued and outstanding shares of
Due West, a private light oil and natural gas company with working interests in
several well-established properties. The Trust acquired all the shares of Due
West at a price of $2.24 per share, for an aggregate cash consideration of
$59.68 million (the "Due West Acquisition"). Advantage funded the Due West
Acquisition using its existing credit facilities.
On October 4, 2001, Advantage issued 5,000,000 Trust Units to the public at a
price of $7.50 per Trust Unit for gross proceeds of $37,500,000. On October 11,
2001, Advantage issued an additional 750,000 Trust Units pursuant to the
exercise of the underwriters' over-allotment option at a price of $7.50 per
Trust Unit for additional gross proceeds of $5,625,000. The aggregate net
proceeds of $43,125,000 were used by Advantage to reduce its debt (a substantial
portion of which was incurred to fund the Due West Acquisition), to fund future
acquisitions and capital expenditures, and for general corporate purposes.
On November 28, 2001, Advantage and the Vendors entered into the Share Purchase
Agreement providing for the acquisition by the Trust of all of the issued and
outstanding securities of Newco, which company, as of the closing date of the
Asset Transfer, was the legal and beneficial owner of the Gascan Assets. The
effective date of the Gascan Acquisition was January 1, 2002 with closing
occurring on January 4, 2002. The net cash consideration payable by the Trust in
respect of the Gascan Acquisition was $69 million prior to adjustments.
On December 18, 2001, Advantage issued 6,014,500 Trust Units to the public at a
price of $7.65 per Trust Unit for gross proceeds of $46,010,925. The net
proceeds of the issue were used by Advantage to repay a portion of Advantage's
long term debt, some of which was incurred in connection with the acquisition of
the Gascan Assets owned by Newco.
11
2002
On January 29, 2002, Advantage issued 2,500,000 Trust Units to the public at a
price of $7.90 per Trust Unit for gross proceeds of $19,750,000. The net
proceeds of the issue were used by Advantage to complete the acquisition of
certain natural gas properties, to repay bank debt and to fund Advantage's 2002
capital expenditure program.
The first annual and special meeting of Unitholders was held on June 25, 2002.
At such meeting, Unitholders considered and approved various matters including
the name change from "Search Energy Corp." to "Advantage Oil & Gas Ltd.", the
addition of a class of non-voting common shares for AOG, certain amendments to
the Trust Indenture and the pre-authorization of private placements of Trust
Units during the ensuing 12-month period.
On September 10, 2002, Advantage completed an asset exchange transaction whereby
it acquired additional interests in producing natural gas properties at
Vermilion, Alberta in consideration for Advantage's interest in heavy oil
properties located in Wainwright, Alberta. The exchange was structured as a
property swap with Advantage neither receiving nor paying any cash in relation
to the transaction. Based upon the reserve engineering reports of Sproule dated
July 1, 2002 and January 1, 2002, the Fund acquired approximately 14.7 bcf (2.5
mmboe) of established natural gas reserves at Vermilion in exchange for 2.2
mmboe of established heavy oil reserves, of which 61% were classified as proved.
On September 30, 2002, Advantage announced that it had entered into an
acquisition agreement with Best Pacific providing for the purchase of all of the
issued and outstanding common shares of Best Pacific, including all shares
issued upon the exercise of outstanding options and warrants (the "Best Pacific
Shares"), on the basis of $1.25 cash consideration for each Best Pacific Share
(the "Offer"). The Offer was made by formal take-over bid circular which was
mailed on October 11, 2002. The Offer expired on November 18, 2002, with
Advantage acquiring 95% of the Best Pacific Shares on such date and completing
the compulsory acquisition of the remaining 5% of the Best Pacific Shares
effective November 21, 2002.
The acquisition of Best Pacific had a net purchase price, after adjustments and
fees, of approximately $53.4 million, which amount includes the assumption of
approximately $21.7 million of net debt.
The properties owned by Best Pacific consisted primarily of high working
interest natural gas and light oil properties located in southern Alberta and
southeastern Saskatchewan.
In conjunction with the acquisition of Best Pacific, Advantage announced on
September 30, 2002 that it had signed an agreement providing for the offering on
a bought deal basis of $55,000,000 aggregate principal amount of Debentures. The
Debentures have a coupon of 10%, mature on November 1, 2007 and are convertible
into Trust Units at a price of $13.30 per Trust Unit. Interest is payable on the
Debentures semi-annually, with the first interest payment to occur on May 1,
2003. The offering of Debentures closed on October 18, 2002, with the net
proceeds of the offering used to fund the acquisition of Best Pacific, to reduce
bank indebtedness and for general corporate purposes.
2003
On January 24, 2003, Advantage announced the appointment of Peter Hanrahan to
the position of Chief Financial Officer in addition to his prior position as
Controller.
At an annual and special meeting of Unitholders held on May 28, 2003,
Unitholders considered and approved various matters including amendments to the
Trust Indenture, the issuance of up to 1,500,000 Trust Units to the Manager in
payment of its performance fee under the Management Agreement and the
pre-authorization of private placements of Trust Units during the ensuing 12
month period.
On July 8, 2003, Advantage completed the issue, by way of short form prospectus,
of $30,000,000 principal amount of 9% convertible unsecured subordinated
debentures through a syndicate of underwriters. The convertible debentures had a
face value of $1,000 each with a coupon of 9%, maturing on August 1, 2008 and
are convertible into Trust Units at $17.00 per Trust Unit. The net proceeds of
the offering were used to fund an expanded capital expenditure program and to
repay debt.
On December 8, 2003, Advantage completed a second issue, by way of short form
prospectus, of 5,100,000 Trust Units at $15.75 per Trust Unit for gross proceeds
of $80,325,000 and $60,000,000 aggregate principal amount of 8 1/4% convertible
unsecured
12
subordinated debentures through a syndicate of underwriters. The convertible
debentures had a face value of $1,000 each with a coupon of 8 1/4%, maturing on
February 1, 2009 and are convertible into Trust Units at $16.50 per Trust Unit.
The net proceeds of the offering were used to fund the acquisition of MarkWest,
to reduce amounts outstanding under Advantage's credit facility and to fund
drilling and exploitation capital expenditures.
In conjunction with the completion of the December financing, Advantage also
announced the completion of the MarkWest acquisition. The acquisition was made
for total cash consideration of $96,800,000 prior to adjustments.
DESCRIPTION OF THE BUSINESS AND OPERATIONS
Advantage Energy Income Fund
The Trust is a limited purpose trust and is restricted to:
1. investing in the Initial Permitted Securities, the Permitted Investments,
Subsequent Investments and such other securities and investments as AOG
may determine, provided that under no circumstances shall the Trustee, AOG
or the Manager purchase or authorize the purchase of any security, asset
or investment (collectively a "Prohibited Investment") on behalf of the
Trust or using any Trust assets or property which is defined as "foreign
property" under subsection 206(1) of the Tax Act or is a "small business
security" as that expression is used in Part LI of the Regulations to the
Tax Act or would result in the Trust not being considered either a "unit
trust" or a "mutual fund trust" for purposes of the Tax Act at the time
such investment was made;
2. disposing of any part of the Trust Fund, including, without limitation,
any Permitted Investments;
3. acquiring the Royalty and other royalties in respect of Resource
Properties;
4. temporarily holding cash, and Permitted Investments (including investments
in AOG) for the purposes of paying Trust expenses and Trust liabilities,
paying amounts payable by the Trust in connection with the redemption of
any Trust Units, and making distributions to Unitholders;
5. acquiring or investing in securities of AOG or any other Subsidiary of the
Trust to fund the acquisition, development, exploitation and disposition
of all types of petroleum and natural gas related assets, including,
without limitation, facilities of any kind and whether effected through
the acquisition of assets or the acquisition of shares or other form of
ownership interest in any entity, the substantial majority of the assets
of which are comprised of like assets;
6. undertaking such other business and activities including investing in
securities as shall be approved by AOG from time to time provided that the
Trust shall not undertake any business or activity which is a Prohibited
Investment (as defined in the Trust Indenture);
and to pay the costs, fees and expenses associated therewith or incidental
thereto.
In accordance with the terms of the Trust Indenture, the Trust will make cash
distributions to Trust Unitholders of the interest income earned from the 14%
Notes, royalty income earned on the Royalty, dividends (if any) received on, and
amounts, if any, received on redemption of, Common Shares and Preferred Shares,
and income and distributions received from any Permitted Investments after
expenses and capital expenditures, any cash redemptions of Trust Units, and
other expenditures. See "Additional Information Respecting Advantage Energy
Income Fund - Cash Distributions".
Advantage Oil & Gas Ltd.
AOG is actively engaged in the business of oil and gas exploration, development,
acquisition and production in the provinces of Alberta, British Columbia and
Saskatchewan.
The Trust employs a strategy to maintain production from AOG's existing
production base while focusing capital expenditures on low-risk development
opportunities. AOG utilizes financial hedges, when deemed appropriate, to manage
and reduce the volatility in commodity prices. See "Risk Factors". AOG generally
sells or farms out higher risk projects while actively pursuing
13
growth opportunities through oil and gas property acquisitions, as well as
through corporate acquisitions. AOG targets acquisitions that are accretive to
net asset value and that increase the Trust's reserve and production base per
Trust Unit outstanding. Acquisitions must also meet reserve life index criteria
and exhibit low risk opportunities to increase reserves and production. It is
currently intended that AOG will finance acquisitions and investments through
bank financing and the issuance of additional Trust Units from treasury,
maintaining prudent leverage.
Significant Acquisitions
Effective October 1, 2003, Advantage acquired all of the shares of MarkWest, a
wholly-owned subsidiary of MarkWest Hydrocarbon, Inc., for total cash
consideration of $96,800,000 prior to adjustments. The MarkWest Properties
consist primarily of natural gas assets located in southeast Alberta and central
Alberta which at the date of acquisition was producing approximately 4,448 boe/d
(approximately 91% of which is natural gas). Approximately 98% of the production
from the MarkWest Properties is operated by MarkWest with MarkWest having
approximately a 78% average working interest in such production. Audited
financial statements as at and for the year ended December 31, 2002 and
unaudited financial statements as at and for the six months ended June 30, 2003
are attached hereto as Schedule "A".
Effective January 1, 2002, Advantage acquired the Gascan Assets. Selected
pro-forma combined operational information, financial information, as well as
production and drilling histories for the Gascan Assets on an historical basis
are set forth in the Trust's Renewal Annual Information Form dated May 16, 2002.
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 December 31, 2003. The effective date of the
Statement is December 31, 2003 and the preparation date of the Statement is
April 19, 2004.
Disclosure of Reserves Data
The reserves data set forth below (the "Reserves Data") is based upon an
evaluation by Sproule Associates Limited ("Sproule") with an effective date of
December 31, 2003 contained in a report of Sproule dated April 19, 2004 (the
"Sproule Report"). The Reserves Data summarizes the oil, liquids and natural gas
reserves of the Corporation 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. Advantage Energy Income Fund engaged Sproule to provide an
evaluation of proved and proved plus probable reserves and no attempt was made
to evaluate possible reserves.
All of the Trust's reserves are in Canada and, specifically, in the provinces of
Alberta, British Columbia and Saskatchewan.
It should not be assumed that the estimates of future net revenues presented in
the tables below represent the fair market value of the reserves. There is no
assurance that the constant prices and costs assumptions and forecast prices and
costs assumptions will be attained and variances could be material. The recovery
and reserve estimates of the Trust's 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 and
natural gas liquid reserves may be greater than or less than the estimates
provided herein.
14
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 Medium Oil Heavy Oil Natural Gas Natural Gas Liquids
--------------------- --------------------- --------------------- ---------------------
Gross Net Gross Net Gross Net Gross Net
RESERVES CATEGORY (mbbl) (mbbl) (mbbl) (mbbl) (mmcf) (mmcf) (mbbl) (mbbl)
- -------------------------- -------- -------- -------- -------- -------- -------- -------- --------
PROVED
Developed Producing 5,762.2 5,239.6 18.1 15.3 156,904 135,432 1,588.5 1,198.2
Developed Non-Producing 67.6 53.0 0.0 0.0 7,766 6,510 67.1 50.3
Undeveloped 734.3 618.5 0.0 0.0 21,161 17,084 197.3 141.0
-------- -------- -------- -------- -------- -------- -------- --------
TOTAL PROVED 6,564.1 5,911.1 18.1 15.3 185,830 159,026 1,853.0 1,389.5
PROBABLE 4,685.6 4,081.2 2.0 1.6 53,512 44,403 800.1 595.8
-------- -------- -------- -------- -------- -------- -------- --------
TOTAL PROVED PLUS PROBABLE 11,249.7 9,992.3 20.1 17.0 239,343 203,429 2,653.1 1,985.3
======== ======== ======== ======== ======== ======== ======== ========
Net Present Values Of Future Net Revenue
-----------------------------------------------------------------------------------------------------
Before Income Taxes Discounted at ($000's) After Income Taxes Discounted at ($000's)
------------------------------------------------- -------------------------------------------------
RESERVES CATEGORY 0% 5% 10% 15% 20% 0% 5% 10% 15% 20%
- -------------------------- --------- ------- ------- ------- ------- --------- ------- ------- ------- -------
PROVED
Developed Producing 741,476 544,378 441,520 377,541 333,278 741,476 544,378 441,520 377,541 333,278
Developed Non-Producing 36,615 31,451 26,569 22,829 20,004 36,615 31,451 26,569 22,829 20,004
Undeveloped 69,527 62,699 52,136 42,782 35,217 69,527 62,699 52,136 42,782 35,217
--------- ------- ------- ------- ------- --------- ------- ------- ------- -------
TOTAL PROVED 847,617 638,527 520,226 443,152 388,500 847,617 638,527 520,226 443,152 388,500
PROBABLE 302,928 178,492 125,592 96,293 77,518 302,928 178,492 125,592 96,293 77,518
--------- ------- ------- ------- ------- --------- ------- ------- ------- -------
TOTAL PROVED PLUS PROBABLE 1,150,545 817,018 645,818 539,446 466,018 1,150,545 817,018 645,818 539,446 466,018
========= ======= ======= ======= ======= ========= ======= ======= ======= =======
TOTAL FUTURE NET REVENUE
(UNDISCOUNTED) as of
December 31, 2003
CONSTANT PRICES AND COSTS
($000's)
Future Net
Future Net Revenue
Well Revenue After
Reserves Operating Development Abandonment Before Income Income
Category Revenue Royalties Costs Costs Costs Income Taxes Taxes Taxes
- ----------- --------- --------- --------- ----------- ---------- ------------ --------- ----------
PROVED 1,396,530 196,829 288,297 42,993 20,794 847,617 0 847,617
PROVED PLUS 1,911,541 281,772 401,264 56,425 21,537 1,150,545 0 1,150,545
PROBABLE
15
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 ($000's)
- -------------------- ------------------------------------------------------------- ------------------------------
PROVED Light and Medium Crude Oil (including solution gas and other
by-products) 87,023
Heavy Oil (including solution gas and other by-products) 123
Natural Gas (including by-products but excluding solution gas
from oil wells) 428,619
PROVED PLUS PROBABLE Light and Medium Crude Oil (including solution gas and other
by-products) 139,100
Heavy Oil (including solution gas and other by-products) 139
Natural Gas (including by-products but excluding solution gas
from oil wells) 501,688
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 Medium Oil Heavy Oil Natural Gas Natural Gas Liquids
--------------------- --------------------- --------------------- ---------------------
Gross Net Gross Net Gross Net Gross Net
RESERVES CATEGORY (mbbl) (mbbl) (mbbl) (mbbl) (mmcf) (mmcf) (mbbl) (mbbl)
- -------------------------- -------- -------- -------- -------- -------- -------- -------- --------
PROVED
Developed Producing 5,613.6 5,115.6 5.1 4.3 155,000 133,801 1,575.5 1,188.1
Developed Non-Producing 67.6 53.3 -- -- 8,237 6,953 67.1 50.3
Undeveloped 734.2 621.5 -- -- 21,187 17,106 198.3 141.8
-------- -------- -------- -------- -------- -------- -------- --------
TOTAL PROVED 6415.4 5,790.3 5.1 4.3 184,423 157,860 1,840.8 1,380.2
PROBABLE 4,637.8 4,057.5 0.6 0.5 53,018 43,981 797.7 593.1
-------- -------- -------- -------- -------- -------- -------- --------
TOTAL PROVED PLUS PROBABLE 11,053.2 9,847.8 5.7 4.8 237,441 201,840 2,638.5 1,973.3
======== ======== ======== ======== ======== ======== ======== ========
Net Present Values Of Future Net Revenue
-----------------------------------------------------------------------------------------------------
Before Income Taxes Discounted at ($000's) After Income Taxes Discounted at ($000's)
------------------------------------------------- -------------------------------------------------
RESERVES CATEGORY 0% 5% 10% 15% 20% 0% 5% 10% 15% 20%
- -------------------------- --------- ------- ------- ------- ------- --------- ------- ------- ------- -------
PROVED
Developed Producing 611,535 449,966 366,835 315,828 280,866 611,535 449,966 366,835 315,828 280,866
Developed Non-Producing 30,982 26,048 22,038 19,029 16,769 30,982 26,048 22,038 19,029 16,769
Undeveloped 43,529 40,233 33,333 26,784 21,346 43,529 40,233 33,333 26,784 21,346
--------- ------- ------- ------- ------- --------- ------- ------- ------- -------
TOTAL PROVED 686,045 516,247 422,206 361,641 318,980 686,045 516,247 422,206 361,641 318,980
PROBABLE 260,192 143,230 97,844 73,969 59,088 260,192 143,230 97,844 73,969 59,088
--------- ------- ------- ------- ------- --------- ------- ------- ------- -------
TOTAL PROVED PLUS PROBABLE 946,237 659,477 520,050 435,610 378,068 946,237 659,477 520,050 435,610 378,068
========= ======= ======= ======= ======= ========= ======= ======= ======= =======
16
TOTAL FUTURE NET REVENUE
(UNDISCOUNTED) as of
December 31, 2003
FORECAST PRICES AND COSTS
($000's)
Future Net
Future Net Revenue
Well Revenue After
Reserves Operating Development Abandonment Before Income Income
Category Revenue Royalties Costs Costs Costs Income Taxes Taxes Taxes
- ----------- --------- --------- --------- ----------- ---------- ------------ --------- ----------
PROVED 1,251,950 172,303 324,096 43,153 26,353 688,045 0 688,045
PROVED PLUS 1,745,915 247,767 466,072 56,745 29,093 946,238 0 946,238
PROBABLE
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 ($000's)
- -------------------- ------------------------------------------------------------- ------------------------------
PROVED Light and Medium Crude Oil (including solution gas and other
by-products) 65,031
Heavy Oil (including solution gas and other by-products) (40)
Natural Gas (including by-products but excluding solution gas
from oil wells) 352,717
PROVED PLUS PROBABLE Light and Medium Crude Oil (including solution gas and other
by-products) 102,678
Heavy Oil (including solution gas and other by-products) (39)
Natural Gas (including by-products but excluding solution gas
from oil wells) 412,484
Pricing Assumptions
The following tables set forth the benchmark reference prices, as at December
31, 2003, reflected in the Reserves Data. These price assumptions were provided
to the Trust by Sproule, the Trust's independent qualified reserves evaluator.
17
SUMMARY OF PRICING ASSUMPTIONS
as of December 31, 2003
CONSTANT PRICES AND COSTS
Natural Gas
Edmonton Liquids
Par Price Natural Gas(1) Fob(1) Exchange
40(degrees) Api Aeco Gas Price Field Gate Rate(2)
Year ($Cdn/bbl) ($Cdn/mmbtu) ($Cdn/bbl) ($US/$Cdn)
- ------------- --------------- -------------- ----------- ----------
2003 Year End $37.61 $ 5.87 $33.83 0.75
Notes:
(1) The exchange rate used to generate the benchmark reference prices in this
table.
SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS
as of December 31, 2003
FORECAST PRICES AND COSTS
Oil Pentanes
Wti Edmonton Cromer Plus
Cushing Par Price Medium Natural Gas Fob
Oklahoma 40(degrees) Api 29.3(degrees) Api Aeco Gas Price Field Gate
Year ($US/bbl) ($Cdn/bbl) ($Cdn/bbl) ($Cdn/Mmbtu) ($Cdn/bbl)
- ---------- --------- --------------- ----------------- -------------- ----------
Forecast
2004 29.63 37.99 32.99 6.04 38.91
2005 26.80 34.24 29.44 5.36 35.07
2006 25.76 32.87 28.47 4.80 33.67
2007 26.14 33.37 29.07 4.91 34.17
2008 26.53 33.87 29.54 4.98 34.69
Thereafter VARIOUS ESCALATION RATES
Butanes Propanes
Fob Fob Inflation Exchange
Field Gate Field Gate Rates(1) Rate(2)
Year ($Cdn/bbl) ($Cdn/bbl) %/Year ($US/$Cdn)
- ---------- ---------- ---------- -------- ----------
Forecast
2004 31.15 28.04 1.5 0.75
2005 25.52 22.56 1.5 0.75
2006 23.28 20.58 1.5 0.75
2007 23.63 20.89 1.5 0.75
2008 23.98 21.20 1.5 0.75
Thereafter
Notes:
(1) Inflation rates for forecasting prices and costs.
(2) Exchange rates used to generate the benchmark reference prices in this
table.
Weighted average historical prices realized by the Trust for the year ended
December 31, 2003, were $6.07/mcf for natural gas, $39.32/bbl for crude oil,
$32.54/bbl for natural gas liquids.
Reconciliations of Changes in Reserves and Future Net Revenue
The following table sets forth the reconciliation in the Trust's net reserves
for the year ended December 31, 2003 using forecast price and cost estimates
derived from the Sproule Report, reconciled to the Trust's net reserves at
December 31, 2002. See the note following the table for a discussion of the
basis upon which net reserves were calculated at December 31, 2002.
18
RECONCILIATION OF
TRUST NET RESERVES
BY PRINCIPAL PRODUCT TYPE
FORECAST PRICES AND COSTS
Light And Medium Oil Heavy Oil
------------------------------------ ------------------------------------
Net Net
Proved Proved
Net Net Plus Net Net Plus
Proved Probable Probable Proved Probable Probable
FACTORS (mbbl) (mbbl) (mbbl) (mbbl) (mbbl) (mbbl)
- ------------------- -------- -------- -------- -------- -------- --------
December 31 2002(1) 8,249 2,298 10,547 44 4 48
Extensions 280 511 791 0 0 0
Improved 0 0 0 0 0 0
Recovery
Technical (1,986) 1,297 (689) (27) (3) (30)
Revisions
Discoveries 0 0 0 0 0 0
Acquisitions 395 62 457 0 0 0
Dispositions (453) (110) (563) 0 0 0
Economic 0 0 0 0 0 0
Factors
Production(2) (695) 0 (695) (13) 0 (13)
-------- -------- -------- -------- -------- --------
December 31, 2003 5,790 4,058 9,848 4 1 5
======== ======== ======== ======== ======== ========
Associated And Non-Associated Gas Natural Gas Liquids
------------------------------------ ------------------------------------
Net Net
Proved Proved
Net Net Plus Net Net Plus
Proved Probable Probable Proved Probable Probable
FACTORS (mbbl) (mbbl) (mbbl) (mmcf) (mmcf) (mmcf)
- ------------------- -------- -------- -------- -------- -------- --------
December 31 2002(1) 152,933 37,808 190,741 1,130 542 1,672
Extensions 6,006 2,871 8,877 7 2 9
Improved 4,758 1,808 6,566 75 24 99
Recovery
Technical (15,385) (4,817) (20,202) 96 (25) 71
Revisions
Discoveries 4,908 977 5,885 0 0 0
Acquisitions 24,384 5,420 29,804 251 50 301
Dispositions (653) (86) (739) (19) 0 (19)
Economic 0 0 0 0 0 0
Factors
Production(2) (19,091) 0 (19,091) (160) 0 (160)
-------- -------- -------- -------- -------- --------
December 31, 2003 157,860 43,981 201,840 1,380 593 1,973
======== ======== ======== ======== ======== ========
Note:
(1) The evaluation as at December 31, 2002 was prepared using National Policy
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 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.
(2) Includes Markwest production from Oct 1 - Dec 31, 2003.
19
The following table sets forth the reconciliation of the Trust's net present
values of future net revenue for the year ended December 31, 2003 using constant
price and cost estimates derived from the Sproule Report.
RECONCILIATION OF CHANGES IN
NET PRESENT VALUES OF FUTURE NET REVENUE
DISCOUNTED AT 10% PER YEAR
PROVED RESERVES
CONSTANT PRICES AND COSTS
($000's)
Period And Factor 2003
- --------------------------------------------------------------------------------------- ------
Estimated Future Net Revenue at Beginning of Year 522.5
Sales and Transfers of Oil and Gas Produced, Net of Production Costs and Royalties (112.0)
Net Change in Prices, Production Costs and Royalties Related to Future Production 5.3
Actual Development Costs Incurred During the Period 68.2
Changes in Estimated Future Development Costs (73.1)
Extensions and Improved Recovery 36.3
Discoveries 17.4
Acquisitions of Reserves 95.2
Dispositions of Reserves (9.8)
Net Change Resulting from Revisions in Quantity Estimates (82.1)
Accretion of Discount 52.3
Net Change in Income Taxes --
------
Estimated Future Net Revenue at End of Year 520.2
======
Additional Information Relating to Reserves Data
Undeveloped Reserves
Proved and probable undeveloped reserves have been assigned in accordance with
engineering and geological practices as defined under NI 51-101. In general,
undeveloped reserves are planned to be developed over the next two years with
close to 75 percent being completed in 2004.
20
Future Development Costs
The following table sets forth development costs deducted in the estimation of
the Trust's future net revenue attributable to the reserve categories noted
below.
Forecast Prices And Costs Constant Prices And Costs
------------------------------------------- -------------------------------------------
Year Proved Plus Probable Proved Plus Probable
Proved Reserves Reserves Proved Reserves Reserves
------------------ -------------------- ------------------ --------------------
0% 10% 0% 10% 0% 10% 0% 10%
------ ------ ------ ------ ------ ------ ------ ------
2004 34,165 32,312 39,782 37,750 34,165 32,312 39,782 37,750
2005 8,585 7,381 14,417 12,390 8,459 7,273 14,204 12,207
2006 41 32 2,050 1,602 40 31 1,990 1,555
2007 32 23 43 31 31 22 41 29
2008 0 0 0 0 0 0 0 0
Thereafter 330 174 453 220 298 158 408 197
------ ------ ------ ------ ------ ------ ------ ------
Total 43,153 39,922 56,745 51,992 42,993 39,796 56,425 51,738
====== ====== ====== ====== ====== ====== ====== ======
Other Oil and Gas Information
Oil and Gas Properties
The following is a description of Advantage's principal oil and natural gas
properties on production or under development as at January 1, 2004. The term
"net", when used to describe Advantage's share of production, means the total of
Advantage's working interest share before deduction of royalties owned by
others. Reserve amounts are stated, before deduction of royalties, at December
31, 2004, based upon escalating cost and price assumptions (gross) as evaluated
in the Sproule Report (see "Description of the Business and Operations Oil and
Natural Gas Reserves"). Unless otherwise specified, gross and net acres and well
count information are as at January 1, 2004. Information in respect of current
production is 2003 exit production, net to Advantage, except where otherwise
indicated.
Medicine Hat, Alberta
The Medicine Hat area is located in southeastern Alberta where Advantage has a
100% working interest in 24 sections of land. Production in the area comes from
all of the main shallow gas formations including the Medicine Hat "A", "C" and
"D" sands, both the Upper and Lower Milk River, as well as the Second White
Specks sands. When the property was acquired in January 2002 there were 115
wells producing 5.2 mmcf/d of natural gas. In 2002 and 2003, several
recompletions along with an additional 164 wells were drilled on this property.
Late in 2003 and continuing into early 2004, an additional 57 wells were drilled
and will be completed during 2004. Exiting 2003, this property was producing
18.6 mmcf/d from approximately 300 wells. Another 43 wells are planned for
drilling and are expected to be on-stream during the second half of 2004.
Compression capacity was also increased in late 2003 by approximately 10 mmcf/d
to accommodate added production from the 2004 drilling programs.
Sproule evaluated Advantage's reserves in the area and assigned 73.8 bcf of
proved natural gas reserves and 8.3 bcf of probable reserves. As such, this
property is Advantage's largest property on an assigned reserves basis.
Wainwright and Kinsella, Alberta
These properties cover varying working interests averaging more than 80% in
approximately 175 sections of land, located in east central Alberta,
approximately 40 kilometers northwest of Wainwright, Alberta. Current combined
production from these areas is 5.6 mmcf/d. In 2002, Advantage swapped out
virtually all of its heavy oil assets which were concentrated in this area for
producing natural gas assets in Advantage's other core area of Vermilion,
immediately to the north of this property.
Natural gas production occurs from the Manville Group and Viking Formations. All
production occurs from shallow depths of between 450 and 700 meters. The Fund
operates 95% of its natural gas production in this area and owns a majority
interest in and operates an extensive gas gathering system tying into three
Advantage-operated gas compression facilities
21
Advantage has downspaced almost a township of land to allow for the drilling of
two Viking wells per section. In 2003, Advantage drilled 23.3 net wells which
encountered a combination of Viking and Upper Mannville zones. The Viking zone
represents long life reserves with moderate producing rates. Advantage has
approximately 2 1/2 townships of land covered with three-dimensional ("3D")
seismic to aid in the selection of these drilling locations.
Sproule evaluated Advantage's proved reserves in the Wainwright and Kinsella
areas and assigned 7.7 bcf of natural gas and 4.0 mbbls of oil. Probable
reserves for Advantage in this area were evaluated by Sproule at 6.1 bcf of
natural gas and 0.6 mbbls of oil.
Stoddart/North Pine, British Columbia
The Stoddart/North Pine area lies immediately northwest of the town of Fort St.
John in northeast British Columbia. The area contains multiple producing
horizons, predominantly natural gas from the Permian, Belloy formation and oil
from the Triassic, Charlie Lake formation. Production from this area has very
low decline rates, is low cost and required minimal capital expenditures.
Advantage owns an interest in 30 producing wells (22 net) in the area. Advantage
operates approximately 80% of the natural gas production and has a 40% working
interest in the oil production. The area includes 12,000 gross (9,176 net) acres
of undeveloped land. Current production from this area is 4.1 mmcf/d of natural
gas and 233 bbls/d of light oil and NGLs.
Sproule evaluated Advantage's proved reserves in the area and assigned 11.5 bcf
of natural gas and 477.9 mbbls of crude oil and NGLs. In addition, 3.1 bcf of
probable natural gas reserves and 164.7 mbbls of probable crude oil and NGLs
reserves have been assigned to this property.
Shouldice, Alberta
The Shouldice area of southern Alberta is located approximately 45 kilometers
southeast of the city of Calgary. Advantage has an average working interest of
more than 85% in 34 sections of land and operates in excess of 90% of its
production. Much of this acreage is downspaced to accommodate additional stepout
and infill drilling. Natural gas production of approximately 7.0 mmcf/d is
produced on a co-mingled basis from the Medicine Hat sand with various Belly
River Formation sands.
In addition to natural gas, Advantage also produced 57 bbls/d of medium gravity
(33(degree) API) crude oil. This production is from the deeper, Mannville
formation, Basal Quartz sands.
During 2003, 20 net wells were added to the existing 70 producers. Both natural
gas and crude oil are produced and gathered through company owned facilities of
varying working interests. An additional 38 new locations are licenced for
drilling which will commence in the second quarter of 2004. Theses will target
the Medicine Hat and Belly River Formations with 5 targeting the deeper Bow
Island Formation. Advantage is adding an additional 4 mmcf/d of new compression
capacity to handle the expected production increase.
The Sproule Report assigns 14.4 bcf of proven natural gas reserves and 100.2
mbbls of proven crude oil and NGLs to this property. In addition, 3.2 bcf of
probable natural gas reserves and 16.0 mbbls of probable crude oil and NGLs
reserves have been assigned to this property.
Bantry, Alberta
Bantry is located immediately east of the town of Brooks and consists of 86
sections of land ranging between 50 and 100% working interest, with over half at
100%. This property was acquired in December 2003 with the acquisition of
MarkWest Resources. Since the acquisition, 25 new wells were drilled of which 18
earned additional acreage through a farm-in arrangement with a major integrated
oil company. Eleven additional sections will be earned through this farm-in
arrangement in the first half of 2004. Production occurs primarily from various
sandstones within the Bow Island Formation as well as from Basal Colorado
Formation channel sandstones. Drilling is shallow with average well depths less
than 1,000 meters.
Natural gas is gathered into Advantage operated compression and dehydration
facilities and current net production from this area is approximately 14.7
mmcf/d. Advantage has added 15 mmcf/d gross of additional compression capacity
in the first quarter of 2004 to handle additional volumes from the new drilling.
Completion and tie-in of the new drills has been delayed due to spring break-up
but production is anticipated to be on-stream by the end of the second quarter
2004.
22
The Sproule Report assigns 19.5 bcf of proven natural gas reserves and 35 mbbls
of proven NGL reserves to this property. In addition, 6.0 bcf of probable
natural gas reserves and 10.7 mbbls of probable NGL reserves have been assigned
to this property.
Nevis, Alberta
The Nevis property was acquired in December 2003 with the acquisition of
Markwest Resources. Situated 50 km east of Red Deer, Nevis consists of
approximately 32 sections of land with an average working interest over 75%.
Natural gas production occurs from numerous shallow depth horizons including the
Edmonton, Belly River and Viking formations. Oil and natural gas is produced
from several slightly deeper reservoirs in the Glauconite, Ostacod and Ellerslie
formations of the Mannville Group. Recent drilling in the Wabamun formation is
developing oil and natural gas production from 2 to 4 meter thick carbonate
reservoirs at the top of the formation, which occurs at moderate depths of 1,600
meters.
Current net production to Advantage is 3.6 mmcf/d of natural gas and 302 bbls/d
of crude oil and NGLs. Advantage operates 90% of its Nevis properties. Natural
gas is gathered through company owned pipelines and processed at a third party
plant. Oil is trucked from single well batteries.
The Sproule Report assigns 9.5 bcf of proven natural gas reserves and 917.3
mbbls of proven crude oil and NGLs reserves to this property. In addition, 4.5
bcf of probable natural gas reserves and 952.5 mbbls of risked probable crude
oil and NGLs reserves have been assigned to this property.
Oil And Gas Wells
The following table sets forth the number and status of wells in which the Trust
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 263.0 164.0 130.0 75.5 875.0 700.1 153.0 91.2
British Columbia 11.0 6.5 5.0 2.3 64.0 37.3 15.0 6.2
Saskatchewan 80.0 49.8 41.0 26.1 -- -- -- --
Manitoba 85.0 5.1 -- -- -- -- -- --
----- ----- ----- ----- ----- ----- ----- -----
Total 439.0 225.4 176.0 103.9 939.0 737.4 168.0 97.4
===== ===== ===== ===== ===== ===== ===== =====
Note:
(1) Excluding minor interest in the following units (less than 5% working
interest): Steelman Unit No. 3, Pine Creek Second White Specks Pool,
Carrot Creek Cardium K Unit No. 1, Delburne Gas Unit, Nevis Unit No. 1,
Bonnie Glen D-3A Gas Cap Unit, Bellis Gas Unit No. 2, Turner Valley Unit
No. 5, Sunchild Gas Unit No. 1, North Pembina Cardium Unit, Kakwa Cardium
A Unit, Bonanza Boundary A Pool Unit No. 1. and Boundary Lake Units No. 1
and No. 2. Injection Wells are categorized as Non-Producing Oil Wells.
Properties with no Attributed Reserves
The following table sets out the Trust's developed and undeveloped land holdings
as at December 31, 2003.
Developed Acres Undeveloped Acres Total Acres
----------------------- ----------------------- -----------------------
Gross Net Gross Net Gross Net
--------- --------- --------- --------- --------- ---------
Alberta 593,984 276,523 388,132 210,682 982,116 487,205
British Columbia 93,187 18,885 21,409 7,003 114,596 25,888
Saskatchewan 8,929 5,088 90,438 86,817 99,367 91,905
--------- --------- --------- --------- --------- ---------
Total 696,100 300,496 499,979 304,502 1,196,079 604,998
========= ========= ========= ========= ========= =========
The Trust expects that rights to explore, develop and exploit 37,969 net acres
of its undeveloped land holdings will expire by December 31, 2004.
23
Forward Contracts
In March and April of 2003 Advantage entered into costless collar contracts on
approximately 60% of its natural gas production (net of royalties). Advantage
does not currently have any oil hedges in place. The specific volumes and terms
of such commitments are set forth below:
Type of Commitment Average Fixed Price Volume Term of Commitment
- ------------------------------- ------------------- ------------- --------------------------
Collar - Natural Gas - AECO 'c' $6.12/mcf 50.4 mmcf/day Apr 1, 2004 - Dec 31, 2004
Collar - Natural Gas - AECO 'c' $6.30/mcf 10.5 mmcf/day Jan 1, 2005 - Mar 31, 2005
Additional Information Concerning Abandonment and Reclamation Costs
Advantage estimates the costs to abandon and reclaim all its shut in and
producing wells, facilities, gas plants, pipelines, batteries and satellites. No
estimate of salvage value is netted against the estimated cost. Advantage's
model for estimating the amount and timing of future abandonment and reclamation
expenditures was done on an operating area level. Estimated expenditures for
each operating area are based upon Sproule's methodology, which details the cost
of abandonment and reclamation for the major properties that Advantage holds.
Each property was assigned an average cost per well to abandon and reclaim the
wells in an area and abandonment and reclamation costs have been estimated over
a 50 year period.
Advantage estimates that they will incur reclamation and abandonment costs on
1,157.6 net producing and non-producing wells. Costs to abandon and reclaim
these wells totals $38.9 million ($10.8 million discounted at 10%) and are
included in the estimate of future net revenue. The additional liability
associated with pipelines and facilities reclamation costs was estimated to be
$60 million ($0.5 million discounted at 10%), and was not deducted in estimating
future net revenue. Facility reclamation costs are scheduled to be incurred in
the year following the end of the reserve life of its associated reserves under
the assumption that decommissioning of plant/facilities are mobile assets with a
long useful life.
Abandonment and reclamation costs included in the estimate of future net revenue
for the next three years are $0.7 million in 2004, $1.3 million in 2005 and $0.9
million in 2006.
Capital Expenditures
The following tables summarize capital expenditures (including capitalized
general and administrative expenses) related to the Trust's activities for the
year ended December 31, 2003:
Capital Expenditures ($ thousands) 2003
- --------------------------------------------------------------------------------
Land and seismic $ 7,502
Drilling, completions and workovers 47,123
Well equipping and facilities 21,094
Other 493
- --------------------------------------------------------------------------------
$ 76,212
Acquisition of Best Pacific Resources Ltd. --
Acquisition of Gascan Resources Ltd. --
Acquisition of MarkWest Canada Resources Corp. 97,025
Property acquisitions 1,848
Property dispositions (6,112)
- --------------------------------------------------------------------------------
Total capital expenditures $ 168,973
- --------------------------------------------------------------------------------
24
Exploration and Development Activities
The following table sets forth the gross and net wells in which the Trust
participated during the year ended December 31, 2003:
Gross Net
----- -----
Medicine Hat 97 97
Viking-Kinsella 26 23.3
Shouldice 20 19.1
Bantry 17 9.9
Vermillion 14 13.5
Other 18 11.0
--- -----
Total 192 173.8
=== =====
In 2004, Advantage plans to drill and tie-in 100 net wells in Medicine Hat, 31
net wells in Bantry, 38 net wells in Shouldice, three horizontal wells at Nevis,
Alberta, one at Benson, Saskatchewan and approximately 3.5 net wells on
non-operated properties.
Production Estimates
The following table sets out the volume of the Trust's production estimated for
the year ended December 31, 2004 reflected in the estimate of future net revenue
disclosed in the tables contained under "Disclosure of Reserves Data".
Light and Medium
Oil Heavy Oil Natural Gas Natural Gas Liquids BOE
(bbls/d) (bbls/d) (mcf/d) (bbls/d) (boe/d)
---------------- --------- ----------- ------------------- -------
2004 2,474 0 84,056 791 17,274
---------------- --------- ----------- ------------------- -------
Production History
The following tables summarize certain information in respect of production,
prices received, royalties paid, operating expenses and resulting netback for
the periods indicated below:
Three Months Three Months Three Months Ended Three Months Ended
Ended March 31, Ended June 30, September 30, December 31,
------------------ ------------------ ------------------ ------------------
2003 2002 2003 2002 2003 2002 2003 2002
------ ------ ------ ------ ------ ------ ------ ------
Average Daily Production(1)
Crude oil and NGLs (bbls/d) 2,946 2,991 2,746 3,081 2,623 2,628 2,714 2,618
Natural gas (mcf/d) 54,497 40,902 51,929 42,196 58,686 48,259 65,280 59,444
Combined (boe/d) 12,029 9,808 11,401 10,114 12,404 10,672 13,594 12,524
Average Net Prices Received(2)
Crude oil and NGLs (bbls/d) 44.34 27.83 36.03 31.54 36.04 33.43 35.67 36.05
Natural gas (mcf/d) 6.18 3.02 6.49 3.55 5.96 3.01 5.76 4.87
Royalties(3)(5)
Crude oil and NGLs (bbls/d) 7.41 4.13 5.88 5.07 5.94 5.30 6.26 7.05
Natural gas (mcf/d) 1.19 0.52 0.96 0.66 0.88 0.49 1.46 1.07
Combined (boe/d) 7.57 3.65 6.27 4.67 5.59 4.26 5.92 4.90
Operating Expenses(4)(5)
Crude oil and NGLs (bbls/d) 7.93 6.67 7.78 9.41 10.27 9.18 7.61 9.48
Natural gas (mcf/d) 0.77 0.74 0.88 0.87 0.81 0.82 0.86 0.71
Combined (boe/d) 5.09 4.20 5.42 4.95 6.27 4.97 5.86 4.64
Netback Received(6)
Crude oil and NGLs (bbls/d) 30.72 17.03 23.09 17.06 20.53 18.95 20.86 19.52
Natural gas (mcf/d) 5.69 1.76 4.58 2.02 4.16 1.70 3.04 3.09
Combined (boe/d) 26.21 13.25 26.53 14.80 23.95 12.63 22.98 21.08
25
Notes:
(1) Before deduction of royalties.
(2) Production prices are net of costs to transport the product to market and
net of hedging gains and losses.
(3) Royalties are net of ARC.
(4) This figure includes all field operating expenses.
(5) Advantage does not record royalties and operating expenses on a commodity
basis. Information in respect of royalties and operating expenses for
crude oil and NGLs ($/bbl) and natural gas ($/mcf) has been determined by
allocating royalties and expenses on an area by area basis based upon the
relative volume of production of crude oil and NGLs ($/bbl) and natural
gas ($/mcf) in those areas.
(6) Information in respect of netbacks received for crude oil & NGLs ($/bbl)
and natural gas ($/mcf) is calculated using operating expense figures for
crude oil and NGLs ($/bbl) and natural gas ($/mcf), which figures have
been estimated. See note (5) above.
The following table indicates the Trust's exit daily production from its
important fields at December 31, 2003:
Natural Gas Crude Oil & NGLs Total
Properties (mcf/d) (bbls/d) (boe/d)
- --------------------------------------------------------------------------------
Medicine Hat 18,619 -- 3,103
Bantry 14,686 7 2,455
Shouldice 6,998 57 1,223
Wainwright 5,597 34 967
Stoddart/North Pine 4,122 233 920
Nevis 3,638 302 908
Legacy Units 2,012 522 857
- --------------------------------------------------------------------------------
Major Properties 55,672 1155 10,434
Other 23,528 1645 5,566
- --------------------------------------------------------------------------------
Total 79,200 2,800 16,000
Definitions and Other Notes
1. Columns may not add due to rounding.
2. The crude oil, natural gas liquids and natural gas reserve estimates
presented in the McDaniel Report are based upon the definitions and
guidelines contained in the COGE Handbook. A summary of those definitions
are set forth below.
"COGE Handbook" means the Canadian Oil and Gas Evaluation Handbook
prepared jointly by the Society of Petroleum Evaluation Engineers (Calgary
chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum;
"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;
(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.
26
"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.
"Gross" means:
(a) in relation to the Trust's interest in production and reserves, its
"Trust gross reserves", which are the Trust's interest (operating
and non-operating) share before deduction of royalties and without
including any royalty interest of the Trust;
(b) in relation to wells, the total number of wells in which the Trust
has an interest; and
(c) in relation to properties, the total area of properties in which the
Trust has an interest.
"Net" means:
(a) in relation to the Trust's interest in production and reserves, the
Trust's interest (operating and non-operating) share after deduction
of royalties obligations, plus the Trust's royalty interest in
production or reserves.
(b) in relation to wells, the number of wells obtained by aggregating
the Trust's working interest in each of its gross wells; and
(c) in relation to the Trust's interest in a property, the total area in
which the Trust has an interest multiplied by the working interest
owned by the Trust.
"NI 51-101" means National Instrument 51-101 Standards of Disclosure for
Oil and Gas Activities;
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 upon
o analysis of drilling, geological, geophysical and engineering data;
o the use of established technology; and
o specified economic conditions.
Reserves are classified according to the degree of certainty associated with the
estimates.
27
(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.
Other criteria that must also be met for the categorization of reserves are
provided in the COGE Handbook.
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
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.
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:
(a) at least a 90 percent probability that the quantities actually
recovered will equal or exceed the estimated proved reserves; and
(b) at least a 50 percent probability that the quantities actually
recovered will equal or exceed the sum of the estimated proved plus
probable reserves.
Additional clarification of certainty levels associated with reserves estimates
and the effect of aggregation is provided in the COGE Handbook.
REPORT OF MANAGEMENT AND DIRECTORS ON RESERVES DATA AND OTHER INFORMATION
Management of Advantage 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
28
(ii) the related estimated future net revenue; and
(iii) proved and proved plus probable oil and gas reserves estimated
as at December 31, 2003 using constant prices and costs; and
(iv) the related estimated future net revenue.
Sproule Associates Limited ("Sproule") has evaluated the Trust's reserves data.
The report of Sproule is presented below.
The independent reserves evaluation committee of the Trust has
(b) reviewed the Trust's procedures for providing information to
Sproule;
(c) met with Sproule to determine whether any restrictions affected
Sproule's ability to report without reservation; and
(d) reviewed the reserves data with management and the independent
qualified reserves evaluator.
The independent reserves evaluation committee has reviewed the Trust'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 independent reserves evaluation
committee, approved
(e) the content and filing with securities regulatory authorities of the
reserves data and other oil and gas information;
(f) the filing of the report of the independent qualified reserves
evaluator on the reserves data; and
(g) the content and filing of this report.
Because the reserves data are based upon judgments regarding future events,
actual results will vary and the variations may be material.
(signed) "Kelly I. Drader" (signed) "Peter A. Hanrahan"
Kelly I. Drader Peter A. Hanrahan
President and Chief Executive Officer Chief Financial Officer
(signed) "Ronald A. McIntosh" (signed) "Rodger A. Tourigny"
Ronald A. McIntosh Rodger A. Tourigny
Director Director
May 12, 2004
REPORT ON RESERVES DATA
To the board of directors of Advantage Energy Income Fund (the "Trust"):
1. We have evaluated the Trust'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
29
(ii) the related estimated future net revenue.
2. The reserves data are the responsibility of the Trust's management. Our
responsibility is to express an opinion on the reserves data based upon
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 Trust 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 Trust's board of directors:
Net Present Value of Future
Net Revenue (before income
Independent Qualified Location of Reserves taxes, 10% discount rate (000's))
Reserves Evaluator or Description and Preparation Date of (County or Foreign -----------------------------------------
Auditor Evaluation Report Geographic Area) Audited Evaluated Reviewed Total
- -------------------------- ----------------------------------- -------------------- ------- --------- -------- --------
Sproule Associates Limited Evaluation of the P&NG Reserves of Canada $75,876 $444,174 Nil $520,050
Advantage Energy Income Fund as
of December 31, 2003 prepared
December 2003 to April 2004
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 express no opinion on the reserves data that we reviewed but
did not audit or evaluate.
6. We have no responsibility to update our reports referred to in paragraph 4
for events and circumstances occurring after their respective preparation
dates.
7. Because the reserves data are based upon judgements regarding future
events, actual results will vary and the variations may be material.
(signed) "Sproule Associates Limited"
Sproule Associates Limited
Calgary, Alberta
April 19, 2004
ADDITIONAL INFORMATION RESPECTING ADVANTAGE ENERGY INCOME FUND
Trust Units
An unlimited number of Trust Units may be created and issued pursuant to the
Trust Indenture. As at April 30, 2004, 39,502,390 Trust Units were issued and
outstanding. Each Trust Unit represents an equal fractional undivided beneficial
interest in any distributions from, and in any net assets of, the Trust in the
event of termination or winding-up of the Trust. The beneficial interests in the
Trust are divided into interests in two classes as follows: (i) described and
designated as "Trust Units", which are entitled to the rights, subject to
limitations, restrictions and conditions set out in the Trust Indenture, as
summarized herein; and (ii) described and designated as "Special Voting Units",
which shall be issued to a trustee and shall be entitled to such number of votes
at meetings of Trust Unitholders as is equal to the number of Trust Units
reserved for issuance that such Special Voting Units represent, such number of
votes and any other rights or limitations to be prescribed by the Board of
Directors. The Special Voting Units give AOG the flexibility to acquire the
securities of another issuer in consideration for securities which are
ultimately exchangeable for Trust Units. All Trust Units are of the same class
with equal rights and privileges. Each Trust Unit is
30
transferable, entitles the holder thereof to participate equally in
distributions, including the distributions of net income and net realized
capital gains of the Trust, and distributions upon liquidation, is fully paid
and non-assessable and entitles the holder thereof to one vote at all meetings
of Trust Unitholders.
The Trust Units do not represent a traditional investment and should not be
viewed by investors as "shares" in either AOG or the Trust. As holders of Trust
Units in the Trust, the Trust Unitholders will not have the statutory rights
normally associated with ownership of shares of a corporation including, for
example, the right to bring "oppression" or "derivative" actions. The price per
Trust Unit is a function of anticipated distributable income from AOG and the
combined ability of the Board of Directors and the Manager to effect long-term
growth in the value of the Trust. The market price of the Trust Units is
sensitive to a variety of market conditions including, but not limited to,
interest rates, commodity prices and the ability of the Trust to acquire
additional assets. Changes in market conditions may adversely affect the trading
price of the Trust Units.
The Trust Units are not "deposits" within the meaning of the Canada Deposit
Insurance Corporation Act (Canada) and are not insured under the provisions of
that act or any other legislation. Furthermore, the Trust is not a trust company
and, accordingly, is not registered under any trust and loan company legislation
as it does not carry on or intend to carry on the business of a trust company.
Trust Unitholder Limited Liability
The Trust Indenture provides that no Trust Unitholder will be subject to any
liability in connection with the Trust or its obligations and affairs and, in
the event that a court determines Trust Unitholders are subject to any such
liabilities, the liabilities will be enforceable only against, and will be
satisfied only out of the Trust Unitholder's share of the Trust's assets.
Pursuant to the Trust Indenture, the Trust will indemnify and hold harmless each
Trust Unitholder from any cost, damages, liabilities, expenses, charges and
losses suffered by a Trust Unitholder resulting from or arising out of such
Trust Unitholder not having such limited liability.
The Trust Indenture provides that all written instruments signed by or on behalf
of the Trust must contain a provision to the effect that such obligation will
not be binding upon Trust Unitholders personally. Notwithstanding the terms of
the Trust Indenture, Trust 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. Personal liability may also arise in respect of claims against
the Trust (to the extent that claims are not satisfied by the Trust Fund) that
do not arise under contracts, including claims in tort, claims for taxes and
possibly certain other statutory liabilities. The possibility of any personal
liability to Trust Unitholders of this nature arising is considered unlikely in
view of the fact that the sole business activity of the Trust is to hold
securities, and all of the business operations currently carried on by AOG will
be carried on by a corporate entity, directly or indirectly.
The business of the Trust and its wholly-owned Subsidiary, AOG, is conducted,
upon the advice of counsel, in such a way and in such jurisdictions as to avoid
as far as possible any material risk of liability to the Trust Unitholders for
claims against the Trust, including obtaining appropriate insurance, where
available, for the operations of AOG and having written agreements, signed by or
on behalf of the Trust, include a provision that such obligations are not
binding upon Trust Unitholders personally.
Issuance of Trust Units
The Trust Indenture provides that Trust Units or rights to acquire Trust Units
may be issued at the times, to the persons, for the consideration, and on the
terms and conditions that the Board of Directors determines. The Trust Indenture
also provides that immediately after any pro rata distribution of Trust Units to
all Trust Unitholders in satisfaction of any non-cash distribution, the number
of outstanding Trust Units will be consolidated such that each Trust Unitholder
will hold, after the consolidation, the same number of Trust Units as the Trust
Unitholder held before the non-cash distribution. In this case, each certificate
representing a number of Trust Units prior to the non-cash distribution is
deemed to represent the same number of Trust Units after the non-cash
distribution and the consolidation.
31
Cash Distributions
The amount of cash to be distributed annually per Trust Unit shall be equal to a
pro rata share of interest on the 14% Notes, 10?% Notes, royalty income from the
Royalty, dividends on or in respect of shares of AOG received by the Trust and
income from the Permitted Investments; less: (i) administrative expenses and
other obligations of the Trust; and (ii) amounts which may be paid by the Trust
in connection with any cash redemptions of Trust Units. AOG may apply some or
all of its cash flow to capital expenditures to develop the Oil and Natural Gas
Properties of AOG or to acquire additional Oil and Natural Gas Properties prior
to making any distributions to the Trust in the form of principal repayments on
the Notes or dividends on the Common Shares, Non-Voting Shares or Preferred
Shares. If, on any Distribution Record Date, the Trustee determines that the
Trust does not have cash in an amount sufficient to pay the full distribution to
be made on such Distribution Record Date in cash or if any cash distribution
should be contrary to any subordination agreement, the distribution payable to
Unitholders on such Distribution Record Date may, at the option of the Trustee,
include a distribution of additional Trust Units having an equal value to the
cash shortfall. Trust Units will be issued pursuant to exemptions under
applicable securities laws, discretionary exemptions granted by applicable
securities regulatory authorities or a prospectus or similar filing.
The Trust derives interest income from its holdings of the Notes. The 14% Notes
bear interest at 14% per annum, payable monthly and will mature on December 31,
2031, subject to extension for an additional 20-year term at the instance of the
Board of Directors, with the approval thereof by resolution of the holders of
the Notes if the Trust does not then hold substantially all of the 14% Notes.
The 10?% Notes bear interest at 10?% per annum, payable on May 1 and November 1
in each calendar year and mature on December 31, 2012. The 9?% Notes bear
interest at 9?% per annum while the 8 1/2% Notes bear interest at 8 1/2% per
annum and both are payable on February 1 and August 1 in each calendar year and
both mature on December 31, 2013. It is expected that the Trust's income will
generally be limited to: (i) the interest received on the principal amount of
the Notes; (ii) royalty income received on the Royalty; and (iii) dividends (if
any) received on shares of AOG. See "Additional Information Respecting Advantage
Oil & Gas Ltd. - Notes".
The Board of Directors intends for the Trust to make monthly cash distributions.
Cash distributions will be made monthly to the Trust Unitholders of record on
the last day of each month (unless such day is not a Business Day, in which case
the date of record shall be the next following Business Day) and shall be
payable on the 15th day of each month or, if such day is not a Business Day, the
following Business Day or such other date as determined from time to time by the
Trustee.
Redemption Right
Trust Units are redeemable 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
redemption. Upon receipt of the redemption request by the Trust, all rights to
and under the Trust Units tendered for redemption shall be surrendered and the
holder thereof shall be entitled to receive a price per Trust Unit (the
"Redemption 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 are surrendered for redemption (the "Redemption Date");
and (ii) the "closing market price" on the principal market on which the Trust
Units are quoted for trading on the Redemption Date.
For the purposes of this calculation, "market price" is an amount equal to the
simple average of the closing price of the Trust Units for each of the trading
days on which there was a closing price; provided that, if the applicable
exchange or market does not provide a closing price but only provides the
highest and lowest prices of the Trust Units traded on a particular day, the
market price shall be an amount equal to the simple average of the highest and
lowest prices for each of the trading days on which there was a trade; and
provided further that if there was trading on the applicable exchange or market
for fewer than five of the 10 trading days, the market price shall be the simple
average of the following prices established for each of the 10 trading days: the
average of the last bid and last ask prices for each day on which there was no
trading; the closing price of the Trust Units for each day that there was
trading if the exchange or market provides a closing price; and the average of
the highest and lowest prices of the Trust Units for each day that there was
trading, if the market provides only the highest and lowest prices of Trust
Units traded on a particular day. The "closing market price" shall be: an amount
equal to the closing price of the Trust Units if there was a trade on the date;
an amount equal to the average of the highest and lowest prices of the Trust
Units if there was trading and the exchange or other market provides only the
highest and lowest prices of Trust Units traded on a particular day; and the
average of the last bid and last ask prices if there was no trading on the date.
32
The aggregate Redemption Price payable by the Trust in respect of any Trust
Units surrendered for redemption during any calendar month shall be satisfied by
way of a cash payment on or before the last day of the following month; provided
that the entitlement of Trust Unitholders to receive cash upon the redemption 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 redemption in the same calendar month shall not exceed $100,000
(provided that the Trustee may, in its sole discretion, waive such limitation in
respect of any calendar month); (ii) at the time such Trust Units are tendered
for redemption the outstanding Trust Units shall be listed for trading on a
stock 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 Redemption Date or for more than five trading
days during the 10-day trading period commencing immediately after the
Redemption Date.
If a Trust Unitholder is not entitled to receive cash upon the redemption of
Trust Units as a result of the foregoing limitations, then the Redemption Price
for such Trust Units shall be the Fair Market Value thereof (as defined in the
Trust Indenture), as determined by the Trustee in the circumstances described in
subparagraphs (ii) and (iii) above, and shall, subject to any applicable
regulatory approvals, be paid and satisfied by way of distribution in specie of
a pro rata number of 14% Notes (in a minimum amount of $100.00 and integral
multiples of $1.00), from time to time outstanding (i.e., in a principal amount
equal to the Redemption Price). No fractional 14% Notes will be distributed and
where the number of 14% Notes to be received by a Trust Unitholder includes a
fraction, such number shall be rounded to the next lowest whole number. The
Trust shall be entitled to all interest paid, or accrued and unpaid, on the 14%
Notes on or before the date of the distribution in specie. If the Trust does not
hold 14% 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 Redemption Price its own debt
securities (the "Redemption Notes") having terms and conditions substantially
the same as the 14% Notes, and with recourse of the holder limited to the assets
of the Trust. Holders of such 14% Notes and Redemption Notes will be required to
acknowledge that they are subject to the subordination agreements described
below under the heading "Additional Information Regarding Advantage Oil & Gas
Ltd. - Notes". 14% Notes and Redemption Notes may not be qualified investments
for trusts governed by registered retirement savings plans, registered
retirement income funds and deferred profit sharing plans if the Trust ceases to
qualify as a mutual fund trust.
It is anticipated that the redemption right will not be the primary mechanism
for holders of Trust Units to dispose of their Trust Units. 14% Notes or
Redemption Notes which may be distributed in specie to Trust Unitholders in
connection with a redemption will not be listed on any stock exchange and no
market is expected to develop in such 14% Notes or Redemption Notes.
Meetings of Trust Unitholders
The Trust Indenture provides that meetings of Trust Unitholders must be called
and held for, among other matters, the election or removal of the Trustee, the
appointment or removal of the auditors of the Trust, the approval of amendments
to the Trust Indenture (except as described under "Additional Information
Respecting Advantage Energy Income Fund - Amendments to the Trust Indenture"),
the sale of the assets of the Trust in their entirety or substantially in their
entirety (other than as part of an internal reorganization), the termination of
the Trust and the direction of the Trustee as to the selection of the directors
of AOG. Meetings of Trust Unitholders will be called and held annually for,
among other things, the election of the Trustee, the appointment of auditors of
the Trust, and the direction of the Trustee as to the selection of the directors
of AOG. A resolution appointing or removing a Trustee, the auditors of the
Trust, or the direction of the Trustee as to the selection of the directors of
AOG must be passed by a simple majority of the votes cast by Trust Unitholders.
The balance of the foregoing matters must be passed by at least 66?% of the
votes cast at a meeting of Trust Unitholders called for such purpose.
A meeting of Trust Unitholders may be convened at any time and for any purpose
by the Trustee and must be convened if requisitioned by the holders of not less
than 20% of the Trust Units then outstanding by a written requisition. A
requisition must, among other things, state in reasonable detail the business
proposed to be transacted at the meeting.
Trust Unitholders may attend and vote at all meetings of Trust Unitholders
either in person or by proxy and a proxyholder need not be a Trust Unitholder.
Two persons present in person or represented by proxy and representing, in the
aggregate, at least 10% of the votes attaching to all outstanding Trust Units
shall constitute a quorum for the transaction of business at all such meetings.
The Trust Indenture contains provisions as to the notice required and other
procedures with respect to the calling and holding of meetings of Trust
Unitholders. The next annual and special meeting of Trust Unitholders is
scheduled for May 26, 2004.
33
Information and Reports
The Trust will furnish to Trust Unitholders such financial statements (including
quarterly and annual financial statements) and other reports as are, from time
to time, required by applicable law, including prescribed forms needed for the
completion of Trust Unitholders' tax returns under the Tax Act and equivalent
provincial legislation.
Prior to each meeting of Trust Unitholders, the Trustee will provide the Trust
Unitholders (along with notice of such meeting) a proxy form and an information
circular containing information similar to that required to be provided to
shareholders of a Canadian public corporation.
The Board of Directors will ensure that AOG provides the Trust with proper
disclosure as to its business and financial operations and sufficient
information and materials on a timely basis to allow the Trust to meet its
public reporting requirements. With respect to material changes, the Board of
Directors will ensure that AOG provides timely disclosure to the Trust as if AOG
were a public corporation.
Takeover Bids
The Trust Indenture contains provisions to the effect that if a takeover bid is
made for the Trust Units and not less than 90% of the Trust Units (other than
Trust Units held at the date of the takeover bid by or on behalf of the offeror
or associates or affiliates of the offeror) are taken up and paid for by the
offeror, the offeror will be entitled to acquire the Trust Units held by Trust
Unitholders who did not accept the takeover bid on the terms offered by the
offeror.
The Trustee
The Trust Indenture provides that the Trustee shall 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 Trust Unitholders and, in connection
therewith, shall exercise that degree of care, diligence and skill that a
reasonably prudent trustee would exercise in comparable circumstances.
The initial term of the Trustee's appointment is until the first annual meeting
of Trust Unitholders. Thereafter, the trustee shall be reappointed or changed
every year as may be determined by a majority of the votes cast at a meeting of
the Trust Unitholders. The Trustee may resign upon 60 days' notice to the Trust.
The Trustee may also be removed by special resolution of the Trust Unitholders.
Such resignation or removal becomes effective upon the acceptance or appointment
of a successor trustee.
Delegation of Authority, Administration and Trust Governance
The Board of Directors has generally been delegated the significant management
decisions of the Trust and the Manager has been retained to administer the Trust
on behalf of the Trustee. In particular, the Trustee has delegated to the Board
of Directors responsibility for any and all matters relating to: (a) any
offering of securities of the Trust, including: (i) ensuring compliance with all
applicable laws; (ii) all matters relating to the content of any offering
documents, the accuracy of the disclosure contained therein, and the
certification thereof; (iii) all matters concerning any subscription agreements
or underwriting or agency agreements providing for the sale of Trust Units or
securities convertible for or exchangeable into Trust Units or rights to Trust
Units; and (iv) all matters concerning the adoption of a unitholder rights plan;
(b) all matters concerning the terms of, and amendment from time to time of,
material contracts; (c) all matters relating to the redemption of Trust Units;
(d) the determination of any Distribution Record Date other than the last day of
each calendar month and the payment of cash distributions to Unitholders; (e)
the determination of any borrowings under the Trust Indenture; (f) the
acquisition of Permitted Investments and Subsequent Investments by the Trust and
the negotiation of agreements respecting Subsequent Investments; (g) maintaining
the books and records of the Trust and providing timely reports to Unitholders;
(h) the financial statements of the Trust and AOG; (i) the continued listing of
the Trust Units of the Trust on any exchange and to maintain the Trust's status
as a reporting issuer, including press releases and material change reports as
required by the continuous disclosure requirements of applicable securities
legislation; and (j) the Initial Permitted Securities. Trust Unitholders are
entitled to elect a majority of the Board of Directors pursuant to the terms of
the Shareholder Agreement. Subject to the ultimate authority of the Board of
Directors, AOG and the Trust will be managed by the Manager. For more
information as to the Board of Directors, see "Additional Information Respecting
Advantage Oil & Gas Ltd. - Management of AOG".
34
Decision-Making
Although the Manager will provide certain advisory and management services to
the Trust pursuant to the Management Agreement, the Board of Directors will
supervise the management of the business and affairs of the Trust, including the
business and affairs of the Trust delegated to AOG. In particular, significant
operational decisions and all decisions relating to: (i) the acquisition and
disposition of properties, assets or securities (individually or in the
aggregate with respect to any single type of security) for a purchase price or
proceeds in excess of $2,000,000; (ii) the approval of annual operating and
capital expenditure budgets; and (iii) establishment of credit facilities, will
be made by the Board of Directors. In addition, the Trustee has delegated
certain matters to the Board of Directors, including making all decisions
relating to: (i) issuance of additional Trust Units; and (ii) the determination
of the amount of Distributable Income. Any amendment to any material contract to
which the Trust is a party will require the approval of the Board of Directors
on behalf of the Trust. The Board of Directors generally intends to hold
regularly scheduled meetings to review the business and affairs of the Trust and
AOG and to make any necessary decisions relating thereto.
Liability of the Trustee
The Trustee, its directors, officers, employees, shareholders and agents shall
not be liable to any Trust Unitholder or any other person, in tort, contract or
otherwise, in connection with any matter pertaining to the Trust or the Trust
Fund, arising from the exercise by the Trustee of any powers, authorities or
discretion conferred under the Trust Indenture, including, without limitation,
any action taken or not taken in good faith in reliance upon any documents that
are, prima facie, properly executed, any depreciation of, or loss to, the Trust
Fund incurred by reason of the sale of any asset, any inaccuracy in any
evaluation provided by the Manager or any other appropriately qualified person,
any reliance upon any such evaluation, any action or failure to act of the
Manager, AOG, or any other person to whom the Trustee has, with the consent of
AOG, delegated any of its duties hereunder, or any other action or failure to
act (including failure to compel in any way any former trustee to redress any
breach of trust or any failure by the Manager or AOG to perform its duties under
or delegated to it under the Trust Indenture or any material contract), unless
such liabilities arise out of the gross negligence, wilful default or fraud of
the Trustee or any of its directors, officers, employees, shareholders or
agents. If the Trustee has retained an appropriate expert, adviser or legal
counsel with respect to any matter connected with its duties under the Trust
Indenture or any material contract, the Trustee may act or refuse to act based
upon the advice of such expert, adviser or legal counsel, and the Trustee shall
not be liable for and shall be fully protected from any loss or liability
occasioned by any action or refusal to act based upon the advice of any such
expert, adviser or legal counsel. In the exercise of the powers, authorities or
discretion conferred upon the Trustee under the Trust Indenture, the Trustee is
and shall be conclusively deemed to be acting as Trustee of the assets of the
Trust and shall not be subject to any personal liability for any debts,
liabilities, obligations, claims, demands, judgments, costs, charges or expenses
against or with respect to the Trust or the Trust Fund. In addition, the Trust
Indenture contains other customary provisions limiting the liability of the
Trustee.
Amendments to the Trust Indenture
The Trust Indenture may be amended or altered, from time to time, by at least
66?% of the votes cast at a meeting of the Trust Unitholders called for such
purpose.
The Trustee may, without the approval of the Trust Unitholders, make certain
amendments to the Trust Indenture, including amendments:
1. for the purpose of ensuring continuing compliance with applicable laws
(including the Tax Act), regulations, requirements or policies of any
governmental or other authority having jurisdiction over the Trustee or
over the Trust;
2. ensuring that the Trust will satisfy the provisions of each of Sections
108(2)(a) and 132(6) of the Tax Act, as from time to time amended or
replaced;
3. which, in the opinion of the Trustee, provide additional protection for or
benefit to the Trust Unitholders;
4. to remove any conflicts or inconsistencies in the Trust Indenture or
making corrections, including the correction or rectification of any
ambiguities, defective provisions, errors, mistakes or omissions, which
are, in the opinion of the Trustee, necessary or desirable and not
prejudicial to the Trust Unitholders;
35
5. which, in the opinion of the Trustee, are necessary or desirable as a
result of changes in taxation laws; and
6. removing or curing inconsistencies between the Trust Indenture and the
Material Contracts (as such term is defined in the Trust Indenture) which
are, in the opinion of the Trustee, necessary or desirable and not
prejudicial to the Unitholders.
Unitholders will be asked to approve, by way of special resolution, certain
proposed changes to the Trust Indenture at the annual and special meeting of
Unitholders scheduled for May 26, 2004. The specific details of such amendments
are set forth in the Trust's Information Circular - Proxy Statement dated April
16, 2004.
Private Placements
At the upcoming annual and special meeting of Unitholders, Unitholders will be
asked to authorize the sale by the Trust in one or more private placements of up
to 15,000,000 Trust Units on such terms as may be determined by the Board of
Directors and by the Trust. It is anticipated that the Trust may undertake
private placements to complete acquisitions or raise equity capital in order to
fund capital expenditures or acquisitions that may enhance the Trust's business
prospects. The Trust will regularly evaluate opportunities which will assist in
enhancing Trust Unitholder value, and the private placement of Trust Units or
instruments convertible into Trust Units will be routinely considered as a
financing alternative, particularly as a private placement can typically be
structured to reduce the market risk associated with traditional long form
public financings. The Trust obtained such approval last year in order to retain
the flexibility to issue up to 18,000,000 Trust Units by private placement in
2004. The Trust is not currently considering the specific terms of any private
placement pursuant to which it may issue Trust Units.
Any private placement must be undertaken in accordance with applicable corporate
law, securities legislation and stock exchange by-laws, regulations and
policies. Among other things, such regulations limit the discount to the market
price at which the Trust Units may be sold pursuant to a private placement.
Some or all of the Trust Units offered by private placement may be purchased by
insiders of the Trust or AOG. The issuance of greater than 25% of the Trust's
issued and outstanding Trust Units to a new or existing Unitholder or group of
Unitholders may result in a change of control of the Trust or enhance an
existing control position. To the extent that Trust Units are purchased by
insiders, persons having a significant or controlling interest in the Trust may
enhance their ownership position with respect to existing Unitholders who do not
participate in the private placement. Where insiders of the Trust or AOG
participate in any such private placement, the TSX may require evidence of the
approval of the majority of Unitholders, excluding the participating insiders,
to the private placement. Funds received from any private placement will be
added to the Trust's working capital to be used for financing programs,
projects, acquisitions, debt reduction or for general corporate purposes.
Term of the Trust and Sale of Substantially All Assets
The Trust has been established for a term ending December 31, 2095. Pursuant to
the Trust Indenture, termination of the Trust or the sale or transfer of the
assets of the Trust in their entirety or substantially in their entirety, except
as part of an internal reorganization of the assets of the Trust as approved by
the Board of Directors, requires approval by at least 66?% of the votes cast at
a meeting of the Trust Unitholders.
Exercise of Voting Rights Attached to Common Shares
The Trust Indenture provides that the Trustee may vote securities of AOG held by
it at any meeting of shareholders of AOG as well as any Permitted Investments
held, from time to time, as part of the Trust Fund which carry voting rights.
However, the Trustee may not, under any circumstances whatsoever, vote any AOG
securities or any other Permitted Investments which carry voting rights to
authorize the sale, lease or exchange of all or substantially all of the
property of AOG or any other entity owned directly or indirectly by the Trust
which represents more than 51% of the Trust Fund, except as part of a
reorganization of AOG and any one or more directly or indirectly owned
subsidiaries of the Trust without the approval of at least 66?% of the votes
cast at a meeting of the Trust Unitholders called for such purpose.
36
ADDITIONAL INFORMATION RESPECTING ADVANTAGE OIL & GAS LTD.
Management of AOG
Pursuant to the Shareholder Agreement, the Board of Directors is comprised of
not more than nine nor less than five members. The Board of Directors is
currently comprised of the seven members indicated below. Pursuant to the
Management Agreement, the Manager will, at all times, have the right to
designate two directors to the Board of Directors. The directors of AOG that
were appointed by the Manager are Kelly Drader and Gary Bourgeois. Unitholders
will always be entitled to select the majority of the Board of Directors. In
addition, a majority of the Board of Directors must not be officers, employees
or consultants of AOG, the Manager, or any of their respective affiliates, and
the Chairman of the Board of Directors must be a director of the Board elected
by the Unitholders. The following table sets forth certain information
respecting AOG's directors and executive officers.
Name and Position Held and Period Served as
Municipality of Residence a Director(6)(7) Principal Occupations During Past Five Years
- ------------------------- ---------------------------------- --------------------------------------------------------------
Gary F. Bourgeois Vice President, Corporate Vice President, Corporate Development of AOG since May 24,
Toronto, Ontario Development and Director since 2001. Vice President of the Manager since March 2001. Prior
May 24, 2001 thereto, Managing Director of the EnerPlus Group of Companies,
which companies specialize in management of oil and gas income
funds and royalty trusts (1998-2000). In addition, President
of Queen-Yonge Investments Limited (since 1985), a private
family-owned investment holding company with holdings in oil
and gas royalty trusts, real estate income funds, direct oil
and gas properties, private and public exploration and
production companies, and direct commercial real estate
holdings.
Kelly I. Drader(2) President, Chief Executive Officer President and Chief Executive Officer of AOG since May 24,
Calgary, Alberta and Director since May 24, 2001 2001. President of the Manager since March 2001. Prior
thereto, Senior Vice President (1997-2001) and Vice President,
Finance and Chief Financial Officer (1990-1997) of EnerPlus
Group of Companies, which companies specialize in the
management of oil and gas income funds and royalty trusts.
Ronald A. McIntosh(3) Director since September 25, 1998 Chairman of Navigo Energy Inc. since December 2003. As of
Calgary, Alberta December 29, 2003, Navigo Energy Inc. became a wholly-owned
subsidiary of NAV Energy Trust and acts as administrator of
NAV Energy Trust. President and Chief Executive Officer of
Navigo Energy Inc. from October 2001 to December 2003. Prior
to December, Chief Operating Officer of Gulf Canada Resources
Ltd. since December, 2000. Prior thereto, Mr. McIntosh was
Vice President, Exploration and International of Petro-Canada
since May 1996.
Roderick M. Myers(2)(3) Director since December 31, 1996 Since May 24, 2001, a self-employed businessman. Prior
Calgary, Alberta thereto, Vice President, Business Development of Search Energy
Corp.
37
Name and Position Held and Period Served as
Municipality of Residence a Director(6)(7) Principal Occupations During Past Five Years
- ------------------------- ---------------------------------- --------------------------------------------------------------
Steven Sharpe(1)(2) Director since May 24, 2001 Managing Partner of Blair Franklin Capital Partners Inc., an
Toronto, Ontario investment banking firm since May, 2003. Prior thereto, Mr.
Sharpe was the Managing Director of The EBS Corporation, a
management and strategic consulting firm, since June 2001.
From July 1998 to June 2001, Executive Vice President or Vice
President, Strategic Development of The Kroll-O'Gara Company,
a NASDAQ listed professional consulting, manufacturing,
Internet and electronic commerce security company. Prior
thereto, Mr. Sharpe was a partner with Davies, Ward & Beck, a
Toronto-based law firm.
Rodger A. Tourigny(1)(3)(5) Director since December 31, 1996 President of Tourigny Management Ltd., a private oil and gas
Calgary, Alberta consulting company.
Lamont Tolley(1) Non-Executive Chairman and Independent businessman who has been active in the oil and gas
Calgary, Alberta Director since May 24, 2001 industry for 20 years. Currently the President of Genex Energy
Inc., a private oil and gas company. Prior to June 1999, he
was a principal and operating manager of Starvest Capital
Inc., a private company which managed both private
institutional oil investments and two public royalty trusts:
Starcor Energy Royalty Fund and Orion Energy Trust.
Patrick J. Cairns Senior Vice President Senior Vice President of AOG since June 2001. Vice President
Calgary, Alberta of the Manager since May 2001. Prior thereto, Mr. Cairns was
Vice President, Evaluations with the Enerplus Group of
Companies, which companies specialize in the management of oil
and gas income funds and royalty trusts.
Peter Hanrahan Chief Financial Officer and Chief Financial Officer of AOG since January 2003. Prior
Calgary, Alberta Controller thereto, Controller of AOG since December 1999. Prior thereto,
Manager of Financial Reporting with Numac Energy Inc.
Toshiyuki Takahashi Vice President, Exploitation Vice President, Exploitation of AOG since August 2001. Vice
Calgary, Alberta President of the Manager since May 2001. Prior thereto, Mr.
Takahashi was Manager of Acquisitions with the Enerplus Group
of Companies, which companies specialize in the management of
oil and gas income funds and royalty trusts.
Richard Mazurkewich Vice President, Operations Vice President, Operations of AOG since August 2001. Prior
Calgary, Alberta thereto, Manager, Production and Facilities of AOG since March
1998. Prior thereto, Production Engineer with Canadian Natural
Resources Limited.
Jay P. Reid Corporate Secretary Partner, Burnet, Duckworth & Palmer LLP, a Calgary-based law
Calgary, Alberta firm.
38
Notes:
(1) Member of the Audit Committee.
(2) Member of the Human Resources, Compensation and Corporate Governance
Committee.
(3) Member of the Independent Reserve Evaluation Committee.
(4) The Corporation does not have an executive committee of the Board.
(5) Mr. Tourigny was a director of Shenandoah Resources Ltd. ("Shenandoah")
prior to it being placed into receivership on September 17, 2002 and prior
to the issuance of cease trade orders in respect of Shenandoah's
securities by the Alberta Securities Commission and the British Columbia
Securities Commission on November 8, 2002 and October 23, 2002,
respectively. Cease trade orders were issued because Shenandoah failed to
file certain required financial statements. As of the date hereof, the
cease trade orders remain outstanding. Shenandoah's common shares were
suspended from trading on the TSX Venture Exchange on April 24, 2002. Mr.
Tourigny resigned his directorship with Shenandoah effective September 17,
2002. Mr. Tourigny was also a director of Probe Exploration Inc. ("Probe")
prior to its receivership and prior to the issuance of cease trade orders
in respect of Probe's securities by the Alberta Securities Commission and
the Ontario Securities Commission on July 7, 2000 and July 17, 2000,
respectively. The cease trade orders were issued because Probe failed to
file certain required financial statements. As at the date hereof, the
cease trade orders remain outstanding. Probe's common shares were
suspended from trading on the TSX on March 17, 2000, and were subsequently
delisted from the TSX at the close of business on March 16, 2001. Mr.
Tourigny resigned his directorship with Probe effective April 14, 2000.
(6) The Corporation's directors shall hold office until the next annual
general meeting of the Corporation's shareholders or until each director's
successor is appointed or elected pursuant to the ABCA, the Shareholder
Agreement and the Management Agreement.
(7) The period of time served as a director of AOG includes the period of time
served as a director of Search prior to the Amalgamation, where
applicable. Each of the directors were appointed directors of
post-Reorganization Search on May 24, 2001.
As at March 31, 2004, the directors and executive officers of AOG, as a group,
beneficially owned, directly or indirectly, or exercised control or direction
over, 2,484,721 Trust Units, or approximately 6.5% of the issued and outstanding
Trust Units.
Distribution Policy
It is anticipated that income to be received by the Trust will be from: (i) the
interest received on the principal amount of the Notes; (ii) royalty income from
the Royalty; and (iii) the dividends received from the shares of AOG. The
Trustee makes monthly cash distributions to Trust Unitholders of the interest
income earned from the Notes, royalty income from the Royalty and dividends, if
any, received on Common Shares, after expenses, if any, and any cash redemptions
of Trust Units. See "Risk Factors - Oil and Natural Gas Prices/Delay in Cash
Distributions/Dependence on AOG".
Share Capital
AOG is authorized to issue an unlimited number of Common Shares, Non-Voting
Shares and Preferred Shares. The Trust is the sole holder of the issued and
outstanding Common Shares. There are no Non-Voting Shares or Preferred Shares
issued and outstanding. The Trust is also the sole holder of the outstanding
Notes.
The following is a description of the rights attaching to the Common Shares,
Non-Voting Shares, Preferred Shares and notes.
Common Shares
Each Common Share entitles its holder to receive notice of and to attend all
meetings of the shareholders of AOG and to one vote at such meetings. The
holders of Common Shares are, at the discretion of the Board of Directors and
subject to applicable legal restrictions, entitled to receive any dividends
declared by the Board of Directors on the Common Shares. The holders of Common
Shares are entitled to share equally in any distribution of the assets of AOG
upon the liquidation, dissolution, bankruptcy or winding-up of AOG or other
distribution of its assets among its shareholders for the purpose of winding-up
its affairs. Such participation is subject to the rights, privileges,
restrictions and conditions attaching to any instruments having priority over
the Common Shares.
Non-Voting Shares
The Non-Voting Shares have identical rights to the Common Shares except that
holders of Non-Voting Shares are not generally entitled to receive notice of or
attend at meetings of shareholders of AOG or to vote their shares at such
meetings.
39
Preferred Shares
The Preferred Shares may be issued, from time to time, in one or more series,
each series consisting of such number of Preferred Shares as determined by the
Board of Directors, who may also fix the designations, rights, privileges,
restrictions and conditions attached to the shares of each series of Preferred
Shares. No Preferred Shares are presently issued and outstanding. The Preferred
Shares of each series shall, with respect to payment of dividends and
distributions of assets in the event of liquidation, dissolution or winding-up
of AOG, whether voluntary or involuntary, or any other distribution of the
assets of AOG among its shareholders for the purpose of winding-up its affairs,
rank on a parity with the Preferred Shares of every other series and shall be
entitled to preference over the Common Shares and the shares of any other class
ranking junior to the Preferred Shares.
14% Notes
The following is a summary of the material attributes and characteristics of the
14% Notes. This summary does not purport to be complete and is qualified in its
entirety by reference to the provisions of 14% Note Indenture, pursuant to which
the 14% Notes are issued.
The aggregate principal amount of the 14% Notes as at December 31, 2003 was
$314,239,188 and the 14% Notes mature on December 31, 2031, subject to an
extension for an additional 20-year term. The 14% Notes bear interest at the
rate of 14% per annum, payable monthly on the 15th day of the month (or, if such
day is not a Business Day, the first Business Day thereafter) for interest
earned during the preceding month. The principal and interest on the 14% Notes
are payable in lawful money of Canada.
The 14% Notes are issuable only as fully-registered notes in minimum
denominations of $100.00 and integral multiples of $1.00.
Payment upon Maturity
On maturity and subject to any applicable subordination restrictions, AOG will
repay the indebtedness represented by the 14% Notes by paying to the Note
Trustee, in lawful money of Canada, an amount equal to the principal amount of
the outstanding 14% Notes, together with accrued and unpaid interest thereon.
Redemption
The 14% Notes will not be redeemable at the option of AOG or by the holders
thereof prior to maturity except in the limited circumstances prescribed by 14%
Note Indenture, where the Board of Directors believe the indebtedness
represented by the 14% Notes could not be refinanced on maturity, or where AOG
is prevented by applicable law from paying dividends or making other
distributions in respect of Common Shares.
Ranking
Payment of the principal and interest (other than regularly scheduled interest
and principal at maturity, provided no default on Senior Indebtedness (as
hereinafter defined) has occurred and payment of such interest or principal is
not otherwise required to be suspended in accordance with the terms of
subordination agreements which may be entered into with the holders of Senior
Indebtedness (as herein defined)) on the 14% Notes will be subordinated in right
of payment, as set forth in 14% Note Indenture, to the prior payment in full of
the principal of and accrued and unpaid interest on, and all other amounts owing
in respect of, all senior indebtedness ("Senior Indebtedness") which is defined
as: (a) all indebtedness, obligations and liabilities of AOG in respect of
borrowed money (including the deferred purchase price of property), other than:
(i) indebtedness evidenced by the 14% Note Indenture; and (ii) indebtedness
which, by the terms of the instrument creating or evidencing the same, is
expressed to rank in right of payment equally with or subordinate to the
indebtedness evidenced by the 14% Note Indenture; and (b) from and after the
commencement of, and during the continuance of, any creditor proceedings
(including bankruptcy, liquidation, winding-up, dissolution, restructuring or
arrangement proceedings), all indebtedness, obligations and liabilities of AOG,
other than indebtedness, obligations and liabilities of AOG represented by the
14% Notes. The 14% Note Indenture provides that in the event of any creditor
proceedings relative to AOG, the holders of all Senior Indebtedness, which would
include bank debt and suppliers of AOG, will be entitled to receive payment in
full before the holders of the 14% Notes are entitled to receive any payment.
Any amount of property received contrary to these provisions shall be held in
trust for and paid over to the holders of Senior Indebtedness.
40
In the event of any creditor proceedings, the indebtedness represented by the
14% Notes is not to be classified with any Senior Indebtedness for voting or
distribution, which means that holders of Senior Indebtedness may vote
separately from the holders of 14% Notes in respect of any restructuring or
arrangement proposal regarding AOG.
Default
The 14% Note Indenture provides that any of the following shall constitute an
"Event of Default": (i) default in payment of the principal of the 14% Notes
when the same becomes due; (ii) the failure to pay the interest obligations of
the 14% Notes for a period of 12 months; (iii) default on any indebtedness
exceeding $5,000,000; (iv) certain events of winding-up, liquidation,
bankruptcy, insolvency or receivership; (v) the taking of possession by an
encumbrancer of all or substantially all of the property of AOG; or (vi) default
in the observance or performance of any other covenant or condition of 14% Note
Indenture and the continuance of such default for a period of 30 days after
notice in writing has been given by the Note Trustee to AOG specifying such
default and requiring AOG to rectify the same.
Subordination Agreements
Pursuant to the terms of 14% Note Indenture, the Note Trustee may enter into
subordination agreements with the holders of certain Senior Indebtedness under
which the Note Trustee, on behalf of the holders of 14% Notes, may agree
directly with a holder of Senior Indebtedness in implementation of and/or in
addition to the subordination terms described under "Ranking" directly above.
The Note Trustee may give a holder of Senior Indebtedness a power of attorney to
be exercised in any creditor proceedings to enforce the terms thereof. The Note
Trustee may also agree to ensure that any transferee of 14% Notes (or other
securities of AOG) agrees to be bound by the provisions of the subordination
agreements.
10 3/8% Notes
The following is a summary of the material attributes and characteristics of the
10 3/8% Notes. This summary does not purport to be complete and is qualified in
its entirety by reference to the provisions of 10 3/8% Note Indenture, pursuant
to which the 10 3/8% Notes are issued.
The aggregate principal amount of the 10 3/8% Notes as at December 31, 2003 was
$25,798,756 and the 10 3/8% Notes mature on December 31, 2012. The 10 3/8% Notes
bear interest at the rate of 10 3/8% per annum, payable on May 1 and November 1
in each year (or if such day is not a Business Day, the first Business Day
thereafter) for interest earned during the preceding six-month period. The
principal and interest on the 10 3/8% Notes are payable in lawful money of
Canada.
The 10 3/8% Notes are issuable only as fully-registered notes in minimum
denominations of $100.00 and integral multiples of $1.00.
Principal Repayments
From time to time, and in any event, not less frequently than each anniversary
of December 31, 2002, AOG must make principal repayments on the 10 3/8% Notes in
an amount equal to not less than 5% of the original principal amount (being
$52,800,000 - the "Original Principal Amount") provided, however, that during
the period commencing from the date of issue to December 31, 2007 AOG shall
make, in aggregate, principal repayments on the 10 3/8% Notes of an amount equal
to not less than 50% of the Original Principal Amount.
Ranking
Payment of the principal and interest (other than regularly-scheduled interest
and principal payments, provided no default on Senior Indebtedness has occurred
and payment of such interest or principal is not otherwise required to be
suspended, in accordance with the terms of subordination agreements which may be
entered into with the holders of Senior Indebtedness) on the 10 3/8% Notes will
be subordinated in right of payment, as set forth in 10 3/8% Note Indenture to
the prior payment in full of the principal of and accrued and unpaid interest on
all Senior Indebtedness.
41
Default
10 3/8% Note Indenture provides that following an event of default the
defaulting party shall have 30 days from receipt of notice of the default to
rectify same.
Subordination Agreements
Pursuant to the terms of 10 3/8% Note Indenture, the Note Trustee may enter into
subordination agreements with the holders of certain Senior Indebtedness under
which the Note Trustee, on behalf of the holders of the 10 3/8% Notes, may agree
directly with a holder of Senior Indebtedness in the implementation of and/or in
addition to the subordination terms described under "Ranking" directly above.
9 3/8% Notes and 8 1/2% Notes
The following is a summary of the material attributes and characteristics of the
9 3/8% Notes and the 8 1/2% Notes (together the "2003 Notes"). This summary does
not purport to be complete and is qualified in its entirety by reference to the
provisions of 9 3/8% Note Indenture, and 8 1/2% Note Indenture pursuant to which
the 9 3/8% Notes and the 8 1/2% Notes are issued, respectively.
The aggregate principal amount of the 9 3/8% Notes as at December 31, 2003 was
$16,513,000 while the aggregate principal amount of the 8 1/2% Notes as at
December 31, 2003 was $45,313,000 . The 9 3/8% Notes bear interest at a rate of
9 3/8% per annum and the 8 1/2% Notes bear interest at a rate of 8 1/2% per
annum, both are payable on February 1 and August 1 in each year (or if such day
is not a Business Day, the first Business Day thereafter) for interest earned
during the preceding 6 month period. The principal and interest on the 2003
Notes is payable in lawful money of Canada. The 2003 Notes mature on December
31, 2013.
The 2003 Notes are issuable only as fully registered notes in minimum
denominations of $100 and into multiples of $1.00.
Principal Repayments
From time to time, and in any event not less frequently than each anniversary of
December 31, 2003, AOG must make principal repayments on the 2003 Notes in an
amount equal to not less than 5% of the original principal amount (being
$28,800,000 in connection with the 9 3/8% Notes and the $57,600,000 in
connection with the 8 1/2% Notes - the "Original Principal Amounts") provided,
however, that during the period commencing from the date of issue to December
31, 2008 AOG shall make, in aggregate, all principal repayments on the 2003
Notes of an amount equal to not less than 50% of the Original Principal Amounts.
Ranking
Payment of the principal and interest (other than regularly scheduled interest
and principal payments, provided no default on Senior Indebtedness has occurred
and payment of such interest or principal is not otherwise required to be
suspended, in accordance with the terms of subordination agreements which may be
entered into with the holders of Senior Indebtedness (on the 2003 Notes) will be
subordinated in right of payment, as set forth in the 9 3/8% Note Indenture and
8 1/2% Note Indenture, respectively, to the prior payment in full of the
principal of the accrued and unpaid interest on all Senior Indebtedness.
Default
9 3/8% Note Indenture and 8 1/2% Note Indenture, each provide that following an
event of default the defaulting party shall have 30 days from receipt of notice
of the default to rectify same.
Subordination Agreements
Pursuant to the terms of 9 3/8% Note Indenture and 8 1/2% Note Indenture, the
Note Trustee may enter into subordination agreements with the holders of certain
Senior Indebtedness under which the Note Trustee, on behalf of the holders of
the 2003 Notes, may agree directly with a holder of Senior Indebtedness in the
implementation of and/or in addition to the subordination terms described under
"Ranking" directly above.
42
The Royalty Agreement
Pursuant to the Royalty Agreement, AOG has granted to the Trust the Royalty on
AOG's interest in petroleum substances within, upon or under all of AOG's
developed and undeveloped Canadian Oil and Natural Gas Properties
The Royalty will consist of the right to receive a monthly payment from AOG
equal to the "Royalty Production Income", which in respect of any period for
which Royalty is calculated, means 95% of the production revenues from the
Properties less an equivalent portion of the amount of all deductions permitted
under the Royalty Agreement. The Royalty does not constitute an interest in land
and the Trust is not entitled to take its share of production in kind or to
separately sell or market its share of petroleum substances.
Pursuant to the Royalty Agreement approximately 95% of the economic benefit
derived from the assets of AOG accrues to the benefit of the Fund and ultimately
to the Trust and its Unitholders. The term of the Royalty Agreement will be for
so long as there are Properties to which the Royalty Agreement applies.
If AOG wishes to dispose of any properties that will result in proceeds in
excess of $5 million, AOG's board of directors is required to approve such
disposition.
Shareholder Agreement
Pursuant to the Shareholder Agreement, prior to the Trust voting its shares in
AOG, each Trust Unitholder shall be entitled to vote in respect of the matter on
the basis of one vote per Trust Unit held and the Trust shall be required to
vote its shares in AOG in accordance with the result of the vote of Trust
Unitholders. Holders of Trust Units shall be entitled to direct the Trust as to
how to vote in respect of all matters placed before the shareholder of AOG,
including, subject to the right of the Manager to designate two directors, the
election of the directors of AOG, approving its financial statements, and
appointing auditors of AOG, who shall be the same as the auditors of the Trust.
In addition, Trust Unitholders will be entitled to direct the Trust as to how to
vote its shares in AOG on any proposed amendment to the Shareholder Agreement,
where such amendment affects the rights of Unitholders to elect a majority of
the Board of Directors. The Trust will not be entitled, without the direction of
Trust Unitholders, to exercise its rights as the sole shareholder of AOG except
as set forth above.
It is a term of the Shareholder Agreement that the Board of Directors shall
consist of a minimum of five and a maximum of nine directors, with the present
number of directors set at seven. The Shareholder Agreement provides that Trust
Unitholders are entitled to select a majority of the Board of Directors. Under
the terms of the Shareholder Agreement, the Manager has the right to designate
two directors to be elected to the Board of Directors.
ADDITIONAL INFORMATION RESPECTING ADVANTAGE INVESTMENT MANAGEMENT LTD.
Pursuant to the Management Agreement, the Manager has agreed to act as manager
of the Trust and AOG. The Board of Directors has retained the Manager to provide
comprehensive management services and has delegated certain authority to the
Manager to assist in the administration and regulation of the day-to-day
operations of the Trust and AOG and to assist in making executive decisions
which conform to the general policies and general principles previously
established by the Board of Directors. The Manager will provide executive
officers to AOG, subject to the approval of the Board of Directors.
43
Management of the Manager
The following table outlines the names and municipalities of residence and
principal occupations of the officers of the Manager who will be responsible for
the provision of such executive services.
Name and
Municipality of
Residence Office Principal Occupation During the Past Five Years
- ---------------- -------------- --------------------------------------------------------------------------------
Kelly Drader President President and Chief Executive Officer of AOG since May 2001. President of the
Calgary, Alberta Manager since March 2001. Prior thereto, Senior Vice President (1997-2001) and
Vice President, Finance and Chief Financial Officer (1990-1997) of EnerPlus
Group of Companies, which companies specialize in the management of oil and gas
income funds and royalty trusts.
Gary Bourgeois Vice President Vice President, Corporate Development of AOG since May 2001. Vice President of
Toronto, Ontario the Manager since March 2001. Prior thereto, Managing Director of the EnerPlus
Group of Companies, which companies specialize in management of oil and gas
income funds and royalty trusts (1998-2000). In addition, President of
Queen-Yonge Investments Limited (since 1985), a private family-owned investment
holding company with holdings in oil and gas royalty trusts, real estate income
funds, direct oil and gas properties, private and public exploration and
production companies, and direct commercial real estate holdings.
Patrick J. Cairns Vice President Senior Vice President of AOG since June 2001. Vice President of the Manager
Calgary, Alberta since May 2001. Prior thereto, Mr. Cairns was Vice President, Evaluations with
the Enerplus Group of Companies, which companies specialize in the management of
oil and gas income funds and royalty trusts.
Toshiyuki Takahashi Vice President Vice President, Exploitation of AOG since August 2001. Vice President of the
Calgary, Alberta Manager since May 2001. Prior thereto, Mr. Takahashi was Manager of Acquisitions
with the Enerplus Group of Companies, which companies specialize in the
management of oil and gas income funds and royalty trusts.
Management Agreement
The Management Agreement provides that during the term of the Management
Agreement, and any renewal thereof, the Manager shall provide recommendations,
assistance and advisory services as requested or required by AOG and the Trust,
respecting the following:
1. to AOG:
(a) keep and maintain at its offices, at all times, books, records and
accounts which shall contain particulars of operations, receipts,
disbursements and investments relating to the Properties and AOG;
(b) make available, in performing its obligations under the Management
Agreement, office space, equipment and qualified personnel,
including all engineering, geological, geophysical, accounting,
clerical, secretarial, corporate and administrative services as may
be necessary to perform its obligations;
(c) arrange or provide for the payment of all costs and expenses
incurred by or on behalf of AOG in connection with the Properties
upon receipt of monies from AOG;
(d) provide or arrange for the administration of all of the records and
documents for the Properties including establishing and maintaining
documents, correspondence files, land files and records;
44
(e) provide or arrange to provide such audit, legal, geological,
engineering, geophysical, financial, insurance and other
professional services or advice and analysis as the officers or
directors of AOG may require or desire to permit any of them to make
informed decisions in connection with the discharge by them of their
responsibilities as officers or directors, to the extent such advice
and analysis can be reasonably provided or arranged by the Manager;
(f) at least annually, and at other times as requested by the Board of
Directors, prepare all production, capital and expense budgets and
business plans in connection with the Properties and also provide
quarterly progress reports to the Board of Directors;
(g) provide or cause to be provided to AOG any services or analysis
reasonably necessary for AOG to be able to consider or participate
in any acquisition, development or disposition by AOG of an interest
in the Properties or other interests in assets;
(h) provide or arrange for such additional administrative services as
AOG may reasonably request in connection with the Properties,
including services relating to the administration of credit
facilities obtained by AOG;
(i) review opportunities to acquire additional Properties which, acting
reasonably, it believes AOG might reasonably be interested in
acquiring and, from time to time, to present AOG with opportunities
to acquire Properties consistent with the investment criteria of
AOG;
(j) conduct negotiations for the acquisition of Properties, provide
lease and land services related to such acquisitions (including
examination and evaluation of any title documents) and arrange for
examination and preparation of legal documents or such other
services required in connection with such acquisitions, provided
that the Manager shall be deemed not to make any warranty of title
with respect to any Properties acquired by AOG;
(k) provide or arrange for all necessary exploitation, development and
other services in respect of acting as operator of any of the
Properties;
(l) review all data, information, notices and requests tendered by any
third party operator, advise AOG as to the appropriate action to be
taken and provide or arrange for any required expertise on behalf of
AOG to facilitate the proper conduct of operations in respect
thereof;
(m) arrange for and negotiate, on behalf of and in the name of AOG, all
contracts with third parties for the proper management and
operations of the Properties;
(n) supervise the disposition and marketing of petroleum substances from
the Properties, invoice third parties as required and effect the
collection of receivables relating thereto;
(o) ensure that AOG complies with all material regulations, statutes and
reporting requirements in connection with the Properties;
(p) carry out the functions and obligations of AOG contained in the
Royalty Agreement with respect to operation of the Properties; and
(q) negotiate all borrowings required by AOG to purchase Properties or
to fund capital expenditures;
2. to the Trust:
(a) ensure compliance by the Trust with its legal obligations, including
its continuous disclosure obligations under all applicable
securities legislation;
(b) provide investor relations services;
45
(c) provide the holders of Trust Units with financial reports and tax
information relating to the Properties, the Notes, the Royalty and
the Trust;
(d) call, hold and distribute materials including notices of meetings
and information circulars in respect of all necessary meetings of
Unitholders;
(e) recommend the amounts payable, from time to time, to Unitholders and
to arrange for distributions to Unitholders of distributable income;
(f) recommend the timing and terms of future offerings of Trust Units or
securities convertible or exchangeable into Trust Units or other
public or private securities, if any; and
(g) recommend investments in Permitted Investments.
The Manager is paid fees for providing all of the services in items 1 and 2
above. See "Additional Information Respecting Advantage Investment Management
Ltd. - Compensation and Term". Notwithstanding the delegations provided in items
1 and 2 above, the Board of Directors will supervise the management of the
business and affairs of AOG, including the business and affairs of the Trust
delegated to AOG, and, in particular:
3. significant operational decisions in respect of AOG as identified by the
Manager, acting reasonably; and
4. decisions relating to:
(a) any offerings, including the issuance of additional Trust Units or
securities convertible into or exchangeable for Trust Units;
(b) the acquisition and disposition of properties, assets, securities
(individually or in the aggregate with respect to any single type of
security) for a purchase price or proceeds in excess of $2,000,000;
(c) the approval of operating and capital expenditure budgets;
(d) the establishment of credit facilities;
(e) all matters to do with the continued listing of the Trust Units on
any exchange and to maintain the Trust's status as a reporting
issuer, including press releases and material change reports as
required by continuous disclosure requirements of applicable
securities legislation;
(f) the determination of the amount of Distributable Income; and
(g) the approval of any amendment to the Management Agreement, the
Royalty Agreement, the Note Indentures or the Shareholder Agreement
on behalf of the Trust, and those matters as set forth in the Trust
Indenture, that may be amended without the approval of Unitholders;
shall be subject to the approval of the Board of Directors.
The Manager and the Trust are responsible for ensuring compliance with the
continuous disclosure obligations under all applicable securities legislation.
The Manager has been indemnified by AOG and the Trust in respect of damages
suffered relating to the performance of services under the Management Agreement
provided that the Manager is in compliance with the standard of care described
below, and any of its directors, officers or employees have been indemnified by
AOG and the Trust provided that such person shall not be found to be liable for
or guilty of wilful misfeasance, bad faith, gross negligence or reckless
disregard of his or her duty to AOG or the Trust.
In exercising its powers and discharging its duties under the Management
Agreement, the Manager is required to exercise that degree of care, diligence
and skill that a reasonably-prudent operator and manager in respect of oil and
gas properties in western
46
Canada and a manager of a publicly-traded reporting issuer, having
responsibility for the subject management, advisory and administrative services,
would exercise in comparable circumstances.
Acquisition and Disposition Strategy
The strategy employed by the Manager is to maintain the level of production of
oil and natural gas from AOG's existing properties and to supplement production
by reserve acquisitions. To maintain production, capital expenditures are
focused on development activity as opposed to exploration. Exploration
properties are generally sold, farmed out or developed using third party
resources. Reserve replacement and additions are achieved through development
activity and acquisitions.
In addition, as part of the services to be provided by the Manager to AOG and
the Trust, the Manager may recommend that AOG enter into agreements to dispose
of Oil and Natural Gas Properties and make farmouts and other dispositions of
such properties. Approval by the Board of Directors of any acquisitions or
dispositions is required where the properties being acquired or disposed of have
a purchase price or proceeds in excess of $2,000,000.
Compensation and Term
In its role under the Management Agreement as manager and administrator of AOG
and the Trust, the Manager receives the following:
1. a fee in an amount equal to 1.5% of Operating Cash Flow, such amount to be
calculated as at the end of each calendar quarter or portion thereof, if
applicable, and paid on the 15th day following any such calendar quarter,
or, if such day is not a Business Day, on the next Business Day; and
2. a fee in an amount equal to 10% of the Total Return Amount (which means,
in respect of any Return Period, an amount equal to the Total Return
Percentage minus 8% if the Return Period is a full calendar year, and
adjusted appropriately should the Return Period be less than a full
calendar year, multiplied by the Market Capitalization for that Return
Period), such amount to be calculated as at the end of each Return Period
and paid on the 15th day following the end of each such Return Period, or,
if such day is not a Business Day, on the next Business Day.
In addition, the Manager has the option (subject to any necessary regulatory
approval) of receiving all or part of the fee provided in paragraph 2 above in
Trust Units at the Unit Market Price calculated as at the end of the relevant
period. To date, no such election has been made.
The Manager representatives who act as employees or officers of AOG are entitled
to participate in any benefit plans in place for AOG employees (including under
any incentive plan) and are entitled to industry-competitive salaries (as
approved by the Board of Directors) for acting in such capacity.
The Manager does not receive any acquisition or disposition fees.
It is the intention of the Manager that the management fees referred to in
paragraphs 1 and 2 above (collectively, the "Management Fees") will fund all
employee bonuses and incentive plans and, to date, such fees have been allocated
by the Manager on the following basis:
Manager Shareholders 66 2/3%
Employees of AOG 33 1/3%
The allocation of the Management Fees and the Termination Fees (as defined
below) amongst the employees of AOG will be based upon the recommendations of
the Manager as approved by the Board of Directors.
The initial term (the "Initial Term") of the Management Agreement is 3 years,
and on each anniversary date of the Management Agreement it automatically renews
on an "evergreen" basis for additional one-year periods, provided that the Board
of Directors has not provided notice to the Manager prior to any such renewal
that such renewal shall not occur. In all instances of termination (except where
the Management Agreement terminates at the end of the term), a termination fee
(the "Initial Termination Fee") equal to the Management Fees paid for the
immediately-prior two years shall be payable, which will be adjusted on a pro
rata
47
basis to reflect a full two-year period if a two-year time period has not yet
passed. Upon completion of the Initial Term, in all instances of termination
(except where the Management Agreement terminates at the end of the term), a
termination fee ("Subsequent Termination Fee") equal to the Management Fees paid
for the immediately-prior 2 1/2 years shall be payable. In no instance shall the
Manager be entitled to both the Initial Termination Fee and the Subsequent
Termination Fee. The Initial Termination Fee and the Subsequent Termination Fee
are, collectively, referred to herein as the "Termination Fees". Notwithstanding
the foregoing, if, during the Initial Term, Kelly Drader (or an alternative
individual with comparable skill and experience who is acceptable to the Board
of Directors) no longer provides all or substantially all of his work time to
AOG and the Trust, the Management Agreement can be terminated by AOG and the
Trust and the Manager will not be entitled to any Termination Fees.
In addition, the Manager is entitled to reimbursement, by the Trust and AOG, of
General and Administrative Costs and expenses related to the Manager's
performance under the Management Agreement, other than costs related solely to
the Manager and costs related to employee bonuses and incentive plans.
Conflicts of Interest
The executive officers of the Manager have extensive experience in the oil and
gas business and in the management of private and public entities. As a result,
certain of the directors, officers and employees of the Manager, and certain of
the consultants retained by the Manager, from time to time, may also be
directors, officers and employees of affiliates of the Manager or may be
consultants retained by affiliates of the Manager. The Management Agreement
contains provisions which require the Manager to make disclosure to the Trustee
and the Board of Directors of the fact and substance of any particular conflict
of interest, if one should occur, and to use all reasonable efforts to resolve
such conflict of interest in a manner which will treat the Trust or AOG, as the
case may be, and the other interested party in an even-handed manner, taking
into account all of the circumstances of the Trust or AOG, as the case may be,
and such interested party, and to act honestly and in good faith in resolving
such matters.
Pursuant to the Management Agreement, the Manager has agreed to make Kelly
Drader available for the performance of the services to be provided to the Trust
and AOG, and Mr. Drader will, during the Initial Term, commit substantially all
of his work time on an annual basis to AOG and the Trust in performing the
services to be provided under the Management Agreement and in acting as AOG's
President and Chief Executive Officer.
The Management Agreement also provides that the Manager and the ManagementCo
Group agree that during the Initial Term:
1. they will not manage another oil and gas income fund or royalty trust;
2. they will not, without prior approval of the Trust and AOG, acting
reasonably, as determined by the Board of Directors, make investments in
or acquire oil and gas assets or income funds, royalty trusts or companies
owning oil and gas assets, except for the purchase of securities of public
oil and gas companies, income funds or royalty trusts on a recognized
stock exchange for investment purposes. Such shareholding in each such
investment shall not exceed 10% of the issued and outstanding securities
of any such issuer; and
3. they will not, without prior approval of the Trust and AOG, acting
reasonably, as determined by the Board of Directors, conduct any other
business activities relating to Canadian resource properties or rendering
services or acting as advisor or manager to any other person or entity
that may have investment or business interests similar to those of AOG or
the Trust;
and thereafter they will not do any of the foregoing except with prior
disclosure to the Board of Directors of the nature and extent of their interest
in such activities and a description of such activities and unless, in each
case, the consent of the Board of Directors is first obtained.
As at the date hereof, neither the Trust, AOG nor the Manager is aware of any
existing or potential material conflicts of interest between the Trust and/or
AOG and a director or officer of the Manager.
48
Cash Distributions
The following is a summary of the distribution made by Advantage from its
inception in May of 2001 to December 31, 2003.
For the 2001 Period Ended Distributions per Unit Payment Date
------------------------- ---------------------- ------------------
June 30 $0.28 July 16, 2001
July 31 0.28 August 15, 2001
August 31 0.22 September 17, 2001
September 30 0.22 October 15, 2001
October 31 0.15 November 15, 2001
November 30 0.15 December 17, 2001
December 31 0.15 January 15, 2002
-----
Total: $1.45
For the 2002 Period Ended Distributions per Unit Payment Date
------------------------- ---------------------- ------------------
January 31 $0.15 February 15, 2002
February 28 0.13 March 15, 2002
March 31 0.13 April 15, 2002
April 30 0.13 May 15, 2002
May 31 0.13 June 17, 2002
June 30 0.13 July 15, 2002
July 31 0.13 August 15, 2002
August 31 0.13 September 16, 2002
September 30 0.13 October 15, 2002
October 31 0.18 November 15, 2002
November 30 0.18 December 16, 2002
December 31 0.18 January 15, 2003
-----
Total: $1.73
For the 2003 Period Ended Distributions per Unit Payment Date
------------------------- ---------------------- ------------------
January 31 $0.18 February 18, 2003
February 28 0.23 March 17, 2003
March 31 0.23 April 15, 2003
April 30 0.23 May 15, 2003
May 31 0.23 June 16, 2003
June 30 0.23 July 15, 2003
July 31 0.23 August 15, 2003
August 31 0.23 September 15, 2003
September 30 0.23 October 15, 2003
October 31 0.23 November 17, 2003
November 30 0.23 December 15, 2003
December 31 0.23 January 15, 2004
-----
Total: $2.71
MARKET FOR SECURITIES
The Trust Units are listed for trading on the TSX under the symbol "AVN.UN". The
following table sets forth the high and low closing trading prices and the
aggregate trading volume of the Trust Units as reported by the TSX for the
periods indicated.
49
Price Range
-----------------
High Low
($) ($) Volume
----- ----- ---------
2003
----
January .......... 13.73 12.86 2,153,333
February ......... 15.58 13.10 2,736,450
March ............ 15.59 11.80 2,732,097
April ............ 16.15 14.15 2,320,369
May .............. 16.55 15.30 2,579,951
June ............. 16.95 15.60 3,094,752
July ............. 16.30 14.92 2,625,024
August ........... 17.25 15.60 2,967,978
September ........ 17.20 16.01 2,408,053
October .......... 16.80 16.10 2,618,497
November ......... 16.60 15.68 2,854,848
December ......... 17.95 15.65 4,210,860
PROMOTERS
Advantage Investment Management Ltd. could be considered the promoter of the
Trust for the years 2001 and 2002. The Manager holds 732,737 Trust Units or 1.8%
of the issued and outstanding Trust Units as at April 30, 2004. The Manager is a
party to the Management Agreement with the Trust. See "Additional Information
Respecting Advantage Investment Management Ltd.".
LEGAL PROCEEDINGS
There are no outstanding legal proceedings which are for claims in excess of 10%
of the current asset value of the Trust to which the Trust is a party or in
respect of which any of its properties are subject, nor are there any such
proceedings known to be contemplated.
INTEREST OF INSIDERS AND OTHERS IN MATERIAL TRANSACTIONS
There were no material interests, direct or indirect, of directors of AOG or
directors and senior officers of the Manager, nominees for director of AOG, any
Unitholder who beneficially owns more than 10% of the Trust Units or any known
associate or affiliate of such persons in any transaction during 2003 or in any
proposed transaction which has materially affected or would materially affect
the Trust or AOG other than (i) certain insiders purchasing Trust Units or
Debentures under the public offerings of such securities completed during 2003,
and (ii) as disclosed herein.
AUDITORS, TRANSFER AGENT AND REGISTRAR
The auditors of the Trust are KPMG LLP, Chartered Accountants, Calgary, Alberta.
Computershare Trust Company of Canada at its offices in Calgary, Alberta and
Toronto, Ontario acts as the transfer agent and registrar for the Trust Units, 8
1/4% Debentures, 9% Debentures and 10% Debentures.
MATERIAL CONTRACTS
Except for contracts entered into by the Trust in the ordinary course of
business or otherwise disclosed herein, the only material contracts entered into
by the Trust are the Trust Indenture described herein under the heading
"Additional Information Respecting Advantage Energy Income Fund" and the
Management Agreement described herein under the heading "Additional Information
Respecting Advantage Investment Management Ltd. - Management Agreement". Copies
of the Trust Indenture and Management Agreement were filed publicly on June 23,
2003 and November 21, 2003, respectively, and are available on the Trust's SEDAR
profile at www.sedar.com.
50
INTEREST OF EXPERTS
Burnet, Duckworth & Palmer LLP, Calgary, Alberta has helped prepare this annual
information form and Sproule Associates Limited, has certified certain of the
contents herein. No person or company whose profession or business gives
authority to a statement made by such person or company and who is named in this
annual information form or in a document that is specifically incorporated by
reference into this annual information form as having prepared or certified a
part of this annual information form, or a report or valuation described in this
annual information form or in a document specifically incorporated by reference
into this annual information form, has received or shall receive a direct or
indirect interest in the property of the Trust or of any associate or affiliate
of the Trust. As at the date hereof, the aforementioned persons and companies
beneficially own, directly or indirectly, less than 1% of the securities of the
Trust and its associates and affiliates. In addition, none of the aforementioned
persons or companies, nor any director, officer or employee of any of the
aforementioned persons or companies, is or is expected to be elected, appointed
or employed as a director, officer or employee of the Trust or of any associates
or affiliates of the Trust, except for Jay P. Reid, the Corporate Secretary of
AOG, who is a partner at Burnet, Duckworth & Palmer LLP, which law firm renders
legal services to the Trust.
RISK FACTORS
The following is a summary of certain risk factors relating to the business of
AOG and the Trust. The following information is a summary only of certain risk
factors and is qualified in its entirety by reference to, and must be read in
conjunction with, the detailed information appearing elsewhere in this Annual
Information Form.
Dependence on AOG
The Trust is an open-ended, limited purpose trust which will be entirely
dependent upon the operations and assets of AOG through its ownership of the
Common Shares, the Notes and the Royalty. Accordingly, the cash distributions to
the Trust Unitholders will be dependent upon the ability of AOG to meet its
interest and principal repayment obligations under the Notes to declare and pay
dividends on the Common Shares, and to pay the Royalty. AOG's income will be
received from the production of oil and natural gas from AOG's existing Canadian
resource properties and will be susceptible to the risks and uncertainties
associated with the oil and natural gas industry generally. AOG is generally not
involved in the exploration for oil and natural gas. As a result, if the oil and
natural gas reserves associated with AOG's Canadian resource properties are not
supplemented through additional development or the acquisition of additional Oil
and Natural Gas Properties, the ability of AOG to meet its obligations to the
Trust may be adversely affected.
Exploitation and Development
Exploitation and development risks are due to the uncertain results of searching
for and producing oil and natural gas using imperfect scientific methods. These
risks are mitigated by using highly skilled staff, focusing exploitation efforts
in areas in which Advantage has existing knowledge and expertise or access to
such expertise, using up-to-date technology to enhance methods, and controlling
costs to maximize returns. Advanced oil and natural gas related technologies
such as three-dimensional seismography, reservoir simulation studies and
horizontal drilling have been and will be used by Advantage to improve its
ability to find, develop and produce oil and natural gas.
Operations
AOG's operations are subject to all of the risks normally incident to the
operation and development of Oil and Natural Gas Properties and the drilling of
oil and natural gas wells, including encountering unexpected formations or
pressures, blow-outs, craterings and fires, all of which could result in
personal injuries, loss of life and damage to the property of AOG and others.
AOG has both safety and environmental policies in place to protect its operators
and employees, as well as to meet the regulatory requirements in those areas
where it operates. In addition, AOG has liability insurance policies in place,
in such amounts as it considers adequate, however, it will not be fully insured
against all of these risks, nor are all such risks insurable. Costs incurred to
repair any of such damage or pay any of such liabilities will reduce Royalty
Income.
Continuing production from a property, and, to some extent the marketing of
production therefrom, are largely dependent upon the ability of the operator of
the property. To the extent the operator fails to perform these functions
properly, revenue may be reduced. Payments from production generally flow
through the operator and there is a risk of delay and additional expense in
51
receiving such revenues if the operator becomes insolvent. Although satisfactory
title reviews are generally conducted in accordance with industry standards,
such reviews do not guarantee or certify that a defect in the chain of title may
not arise to defeat the claim of AOG to certain Properties. A reduction of the
income from the Royalty could result in such circumstances.
Expansion of Operations
The operations and expertise of management of the Trust are currently focused on
conventional oil and gas production and development in the Western Canadian
Sedimentary Basin. In the future, the Trust may acquire oil and gas properties
outside this geographic area. In addition, the Trust Indenture does not limit
the activities of the Trust to oil and gas production and development, and the
Trust could acquire other energy related assets, such as oil and natural gas
processing plants or pipelines, or an interest in an oil sands project.
Expansion of our activities into new areas may present new additional risks or
alternatively, may significantly increase the exposure to one or more of the
present risk factors which may result in future operational and financial
conditions of the Trust being adversely affected.
Oil and Natural Gas Prices
The monthly cash distributions the Trust pays to Unitholders are highly
dependent upon the prices received for AOG'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
AOG. 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.
Declines in oil or natural gas prices will have an adverse effect upon the
Trust's operations, financial condition, reserves and ultimately on its ability
to pay distributions to Unitholders.
The Trust may manage the risk associated with changes in commodity prices by
entering into oil or natural gas price hedges. If the Trust hedges its commodity
price exposure, it will forego the benefits it would otherwise experience if
commodity prices were to increase. In addition, commodity hedging activities
could expose the Trust to losses. To the extent that the Trust engages in risk
management activities related to commodity prices, it will be subject to credit
risks associated with counterparties with which it contracts.
Oil prices were relatively high 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, such price 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. The price of oil
and natural gas will fluctuate and price and demand are factors beyond
Advantage's control. Such fluctuations will have a positive or negative effect
upon the revenue to be received by it. Such fluctuations will also have an
effect upon the acquisition costs of any future Oil and Natural Gas Properties
that Advantage may acquire. As well, cash distributions from the Trust will be
highly sensitive to the prevailing price of crude oil and natural gas.
52
Marketing
The marketability and price of oil and natural gas that may be acquired or
discovered by Advantage will be affected by numerous factors beyond Advantage's
control. These factors include demand for oil and natural gas, market
fluctuations, the proximity and capacity of oil and natural gas pipelines and
processing equipment and government regulations, including regulations relating
to environmental protection, royalties, allowable production, pricing, importing
and exporting of oil and natural gas.
Capital Investment
To the extent that AOG uses cash flow to finance acquisitions, development costs
and other significant expenditures, the net cash flow of the Trust will be
reduced. Hence, the timing and amount of capital expenditures may affect the
amount of net cash flow available to the Trust and, as a consequence, the amount
of cash available to distribute to Unitholders. Therefore, distributions may be
reduced, or even eliminated, at times when significant capital or other
expenditures are made.
The Board of Directors has the discretion to determine the extent to which cash
flow will be allocated to the payment of debt service charges as well as the
repayment of outstanding debt, including under the credit facility. As a
consequence, the amount of funds retained by AOG to pay debt services charges or
reduce debt will reduce the amount of cash distributed to Unitholders during
those periods in which funds are so retained.
Assessments of Value of Acquisitions
Acquisitions of resource issuers and resource assets will be based in large part
upon 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 the Trust'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 upon reports by a firm of independent
engineers that are not the same as the firm that the Trust 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 the Trust. Any such instance may offset the
return on and value of the Trust Units.
Possible Changes in Accounting Standards Applicable to Convertible Debentures
On November 3, 2003 the Accounting Standards Board of the Canadian Institute of
Chartered Accountants approved, subject to a written ballot, a change to the
accounting standards applicable to convertible debentures such as those proposed
to be issued by the Trust. If approved, the new standard would require that the
amounts outstanding under the Debentures be classified as liabilities and that
the interest costs on the Debentures be included as interest expense in the
determination of net income. The new standards would be effective for fiscal
periods beginning on or after November 1, 2004.
Debt Service
AOG has credit facilities in the amount of $180,000,000. Variations in interest
rates and scheduled principal repayments could result in significant changes in
the amount required to be applied to debt service before payment of any amounts
to the Trust. Although it is believed that the bank line of credit is
sufficient, there can be no assurance that the amount will be adequate for the
financial obligations of AOG or that additional funds can be obtained.
The lenders have been provided with security over substantially all of the
assets of AOG. If AOG becomes unable to pay its debt service charges or
otherwise commits an event of default such as bankruptcy, the lenders may
foreclose on or sell the Properties free from or together with the Royalty. The
payment of interest and principal on debt may also result in the Trust or its
subsidiaries having taxable income and cash taxes payable as taxable income
would no longer be reduced by royalty payments at the time debt repayment
occurs.
53
Prior Ranking Indebtedness; Absence of Covenant Protection
The Debentures will be subordinate to all Senior Indebtedness and to any
indebtedness of creditors of Advantage. The payment of principal and interest on
the Debentures will be subordinated to the Senior Indebtedness of Advantage and
to indebtedness of trade creditors of Advantage. The Debentures will also be
effectively subordinate to claims of creditors of Advantage's subsidiaries
except to the extent Advantage is a creditor of such subsidiaries ranking at
least pari passu with such other creditors.
The Indentures will not limit the ability of Advantage to incur additional
liabilities (including Senior Indebtedness) or to make distributions, except, in
respect of distributions, where an Event of Default has occurred or would occur
and such default has not been cured or waived. The Indentures do not contain any
provision specifically intended to protect holders of the Debentures in the
event of a future leveraged transaction involving Advantage. However, the
Indentures, among other things, restrict the Trust's level of indebtedness,
provides operating investment guidelines, mandates the making of distributions
and specify the nature of the Trust's business.
The economic impact on Advantage of claims of aboriginal title is unknown.
Aboriginal people have claimed aboriginal title and rights to a substantial
portion of western Canada. Advantage is unable to assess the effect, if any,
that any such claim would have on its business and operations.
Environmental Concerns
The oil and natural gas industry is subject to 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 in respect of
AOG or the Properties. Such legislation may be changed to impose higher
standards and potentially more costly obligations on AOG. Although AOG has
established a reclamation fund for the purpose of funding its currently
estimated future environmental and reclamation obligations based upon its
current knowledge, there can be no assurance that the Trust will be able to
satisfy its actual future environmental and reclamation obligations.
Although AOG 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, AOG'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 AOG's cash flow and could therefore reduce
distributable income payable to Unitholders.
Additionally, the potential impact on the Trust's operations and business of the
December 1997 Kyoto Protocol, which has now been ratified by Canada, with
respect to instituting reductions of greenhouse gases is difficult to quantify
at this time as specific measures for meeting Canada's commitments have not been
developed.
Unforeseen Title Defects
Although title reviews are generally 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 AOG'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.
Any site reclamation or abandonment costs actually incurred in the ordinary
course of business in a specific period will be funded out of cash flow and,
therefore, will reduce the amounts available for distribution to Unitholders.
Should the Trust be unable to fully fund the cost of remedying an environmental
problem, it might be required to suspend operations or enter into interim
compliance measures pending completion of the required remedy.
Delay in Cash Distributions
In addition to the usual delays in payment by purchasers of oil and natural gas
to the operators of the Properties, and by the operator to the Manager or AOG,
payments between any of such 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,
54
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 distributions to Unitholders.
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 the Trust'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
the Trust has engaged in, or in the future will engage in risk management
activities related to commodity prices and foreign exchange rates. The Trust
will be subject to unfavourable price changes and credit risks associated with
the counterparties with which it contracts. The Trust 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, as well as impact the market price of the Trust
Units on the TSX.
Reliance upon the Manager and Senior Executives of AOG
Unitholders will be dependent upon the management of the Manager and AOG in
respect of the administration and management of all matters relating to the
Properties, the Royalty, the Trust and the Trust Units. The loss of the services
of key individuals who currently comprise the management team of the Trust could
have a detrimental effect upon the Trust. Investors who are not willing to rely
on the management of the Manager and AOG should not invest in the Trust Units.
Reserves
The value of the Trust Units will depend upon, among other things, the reserves
attributable to the Trust's properties. Estimating reserves is inherently
uncertain. Ultimately, actual production, revenues and expenditures for the
Trust'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 the Trust's properties have been independently evaluated at the
dates indicated by independent oil and gas reservoir engineering firms. These
firms consider a number of factors and make assumptions when estimating
reserves. These factors and assumptions include:
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.
These factors and assumptions were based upon prices at the date the relevant
evaluations were prepared. If these factors and assumptions prove to be
inaccurate, 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 upon 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.
55
Depletion of Reserves
The Trust has certain unique attributes that differentiate it from other oil and
gas industry participants. Distributions of Distributable Income in respect of
Properties, absent commodity price increases or cost effective acquisition and
development activities will decline over time in a manner consistent with
declining production from typical oil, natural gas and natural gas liquids
reserves. AOG will not be reinvesting cash flow in the same manner as other
industry participants. Accordingly, absent capital injections, AOG's initial
production levels and reserves will decline.
AOG's future oil and natural gas reserves and production, and therefore its cash
flows, will be highly dependent upon AOG's success in exploiting its reserve
base and acquiring additional reserves. Without reserve additions through
acquisition or development activities, AOG'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, AOG'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 AOG is required to use cash flow
to finance capital expenditures or property acquisitions, the level of
Distributable Income will be reduced.
There can be no assurance that the Trust, will be successful in developing or
acquiring additional reserves on terms that meet the Trust's investment
objectives.
Reliance upon Third Party Operators
Continuing production from a property and marketing of product produced from the
property are dependent to a large extent upon the ability of the operator of the
property. The Trust currently operates properties that represent approximately
85% of its total daily production. To the extent the operator fails to perform
these functions properly or becomes insolvent, revenue may be reduced.
Accounting Write-Downs as a Result of GAAP
Canadian Generally Accepted Accounting Principles ("GAAP") require that
management apply certain accounting policies and make certain estimates and
assumptions that 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
may 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 that
is based in part upon estimated future net cash flow from reserves. If net
capitalized costs exceed the estimated recoverable amounts, the Trust 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.
Enforcement of Operating Agreements
Operations of the wells on properties not operated by the Trust 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
the Trust or the Unitholders. The Trust, 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
56
the terms of the operating agreements; thus, Unitholders will be dependent upon
the Trust, as owner of the working interest, to enforce such rights.
Changes in Legislation
There can be no assurance that the treatment of mutual fund trusts will not be
changed in a manner adversely affecting Trust Unitholders. If the Trust ceases
to qualify as a "mutual fund trust" under the Tax Act, the Trust Units will
cease to be qualified investments for registered retirement savings plans,
registered education savings plans, deferred profit sharing plans and registered
retirement income funds.
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
taxation, may in the future be changed or interpreted in a manner that adversely
affects the Trust and its Unitholders. Tax authorities having jurisdiction over
the Trust or the Unitholders may disagree with how the Trust calculates its
income for tax purposes or could change administrative practises to the
detriment of the Trust or the detriment of its Unitholders.
The Trust expects that it will continue to qualify as a mutual fund trust for
purposes of the Tax Act. The Trust may not, however, always be able to satisfy
any future requirements for the maintenance of mutual fund trust status. Should
the status of the Trust as a mutual fund trust be lost or successfully
challenged by a relevant tax authority, certain adverse consequences may arise
for the Trust and its Unitholders. Some of the significant consequences of
losing mutual fund trust status are as follows:
o The Trust would be taxed on certain types of income distributed to
Unitholders, including income generated by the royalties held by the
Trust. Payment of this tax may have adverse consequences for some
Unitholders, particularly Unitholders that are not residents of Canada and
residents of Canada that are otherwise exempt from Canadian income tax.
o The Trust would cease to be eligible for the capital gains refund
mechanism available under Canadian tax laws if it ceased to be a mutual
fund trust.
o Trust Units held by Unitholders that are not residents of Canada would
become taxable Canadian property. These non-resident holders would be
subject to Canadian income tax on any gains realized on a disposition of
Trust Units held by them.
o Trust Units would not constitute qualified investments for registered
retirement savings plans ("RRSPs"), registered retirement income funds
("RRIFs"), registered education savings plans ("RESTs") or deferred profit
sharing plans ("DPSPs"). If, at the end of any month, one of these exempt
plans holds Trust Units that are not qualified investments, the plan must
pay a tax equal to 1% of the fair market value of the Trust Units at the
time the Trust Units were acquired by the exempt plan. An RRSP or RRIF
holding non-qualified Trust Units would be subject to taxation on income
attributable to the Trust Units. If an RESP holds non-qualified Trust
Units, it may have its registration revoked by the Canada Customs and
Revenue Agency.
In addition, the Trust may take certain measures in the future to the extent it
believes necessary to ensure that the Trust maintains its status as a mutual
fund trust. These measures could be adverse to certain holders of Trust Units,
particularly "non-residents" of Canada as defined in the Tax Act. See "Risk
Factors - Non Resident Ownership of Trust Units".
Investment Eligibility
The Trust will endeavour to ensure that the Trust Units continue to be qualified
investments for registered retirement savings plans, registered education
savings plans, deferred profit sharing plans and registered retirement income
funds. The Tax Act imposes penalties for the acquisition or holding of
non-qualified or ineligible investments and there is no assurance that the
conditions prescribed for such qualified or eligible investments will be adhered
to at any particular time.
57
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 AOG. The Trust
Units represent a fractional interest in the Trust. As holders of Trust Units,
Unitholders will not have the statutory rights normally associated with
ownership of shares of a corporation including, for example, the right to bring
"oppression" or "derivative" actions. The Trust's primary assets will be the
Notes, the Common Shares, the Royalty and other investments in securities. The
price per Trust Unit is a function of anticipated Distributable Income, the
Properties acquired by AOG, and the Manager's ability to effect long-term growth
in the value of the Trust. The market price of the Trust Units will be sensitive
to a variety of market conditions including, but not limited to, interest rates
and the ability of the Trust to acquire suitable oil and natural gas properties.
Changes in market conditions may adversely affect the trading price of the Trust
Units.
The Trust Units are also unlike conventional debt instruments in that there is
no principal amount owing to Unitholders. The Trust Units will have minimal
value when reserves from Advantage's properties can no longer be economically
produced or marketed. Unitholders will only be able to obtain a return of the
capital they invested during the period when reserves may be economically
recovered and sold. Accordingly, the distributions received over the life of the
investment may not be equal to or greater than the initial capital investment.
The Trust Units are not "deposits" within the meaning of the Canada Deposit
Insurance Corporation Act (Canada) and are not insured under the provisions of
that Act or any other legislation. Furthermore, the Trust is not a trust company
and, accordingly, is not registered under any trust and loan company legislation
as it does not carry on or intend to carry on the business of a trust company.
Net Asset Value
The net asset value of the assets of the Trust from time to time will vary
depending upon a number of factors beyond the control of management, including
oil and gas prices. The trading prices of the Trust Units from time to time is
also determined by a number of factors which are beyond the control of
management and such trading prices may be greater than the net asset value of
the Trust's assets.
Additional Financing
In the normal course of making capital investments to maintain and expand the
oil and gas reserves of the Trust, additional Trust Units are issued from
treasury which may result in a decline in production per Trust Unit and reserves
per Trust Unit. Additionally, from time to time the Trust issues Trust Units
from treasury in order to reduce debt and maintain a more optimal capital
structure. To the extent that external sources of capital, including the
issuance of additional Trust Units, become limited or unavailable, the Trust's
and AOG's ability to make the necessary capital investments to maintain or
expand its oil and gas reserves will be impaired. To the extent that the Trust
and AOG are required to use cash flow to finance capital expenditures or
property acquisitions or to pay debt service charges or to reduce debt, the
level of Distributable Income will be reduced.
Competition
There is strong competition relating to all aspects of the oil and gas industry.
There are numerous trusts in the oil and gas industry, who are competing for the
acquisitions of properties with longer life reserves and properties with
exploitation and development opportunities. As a result of such increasing
competition, it will be more difficult to acquire reserves on beneficial terms.
The Trust and AOG also compete for reserve acquisitions and skilled industry
personnel with a substantial number of other oil and gas companies, many of
which have significantly greater financial and other resources than the Trust
and AOG.
Return of Capital
Trust Units will have no value when reserves from the Properties can no longer
be economically produced and, as a result, cash distributions do not represent a
"yield" in the traditional sense and are not comparable to bonds or other fixed
yield securities, where investors are entitled to a full return of the principal
amount of debt on maturity in addition to a return on investment through
interest payments. Distributions represent a blend of a return of Unitholders'
initial investment and a return on Unitholders' initial investment.
58
Unitholders have a limited right to require the Trust to repurchase their Trust
Units, which is referred to as a redemption right. See "Information Relating to
the Trust - Right of Redemption". It is anticipated that the redemption right
will not be the primary mechanism for Unitholders to liquidate their investment.
The right to receive cash in connection with a redemption is subject to
limitations. Any securities which may be distributed in specie to Unitholders in
connection with a redemption may not be listed on any stock exchange and a
market may not develop for such securities. In addition, there may be resale
restrictions imposed by law upon the recipients of the securities pursuant to
the redemption right.
Redemption Right
It is anticipated that the redemption right will not be the primary mechanism
for Trust Unitholders to liquidate their investments. 14% Notes or Redemption
Notes which may be distributed in specie to Trust Unitholders in connection with
a redemption will not be listed on any stock exchange and no established market
is expected to develop for such 14% Notes or Redemption Notes. Cash redemptions
are subject to limitations. See "Additional Information Respecting Advantage
Energy Income Fund - Redemption Right".
Non-resident Ownership of Trust Units
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. The Board is proposing that certain changes be made to the Trust
Indenture to provide that if at any time AOG becomes aware that the beneficial
owners of 45% or more of the Trust Units then outstanding are or may be
non-residents or that such a situation is imminent, AOG, on the Trust's behalf,
shall review such actions as may be necessary to carry out the foregoing
intention.
Unitholder Limited Liability
The Trust Indenture provides that no Trust Unitholder will be subject to any
liability in connection with the Trust or its affairs or obligations and, in the
event that a court determines that Trust Unitholders are subject to any such
liabilities, the liabilities will be enforceable only against, and will be
satisfied only out of, such Unitholder's share of the Trust's assets.
The Trust Indenture provides that all written instruments signed by or on behalf
of the Trust must contain a provision to the effect that such obligation will
not be binding upon Unitholders personally. Personal liability may also arise in
respect of claims against the Trust that do not arise under contracts, including
claims in tort, claims for taxes and possibly certain other statutory
liabilities. The possibility of any personal liability of this nature arising is
considered unlikely.
The operations of the Trust will be conducted, upon the advice of counsel, in
such a way and in such jurisdictions as to avoid as far as possible any material
risk of liability on the Trust Unitholders for claims against the Trust.
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 upon 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.
Regulatory Matters
The Trust's operations are subject to a variety of federal and provincial laws
and regulations, including laws and regulations relating to the protection of
the environment.
Conflicts of Interest
The directors and officers of the Corporation are engaged in and will continue
to be engaged in other activities in the oil and natural gas industry and, as a
result of these and other activities, the directors and officers of the
Corporation may become subject to conflicts of interest. The ABCA provides that
in the event that a director has an interest in a contract or proposed contract
or agreement, the director shall disclose his interest in such contract or
agreement and shall refrain from voting on any matter in
59
respect of such contract or agreement unless otherwise provided under the ABCA.
To the extent that conflicts of interest arise, such conflicts will be resolved
in accordance with the provisions of the ABCA.
ADDITIONAL INFORMATION
Additional information, including directors' and officers' remuneration and
indebtedness, principal holders of securities and interests of insiders in
material transactions, where applicable, is contained in the Information
Circular of the Trust dated April 16, 2004. Additional financial information is
provided in Advantage's financial statements for the year ended December 31,
2003.
The Trust shall provide to any person, upon request to the Chief Financial
Officer of the Corporation:
1. when the securities of the Trust are in the course of a distribution
pursuant to a preliminary short form prospectus or a short form
prospectus:
(a) 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 in the Annual Information Form;
(b) one copy of the comparative financial statements of Advantage for
its most recently completed fiscal period 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;
(c) one copy of the Information Circular of the Trust in respect of its
most recent annual and special meeting of Unitholders; and
(d) one copy of any other documents that are incorporated by reference
into the preliminary short form prospectus or the short form
prospectus and which are not required to be provided under items (a)
to (c) above; or
2. at any other time, one copy of any documents referred to in items (1)(a),
(b) and (c) above, provided that 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.
For additional copies of this Annual Information Form and the materials listed
in the preceding paragraphs, please contact:
Advantage Energy Income Fund
Suite 3100, 150 - 6th Avenue S.W.
Calgary, Alberta T2P 3H7
Phone: (403) 261-8810
Fax: (403) 262-0723
A-1
SCHEDULE "A"
FINANCIAL STATEMENTS OF MARKWEST RESOURCES CANADA CORP.
November 12, 2003
Auditors' Report
To the Directors of
MarkWest Resources Canada Corp.
We have audited the balance sheet of MarkWest Resources Canada Corp. (the
"Company") as at December 31, 2002 and the statements of earnings and retained
earnings (deficit) and cash flows for the year then ended. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based upon
our audit.
We conducted our audit 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 the
results of its operations and its cash flows for the year then ended in
accordance with Canadian generally accepted accounting principles.
"PricewaterhouseCoopers LLP"
Chartered Accountants
A-2
MarkWest Resources Canada Corp.
Balance Sheet June 30, December 31,
2003 2002
$ $
(unaudited)
Assets
Current assets
Cash 1,726,092 3,345,099
Accounts receivable 6,033,365 5,238,507
Prepaids and other current assets 677,276 574,714
-----------------------------
8,436,733 9,158,320
Deferred financing costs 218,654 319,571
Property, plant and equipment (note 3) 152,640,666 142,334,142
-----------------------------
161,296,053 151,812,033
=============================
Liabilities
Current liabilities
Accounts payable and accrued liabilities 14,099,386 9,948,858
Current portion of capital lease obligations 312,499 --
Advances from parent (note 6) 51,788,151 16,265,710
-----------------------------
66,200,036 26,214,568
Long-term debt (note 4) 18,000,000 53,000,000
Capital lease obligation (note 5) 2,206,068 --
Provision for future site restoration (note 7) 1,386,888 1,159,212
Future income tax 39,091,849 45,360,728
-----------------------------
126,884,841 125,734,508
-----------------------------
Shareholders' Equity
Share capital (note 8) 28,542,263 28,542,263
Retained earnings 5,868,949 (2,464,738)
-----------------------------
34,411,212 26,077,525
-----------------------------
161,296,053 151,812,033
=============================
Approved by the Board of Directors
"Larry Strong" Director "Harvey Nelson" Director
- ------------------ -------------------
A-3
MarkWest Resources Canada Corp.
Statement of Earnings and Retained Earnings (Deficit) For the six
month period For the year
ended ended
June 30, December 31,
2003 2002
$ $
(unaudited)
Revenue
Petroleum and natural gas revenue 24,973,852 41,747,575
Royalties, net of Alberta Royalty Tax Credit (7,583,945) (10,026,021)
----------------------------
17,389,907 31,721,554
Other Income 34,498 33,967
----------------------------
17,424,405 31,755,521
----------------------------
Expenses
Production 4,613,846 7,244,966
General and administrative 1,322,183 2,629,180
Depletion, depreciation, amortization and site restoration 8,291,569 21,248,048
Interest expense 878,873 1,596,929
Other 100,917 1,079,330
----------------------------
15,207,388 33,798,453
----------------------------
Earnings (loss) before income taxes 2,217,017 (2,042,932)
----------------------------
Income taxes
Current tax expense (recovery) 152,209 (160,291)
Future tax recovery (6,268,879) (2,445,256)
----------------------------
(6,116,670) (2,605,547)
----------------------------
Net earnings for the period 8,333,687 562,615
Deficit - As at January 1 (2,464,738) (3,027,353)
----------------------------
Retained earnings (deficit) - End of period 5,868,969 (2,464,738)
============================
A-4
MarkWest Resources Canada Corp.
Statement of Cash Flows For the six
month period For the year
ended ended
June 30, December 31,
2003 2002
$ $
(unaudited)
Cash provided by (used in)
Net earnings for the period 8,333,687 562,615
Items not affecting cash
Depreciation, depletion and amortization 8,291,569 21,248,048
Future income taxes (6,268,879) (2,445,256)
Amortization of deferred financing costs 100,917 1,079,330
----------------------------
10,457,294 20,444,737
Net change in non-cash working capital items 4,032,286 2,265,829
----------------------------
14,489,580 22,710,566
----------------------------
Investing activities
Property, plant and equipment additions (18,215,689) (25,490,063)
Proceeds on disposition of property, plant and equipment 2,579,439 --
Abandonment expenditures (103,183) (5,151)
Change in capital accrual (236,478) (1,637,235)
----------------------------
(15,975,911) (27,132,449)
----------------------------
Financing activities
Repayment of long-term debt (35,000,000) --
Advances from parent 34,979,741 5,646,530
Decrease in capital lease obligations (112,417) --
----------------------------
(132,676) 5,646,530
----------------------------
(Decrease) increase in cash (1,619,007) 1,224,647
Cash - Beginning of period 3,345,099 2,120,452
----------------------------
Cash - End of period 1,726,092 3,345,099
============================
Supplementary information
Interest paid on long-term debt 1,495,649 2,692,095
Income taxes paid (received) 199,369 (500,783)
Non-cash items
Assets acquired under capital lease 2,630,984 --
A-5
MarkWest Resources Canada Corp.
Notes to Financial Statements
(Information as at and for the period ended June 30, 2003 is unaudited)
June 30, 2003 (unaudited) and December 31, 2002
- --------------------------------------------------------------------------------
1. Nature of operations
MarkWest Resources Canada Corp. (the "Company") explores for and
produces oil and natural gas and is a wholly owned subsidiary of
MarkWest Hydrocarbon, Inc.
2. Significant accounting policies
Cash
Cash consists of the balance with the bank, cash on hand and
short-term investments with a maturity of three months or less when
purchased.
Property, plant and equipment
The Company follows the full cost method of accounting for oil and
gas operations, whereby all costs of exploring for and developing
oil and gas properties and related reserves are capitalized. Such
costs include land acquisition costs, costs of drilling both
productive and non-productive wells, and geological and geophysical
expenses and related overhead. Proceeds of disposition are applied
against the cost pools with no gain or loss recognized except where
the disposition results in a significant change in the rate of
depletion.
The carrying value is limited to the recoverable amount as
determined by estimating the future net revenues from proven
properties (based on period end prices and costs) and the value of
unproven properties (at the lower of cost and net realizable value)
less estimated future site restoration costs, general and
administrative expenses and financing costs.
Capitalized costs, excluding costs relating to unproven properties,
are depleted using the unit-of-production method based on estimated
proven reserves of oil and gas before royalties as determined by
independent petroleum engineers. For purposes of the depletion
calculation, oil and natural gas reserves and production are
converted to a common unit-of-measure. Other assets are depreciated
on a straight-line basis over the estimated service lives of the
assets.
Assets under capital lease are recorded at the present value of the
lease payments at the inception of the lease.
Provision for future site restoration
The Company estimates its future site restoration and abandonment
costs for its oil and gas properties. The costs represent
management's best estimate of the future restoration and abandonment
costs based upon current legislation and industry practices. The
total estimated costs are being provided for on a unit-of-production
basis. The annual provision is included in amortization expense and
actual site restoration costs are charged to the liability account
as incurred.
Joint ventures
Certain of the Company's activities are conducted jointly with other
parties. These financial statements reflect the Company's
proportionate interest in such activities.
A-6
MarkWest Resources Canada Corp.
Notes to Financial Statements
(Information as at and for the period ended June 30, 2003 is unaudited)
June 30, 2003 (unaudited) and December 31, 2002
- --------------------------------------------------------------------------------
Financial instruments
The Company's financial instruments are comprised of cash, accounts
receivable, accounts payable, advances from parent, long term debt
and commodity instruments (note 10). The fair value of the financial
instruments approximates their carrying amount. A significant
portion of the Company's accounts receivable is from oil and gas
companies. Although collection of these receivables could be
influenced by economic factors affecting this industry, the risk of
significant loss is considered remote.
Income taxes
The Company follows the liability method of accounting for income
taxes. Under this method, the Company records future income taxes
for the effect of any differences between the accounting and the
income tax basis of an asset or liability using income tax rates
substantially enacted on the balance sheet date. The effect of a
change in income tax rates on the future income tax assets and
liabilities is recognized in income in the period of the change.
Measurement uncertainty
The amount recorded for depletion and depreciation of capital assets
and the provision for future site restoration costs are based on
estimates. The ceiling test calculation is based on estimates of
proven reserves, production rates, oil and gas prices, future costs
and other relevant assumptions. By their nature, these estimates are
subject to measurement uncertainty and the effect upon the financial
statements from changes in such estimates in future periods could be
significant.
3. Property, plant and equipment
June 30, 2003
-------------------------------------------
Accumulated
Cost amortization Net
$ $ $
Petroleum and natural gas properties and
equipment 187,196,766 37,321,667 149,875,099
Furniture and equipment 354,338 186,868 167,470
Assets under capital lease 2,630,984 32,887 2,598,097
-------------------------------------------
190,182,088 37,541,422 152,640,666
===========================================
December 31, 2002
-------------------------------------------
Accumulated
Cost amortization Net
$ $ $
Petroleum and natural gas properties and
equipment 171,592,526 29,430,588 142,161,938
Furniture and equipment 322,328 150,124 172,204
-------------------------------------------
171,914,854 29,580,712 142,334,142
===========================================
A-7
MarkWest Resources Canada Corp.
Notes to Financial Statements
(Information as at and for the period ended June 30, 2003 is unaudited)
June 30, 2003 (unaudited) and December 31, 2002
- --------------------------------------------------------------------------------
Costs for unproven properties of $45,443,638 at June 30, 2003 and
$48,420,924 at December 31, 2002 have been excluded from the depletion
calculation. During the six month period ended June 30, 2003 and the year
ended December 31, 2002, the Company capitalized no overhead costs related
to exploration and development activities and capitalized $1,109,482 and
$2,251,374 of interest expense respectively.
Month end prices of $29.16/bbl (December 31, 2002 - $33.49/bbl) for oil
and $6.34/mcf (December 31, 2002 -$5.66/mcf) for gas resulted in no
ceiling test deficiency at June 30, 2003 or December 31, 2002.
4. Long-term debt
On May 24, 2002, the Company amended its credit agreement ("Canadian
Credit Facility") with various financial institutions for an amount of
US$35,000,000. This facility is a component of the overall debt facility
of the parent company, MarkWest Hydrocarbons, Inc. ("Parent") of Denver,
Colorado. The overall amount of the Parent's facility ("Credit Facility")
is US$60,000,000.
Available borrowings under the Credit Facility are determined by a
borrowing base that is determined by the value of the proved reserves of
oil and gas owned by the Parent (directly or indirectly through
subsidiaries, including MarkWest Resources Canada Corp.), and also on the
working capital of the Parent, the level of which is determined by NGL
product accounts receivable and inventory levels. The borrowing base on
proved reserves is calculated semi-annually, while the borrowing base on
working capital is calculated monthly. Actual borrowing limits for the
Credit Facility may be less than US$60,000,000, depending on proved
reserves, working capital levels, and financial covenants. The Company had
outstanding borrowings of C$18,000,000, or approximately US$13,320,000, at
June 30, 2003, and C$53,000,000, or approximately US$33,758,000, at
December 31, 2002 of the US$35,000,000 available.
The Canadian Credit Facility permits MarkWest Resources Canada Corp. to
borrow money at a rate equal to the London Interbank Offered Rate
("LIBOR") plus an applicable margin of between 1.75% and 2.75% based on a
certain leverage ratio, which is determined as the ratio of total funded
debt to EBITDA. Funds can also be borrowed at the Canadian Prime Rate plus
an applicable margin of between 0.375% and 1.375%, based on the leverage
ratio. There is a fee on the unused portion of the Canadian Credit
Facility of between 0.25% and 0.50%, based on the leverage ratio. The
weighted average interest rate was 5.32% for the period ended June 30,
2003, and 5.02% for the year ended December 31, 2002.
The Credit Facility is a revolving facility, with a maturity and expiry
date of August 9, 2004. The entire outstanding principal balance is due in
full on this date. The Credit Facility is collateralized by a first lien
on substantially all the Company's assets.
A-8
MarkWest Resources Canada Corp.
Notes to Financial Statements
(Information as at and for the period ended June 30, 2003 is unaudited)
June 30, 2003 (unaudited) and December 31, 2002
- --------------------------------------------------------------------------------
5. Capital Lease obligations
Future minimum annual lease payments at June 30, 2003 (December 31, 2002 -
$nil) consist of the following:
June 30,
2003
$
2004 443,220
2005 443,220
2006 443,220
2007 and thereafter 1,585,200
----------
2,914,860
Less amounts representing interest at 5.5% (396,293)
----------
2,518,567
Current portion (312,499)
----------
2,206,068
==========
Interest of $35,323 relating to capital lease obligations is included in
interest expense for the period ended June 30, 2003.
6. Advances from parent
The advances from parent bear interest at 7% per annum, are due on demand
and are unsecured.
7. Provision for future site restoration
June 30, December 31,
2003 2002
$ $
Balance - Beginning of period 1,159,212 222,958
Current period provisions 330,859 941,405
Current period expenditures (103,183) (5,151)
---------- ----------
1,386,888 1,159,212
========== ==========
The provision for future site restoration costs is recorded in the statement of
income as a component of depletion, depreciation and amortization expense and on
the balance sheet as a long-term liability. The total estimated liability is
$4,700,000 at June 30, 2003 (December 31, 2002 - $3,960,000).
A-9
MarkWest Resources Canada Corp.
Notes to Financial Statements
(Information as at and for the period ended June 30, 2003 is unaudited)
June 30, 2003 (unaudited) and December 31, 2002
- --------------------------------------------------------------------------------
8. Share capital
Authorized
Unlimited number of common shares without nominal or par value
Issued Number of Amount
As at June 30, 2003 and December 31, 2002 shares $
Class A common shares 26,399,363 28,542,263
9. Commitments
The Company has committed to certain payments for office space over the
next four years as follows:
June 30,
2003
$
2004 188,348
2005 188,348
2006 188,348
2007 172,652
10. Commodity instruments
Derivative commodity instruments may be used from time to time by the
Company to manage its exposure to price risks relating to natural gas
prices. The Company's policy is to not utilize derivative commodity
instruments for trading or speculative purposes.
Realized gains and losses on derivative instruments used as hedges are
recognized in income in the period that the hedge is settled.
The Company had the following natural gas hedge agreements outstanding at
June 30, 2003 and December 31, 2002:
Volume Price
Type (gj/day) ($/gj) Term
Fixed price 2,462 4.62 Jan. 1, 2003 to Dec. 31, 2003
Fixed price 2,462 4.82 Jan. 1, 2003 to Dec. 31, 2003
Fixed price 1,758 4.65 Jan. 1, 2004 to Dec. 31, 2004
Fixed price 1,758 4.87 Jan. 1, 2004 to Dec. 31, 2004
Costless collar 2,462 4.09 - 5.24 Jan. 1, 2003 to Dec. 31, 2003
Costless collar 1,758 4.10 - 5.25 Jan. 1, 2004 to Dec. 31, 2004
Basis swap 6,330 Nymex/AECO Apr. 1, 2003 to Oct. 31, 2003
Basis swap 5,275 Nymex/AECO Apr. 1, 2003 to Oct. 31, 2003
The unrealized loss on these contracts was $6,105,538 as at June 30, 2003 and
$4,117,199 as at December 31, 2002.
B-1
SCHEDULE B - UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS
COMPILATION REPORT
The Board of Directors of Advantage Oil & Gas Ltd.
We have read the accompanying unaudited pro forma consolidated balance sheet of
Advantage Energy Income Fund (the "Fund") as at June 30, 2003 and unaudited pro
forma consolidated statement of operations for the six months then ended and for
the year ended December 31, 2002, and have performed the following procedures:
1. Compared the figures in the columns captioned "Advantage" to the unaudited
consolidated financial statements of the Fund as at June 30, 2003 and for
the six months then ended, and the audited consolidated financial
statements of the Fund for the year ended December 31, 2002, respectively,
and found them to be in agreement.
2. Compared the figures in the columns captioned "MarkWest" to the unaudited
financial statements of MarkWest Resources Canada Corp. as at June 30,
2003 and for the six months then ended, and the audited financial
statements of MarkWest Resources Canada Corp. for the year ended December
31, 2002, respectively, and found them to be in agreement.
3. Made enquiries of certain officials of the Fund 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 consolidated financial statements comply
as to form in all material respects with the securities
regulations of various provinces.
The officials:
(a) described to us the basis for determination of the pro forma
adjustments, and
(b) stated that the pro forma consolidated financial statements
comply as to form in all material respects with the securities
regulations of various provinces.
4. Read the notes to the pro forma consolidated 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 "Advantage" and "MarkWest" as at
June 30, 2003 and for the six months then ended, and for the year ended
December 31, 2002, and found the amounts in the column captioned "Pro
forma" 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
consolidated financial statements, and we therefore make no representation about
the sufficiency of the procedures for the purposes of a reader of such
statements.
"KPMG LLP"
Chartered Accountants
Calgary, Canada
November 21, 2003
B-2
ADVANTAGE ENERGY INCOME FUND
PROFORMA CONSOLIDATED BALANCE SHEET
(thousands of dollars)
(unaudited)
Advantage MarkWest
June 30, June 30, Pro Forma Pro Forma
2003 2003 Adjustments Consolidated
--------------------------------------------------------------------------
Assets
Current
Accounts receivable 22,730 8,655 31,385
------------------------------------------ ---------
22,730 8,655 -- 31,385
Property and equipment 403,980 152,641 (47,641) (note 2a) 508,980
Goodwill -- -- 27,146 (note 2a) 27,146
------------------------------------------ ---------
$ 426,710 $ 161,296 $ (20,495) $ 567,511
========================================== =========
Liabilities
Current
Bank indebtedness $ 139,359 $ 18,000 79,037 (note 2a) $ 73,687
(133,909) (note 2a)
(28,800) (note 2h)
Accounts payable and accrued liabilities 28,306 14,412 2,000 (note 2a) 44,718
Advances from parent -- 51,788 (51,788) (note 2a)
Cash distribution to Unitholders 7,116 -- 7,116
------------------------------------------ ---------
174,781 84,200 (133,460) 125,521
Capital lease obligation -- 2,206 -- 2,206
Provision for future site restoration 5,968 1,387 -- 7,355
Future income taxes 62,057 39,092 (15,333) (note 2a) 85,816
------------------------------------------ ---------
$ 242,806 $ 126,885 $ (148,793) $ 220,898
------------------------------------------ ---------
Unitholders' Equity
Unitholders' capital 202,658 28,542 (28,542) (note 2a) 278,967
76,309 (note 2a)
Convertible debentures 18,556 -- 60,000 (note 2a) 108,556
30,000 (note 2h)
Accumulated income 70,640 5,869 (5,869) (note 2a) 67,040
(3,600) (note 2h)
Accumulated cash distributions (107,950) -- (note 2a) (107,950)
------------------------------------------ ---------
183,904 34,411 128,298 346,613
------------------------------------------ ---------
$ 426,710 $ 161,296 $ (20,495) $ 567,511
========================================== =========
see accompanying notes to the unaudited proforma consolidated financial
statements
B-3
ADVANTAGE ENERGY INCOME FUND.
PROFORMA CONSOLIDATED STATEMENT OF OPERATIONS
(thousands of dollars)
(unaudited)
Advantage MarkWest
Six months Six months
ended ended
June 30, June 30, Pro Forma
2003 2003 Adjustments Pro Forma
--------------------------------------------------------------------
Revenue
Petroleum and natural gas sales $ 81,733 $ 25,009 $ 106,742
Royalties, net of ARC (14,706) (7,584) (50) (note 2b) (22,340)
--------------------------------------------------------------------
67,027 17,425 (50) 84,402
--------------------------------------------------------------------
Expenses
Operating 11,138 4,715 15,853
General and administrative 1,740 1,322 3,062
Management fee 838 -- 838
Interest 3,387 879 (2,075) (note 2c) 2,191
Depletion, depreciation and site restoration 23,083 8,292 417 (note 2d) 31,792
Non-cash performance incentive 4,840 -- 4,840
--------------------------------------------------------------------
45,026 15,208 (1,658) 58,576
--------------------------------------------------------------------
Income before taxes 22,001 2,217 1,608 25,826
Taxes
Current income taxes 573 152 236 (note 2e) 961
Future income taxes (recovery) (15,007) (6,269) 701 (note 2f) (20,575)
--------------------------------------------------------------------
(14,434) (6,117) 937 (19,614)
--------------------------------------------------------------------
Net income $ 36,435 $ 8,334 $ 671 $ 45,440
====================================================================
Net income per trust unit (note 2g)
Basic $ 1.15
Diluted $ 1.06
see accompanying notes to the unaudited pro forma consolidated financial
statements
B-4
ADVANTAGE ENERGY INCOME FUND.
PROFORMA CONSOLIDATED STATEMENT OF OPERATIONS
(thousands of dollars)
(unaudited)
Advantage MarkWest
Six months Six months
ended ended
June 30, June 30, Pro Forma
2002 2002 Adjustments Pro Forma
--------------------------------------------------------------------
Revenue
Petroleum and natural gas sales $ 97,837 $ 41,782 $ 139,619
Royalties, net of ARC (17,344) (10,026) (50) (note 2b) (27,420)
--------------------------------------------------------------------
80,493 31,756 (50) 112,199
--------------------------------------------------------------------
Expenses
Operating 18,486 7,245 25,731
General and administrative 2,624 2,629 5,253
Management fee 930 -- 930
Interest 4,272 1,597 (4,184) (note 2c) 1,685
Non-cash performance incentive 16,475 -- 16,475
Depletion, depreciation and site restoration 41,074 21,248 (4,373) (note 2d) 57,949
Other -- 1,079 1,079
--------------------------------------------------------------------
83,861 33,798 (8,557) 109,102
--------------------------------------------------------------------
Income (loss) before taxes (3,368) (2,042) 8,507 3,097
Taxes
Current income taxes 529 (160) 236 (note 2e) 605
Future income taxes (recovery) (15,992) (2,445) 3,619 (note 2f) (14,818)
--------------------------------------------------------------------
(15,463) (2,605) 3,855 (14,213)
--------------------------------------------------------------------
Net income $ 12,095 $ 563 $4,652 $ 17,310
====================================================================
Net income per trust unit (note 2g)
Basic $ 0.27
Diluted $ 0.27
see accompanying notes to the unaudited pro forma consolidated financial
statements
B-5
ADVANTAGE ENERGY INCOME FUND
Notes to Pro Forma Consolidated Financial Statements
Six months Ended June 30, 2003 and Year Ended December 31, 2002
(unaudited)
1. Basis of Presentation
On November 12, 2003 Advantage Oil & Gas Ltd. entered into a Share
Purchase Agreement to purchase all of the issued and outstanding shares of
MarkWest Resources Canada Corp ("MarkWest"). The acquisition is expected
to close on or before December 16, 2003.
The accompanying unaudited pro forma consolidated balance sheet and pro
forma consolidated statements of operations ("pro forma consolidated
financial statements") have been prepared based on the unaudited balance
sheets as at June 30, 2003 and the statement of operations of MarkWest and
Advantage for the six months ended June 30, 2003 and the year ended
December 31, 2002.
The accompanying unaudited pro forma consolidated financial statements
have been prepared by management of Advantage Energy Income Fund
("Advantage") in accordance with Canadian generally accepted accounting
principles. In the opinion of management, the pro forma consolidated
financial statements include all material adjustments necessary for fair
presentation in accordance with Canadian generally accepted accounting
principles.
The pro forma consolidated balance sheet gives effect to the transactions
described in Note 2 as if they occurred on the balance sheet date while
the pro forma consolidated statements of operations give effect to these
transactions as if they had occurred at the beginning of the period.
These pro forma consolidated financial statements may not be indicative
either of the results that actually would have occurred if the events
reflected herein had been in effect upon the dates indicated or of the
results which may be obtained in the future.
Accounting policies used in the preparation of the pro forma financial
statements are consistent with those used in the audited financial
statements for Advantage prepared for the year ended December 31, 2002.
This financial information should be read in conjunction with Advantage's
audited financial statements for that year.
2. Pro forma transactions and assumptions
(a) Under the terms of the agreement, Advantage would acquire all of the
issued and outstanding shares of MarkWest for total cash
consideration of $81,037,000. The acquisition is being accounted for
under the purchase method. Net assets acquired at fair market value
are as follows:
($000's)
Working capital (deficiency) $ (5,757)
Site restoration liability (1,387)
Bank indebtedness (18,000)
Capital lease obligation (2,206)
Future income taxes (23,759)
Goodwill 27,146
Property and equipment 105,000
---------
$ 81,037
---------
B-6
ADVANTAGE ENERGY INCOME FUND
Notes to Pro Forma Consolidated Financial Statements
Six months Ended June 30, 2003 and Year Ended December 31, 2002
(unaudited)
The above represents management's preliminary assessment of assets
acquired. The allocation of the purchase price will be finalized after the
business combination has been completed and the fair values of the assets
and liabilities have been determined, accordingly the above allocation is
subject to change. Transaction costs incurred by Advantage in connection
with the acquisition include legal, advisory and other professional costs
of $2,000,000 and have been included in accounts payable and accrued
liabilities.
Consideration comprised of:
Cash $79,037
Transaction costs 2,000
-------
$81,037
=======
The acquisition is to be financed through the issuance of $60,000,000 of
8 1/4% subordinated convertible debentures and the issuance of 5.1 million
trust units issued at a price of $15.75 per unit. Associated underwriters'
fees of $2,400,000 are included in accumulated income. Excess proceeds
over the purchase price of MarkWest will be used to reduce bank debt.
(b) Alberta Royalty Credit has been reduced to reflect the requirement
of Advantage to share the maximum annual limit with its
subsidiaries.
(c) A reduction of interest expense has been calculated by applying
applicable bank interest rates averaging 5.0% for the period to the
decrease in the bank loan with respect to the proceeds raised in
excess of the purchase price.
(d) Depletion, depreciation has been adjusted on a consolidated basis
incorporating the fair value of the assets of MarkWest determined
under the purchase method as set out in note 2(a) and incorporating
the combined reserves and production.
(e) Current taxes have been adjusted to reflect changes in large
corporations tax.
(f) Future income tax expense has been adjusted to tax effect the pro
forma income statement adjustments.
(g) Pro forma basic per unit amounts are based on the weighted average
number of Advantage units outstanding for the period plus the
additional units issued pursuant to the prospectus. Pro forma
diluted per unit amounts are based on the weighted average number of
diluted Advantage units outstanding for the period plus the
additional units that would be issued on the conversion of the
convertible debentures referenced under 2(a) and 2(h).
(h) Convertible debentures and bank debt have been adjusted to reflect
Advantage's issuance of $30,000,000 of 9.00% subordinated
convertible debentures on July 8, 2003. Associated underwriters'
fees of $1,200,000 are included in accumulated income.
3. Convertible Debentures
The convertible debentures and related interest obligations have been
classified as equity on the balance sheet as the Trust may elect to
satisfy the debenture interest and principle obligation by the issuance of
Trust Units. Issue costs associated with the debentures have been treated
as a reduction to retained earnings. When calculating cash available for
distribution to Unitholders, interest on the convertible debentures is
deducted from cash flow from operations.